##### 



U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549   FORM 10-K (Mark One)[X]
    
    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIESEXCHANGE ACT OF 1934For the fiscal year ended December 31, 2003
 or [  ]
    
    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  Delaware
(state or other jurisdiction of
incorporation or organization)
    
    84-0637348
(I.R.S. Employer
Identification No.)
 One Landmark Square
Stamford, Connecticut
(Address of principal executive offices)
    
    06901
(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
months (or for such shorter period that the Registrant was required to file
such reports), and (2) has been subject to such filing requirements for the
past 90 days.  Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-B is not contained herein, and will not be contained, to the
best of Registrants knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. [  ] Indicate by check mark whether the Registrant is an accelerated filer as
defined in Exchange Act Rule 12-b-2  The aggregate market value of the voting stock of the Registrant held by
non-affiliates, computed by reference to the average bid and asked price of
such common equity as of the last business day of the Registrants most
recently completed second fiscal quarter, was $9,664,585. The number of shares outstanding of each class of the Registrants Common Stock
as of March 25, 2004 was: Common Stock, $0.10 par value, 3,612,472 DOCUMENTS INCORPORATED BY REFERENCE




---



##### 



PrimeEnergy Corporation FORM 10-K ANNUAL REPORT
For the Fiscal Year Ended
December 31, 2003 PART I Item 1. BUSINESS. General This Report contains forward-looking statements that are based on
managements current expectations, estimates and projections. Words such as
expects, anticipates, intends, plans, believes, projects and
estimates, and variations of such words and similar expressions are intended
to identify such forward-looking statements. These statements constitute
forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933, and are subject to the safe harbors created thereby.
These statements are not guarantees of future performance and involve risks and
uncertainties and are based on a number of assumptions that could ultimately
prove inaccurate and, therefore, there can be no assurance that they will prove
to be accurate. Actual results and outcomes may vary materially from what is
expressed or forecast in such statements due to various risks and
uncertainties. These risks and uncertainties include, among other things,
volatility of oil and gas prices, competition, risks inherent in the Companys
oil and gas operations, the inexact nature of interpretation of seismic and
other geological and geophysical data, imprecision of reserve estimates, the
Companys ability to replace and expand oil and gas reserves, and such other
risks and uncertainties described from time to time in the Companys periodic
reports and filings with the Securities and Exchange Commission. Accordingly,
stockholders and potential investors are cautioned that certain events or
circumstances could cause actual results to differ materially from those
projected. PrimeEnergy Corporation (the Company) was organized in March, 1973,
under the laws of the State of Delaware. The Company is engaged in the oil and gas business through the
acquisition, exploration, development, and production of crude oil and natural
gas. The Companys properties are located primarily in
Texas, Oklahoma, West Virginia, the Gulf of Mexico, New Mexico, and Louisiana. The Company, through its
wholly-owned subsidiaries Prime Operating Company, Southwest Oilfield
Construction Company, Eastern Oil Well Service Company and EOWS Midland
Company, acts as operator and provides well servicing support operations for
many of the onshore oil and gas wells in which the Company has an interest, as
well as for third parties. The Company owns and operates properties in the
Gulf of Mexico through its sixty percent owned subsidiary F-W Oil Exploration
L.L.C. (FW). The Company is also active in the acquisition of producing oil
and gas properties through joint ventures with industry partners. The Companys
wholly-owned subsidiary, PrimeEnergy Management Corporation (PEMC), acts as
the managing general partner in 18 oil and gas limited partnerships (the
Partnerships) of which two are publicly held, and acts as the managing
trustee of two asset and income business trusts (the Trusts). Exploration, Development and Acquisition Activities The Companys activities include development and exploratory drilling. The
Companys strategy is to develop a balanced portfolio of drilling prospects
that includes lower risk wells with a high probability of success and higher
risk wells with greater economic potential. In
2003, the Company drilled 25 gross (10.504 net) wells in its onshore
operating areas at a cost of approximately $7 million. The Company also spent
$10 million to acquire and develop properties in the Gulf of Mexico owned through FW. In
2004, the Company expects to spend approximately $16 million on
development and exploratory drilling. The Company plans to spend
approximately 40% onshore and approximately 60% of its
drilling expenditures on higher risk and potentially more prolific
offshore prospects. The Company believes that its diversified portfolio approach to its
drilling activities results in more consistent and predictable economic results
than might be experienced with a less diversified or higher risk drilling
program profile. 2




---



##### 



The Company attempts to assume the position of operator in all
acquisitions of producing properties. The Company will continue to evaluate
prospects for leasehold acquisitions and for exploration and development
operations in areas in which it owns interests and is actively pursuing the
acquisition of producing properties. In order to diversify and broaden its
asset base, the Company will consider acquiring the assets or stock in other
entities and companies in the oil and gas business. The main objective of the
Company in making any such acquisitions will be to acquire income producing
assets so as to increase the Companys net worth and increase the Companys oil
and gas reserve base. The Company presently owns producing and non-producing properties located
primarily in Texas, Oklahoma, West Virginia, the Gulf of Mexico, New
Mexico, and Louisiana,
and owns a substantial amount of well servicing equipment. The Company does
not own any refinery or marketing facilities, and does not currently own or
lease any bulk storage facilities or pipelines other than adjacent to and used
in connection with producing wells and the interests in certain gas gathering
systems. All of the Companys oil and gas properties and interests are located
in the continental United States. In the past, the supply of gas has exceeded demand on a cyclical basis,
and the Company is subject to a combination of shut-in and/or reduced takes of
gas production during summer months. Prolonged shut-ins could result in
reduced field operating income from properties in which the Company acts as
operator. Exploration for oil and gas requires substantial expenditures particularly
in exploratory drilling in undeveloped areas, or wildcat drilling. As is
customary in the oil and gas industry, substantially all of the Companys
exploration and development activities are conducted through joint drilling and
operating agreements with others engaged in the oil and gas business. Summaries of the Companys oil and gas drilling activities, oil and gas
production, and undeveloped leasehold, mineral and royalty interests are set
forth under Item 2., Properties, below. Summaries of the
Companys oil and gas reserves, future net revenue and present value of future
net revenue are also set forth under Item 2., Properties 
Reserves below. Well Operations The Companys on-shore operations are conducted through a central office
in Houston, Texas, and district offices in Houston and Midland, Texas, Oklahoma
City, Oklahoma, and Charleston, West Virginia. The Company currently operates
1,533 oil and gas wells, 427 through the Houston office, 160 through the
Midland office, 458 through the Oklahoma City office and 450 through the
Charleston, West Virginia office. Substantially all of the wells operated by
the Company are wells in which the Company has an interest. The Companys
off-shore operations are conducted through FW, also in Houston, Texas. The Company operates wells pursuant to operating agreements which govern
the relationship between the Company as operator and the other owners of
working interests in the properties, including the Partnerships, Trusts and
joint venture participants. For each operated well, the Company receives
monthly fees that are competitive in the areas of operations and also is
reimbursed for expenses incurred in connection with well operations. The Partnerships ,Trusts and Joint Ventures Since 1975, PEMC has sponsored a total of 59 limited partnerships, 22 of
which were offered publicly and 37 of which were offered in private placements
and two Delaware business trusts, both of which were offered publicly. The
Partnership and Trust interests were sold by broker-dealers which are members
of the National Association of Securities Dealers, Inc. through a managing
dealer. The total funds contributed to the Partnerships and Trusts was about
$157,550,000. The aggregate number of limited partners in the Partnerships and
beneficial owners of the Trusts now administered by PEMC is
approximately 4,600.
This number, as well as the number of remaining partnerships noted above, has
decreased in recent years as the Company continues to buy back limited partner
interests. The total funds invested by Joint
Venture Partners was $27.6 million. PEMC, as managing general partner of the Partnerships and managing trustee
of the Trusts, is responsible for all Partnership and Trust activities,
including the review and analysis of oil and gas properties for acquisition,
the drilling of development wells and the production and sale of oil and gas
from productive wells. PEMC also provides administration, accounting and tax
preparation for the Partnerships and Trusts. PEMC is liable for all debts and
liabilities of the Partnerships and Trusts, to the extent that the assets of a
given limited partnership or trust are not sufficient to satisfy its
obligations. The Company stopped sponsoring partnerships and trusts in 1992.
Today there are only 18 partnerships and two trusts remaining. 3




---



##### 



Regulation Regulation of Transportation and Sale of Natural Gas: Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas Act of
1938, as amended (NGA), the Natural Gas Policy Act of 1978, as amended
(NGPA), and regulations promulgated there under by the Federal Energy
Regulatory Commission (FERC) and its predecessors. In the past, the federal
government has regulated the prices at which natural gas could be sold. While
sales by producers of natural gas can currently be made at uncontrolled market
prices, Congress could reenact price controls in the future. Deregulation of
wellhead natural gas sales began with the enactment of the NGPA. In 1989,
Congress enacted the Natural Gas Wellhead Decontrol Act, as amended (the
Decontrol Act). The Decontrol Act removed all NGA and NGPA price and
non-price controls affecting wellhead sales of natural gas effective January 1,
1993. Since 1985, FERC has endeavored to make natural gas transportation more
accessible to natural gas buyers and sellers on an open and non-discriminatory
basis. FERC has stated that open access policies are necessary to improve the
competitive structure of the interstate natural gas pipeline industry and to
create a regulatory framework that will put natural gas sellers into more
direct contractual relations with natural gas buyers by, among other things,
unbundling the sale of natural gas from the sale of transportation and storage
services. Beginning in 1992, FERC issued Order No. 636 and a series of related
orders (collectively, Order No. 636) to implement its open access policies.
As a result of the Order No. 636 program, the marketing and pricing of natural
gas have been significantly altered. The interstate pipelines traditional role
as wholesalers of natural gas has been eliminated and replaced by a structure
under which pipelines provide transportation and storage service on an open
access basis to others who buy and sell natural gas. Although FERCs orders do
not directly regulate natural gas producers, they are intended to foster
increased competition within all phases of the natural gas industry. In 2000, FERC issued Order No. 637 and subsequent orders (collectively,
Order No. 637), which imposed a number of additional reforms designed to
enhance competition in natural gas markets. Among other things, Order No. 637
revised FERC pricing policy by waiving price ceilings for short-term released
capacity for a two-year experimental period, and effected changes in FERC
regulations relating to scheduling procedures, capacity segmentation,
penalties, rights of first refusal and information reporting. Most major
aspects of Order No. 637 have been upheld on judicial review, and most
pipelines tariff filings to implement the requirements of Order No. 637 have
been accepted by the FERC and placed into effect. The Outer Continental Shelf Lands Act (OCSLA), which FERC implements as
to transportation and pipeline issues, requires that all pipelines operating on
or across the outer continental shelf (OCS) provide open access,
non-discriminatory transportation service. One of FERCs principal goals in
carrying out OCSLAs mandate is to increase transparency in the market to
provide producers and shippers on the OCS with greater assurance of open
access service on pipelines located on the OCS and non-discriminatory rates and
conditions of service on such pipelines. It should be noted that FERC currently is considering whether to
reformulate its test for defining non-jurisdictional gathering in the shallow
waters of the OCS and, if so, what form that new test should take. The stated
purpose of this initiative is to devise an objective test that furthers the
goals of the NGA by protecting producers from the unregulated market power of
third-party transporters of gas, while providing incentives for investment in
production, gathering and transportation infrastructure offshore. While we
cannot predict whether FERCs gathering test ultimately will be revised and,
if so, what form such revised test will take, any test that refunctionalizes as
FERC-jurisdictional transmission facilities currently classified as gathering
would impose an increased regulatory burden on the owner of those facilities by
subjecting the facilities to NGA certificate and abandonment requirements and
rate regulation. We cannot accurately predict whether FERCs actions will achieve the goal
of increasing competition in markets in which our natural gas is sold.
Additional proposals and proceedings that might affect the natural gas industry
are pending before FERC and the courts. The natural gas industry historically
has been very heavily regulated; therefore, there is no assurance that the less
stringent regulatory approach recently pursued by FERC will continue. However,
we do not believe that any action taken will affect us in a way that materially
differs from the way it affects other natural gas producers, gatherers and
marketers. Intrastate natural gas transportation is subject to regulation by state
regulatory agencies. The basis for intrastate regulation of natural gas
transportation and the degree of regulatory oversight and scrutiny given to
intrastate natural gas pipeline rates and services varies from state to state.
Insofar as such regulation within a particular state will generally affect all
intrastate natural gas shippers within the state on a comparable basis, we
believe that the regulation of similarly situated intrastate natural gas
transportation in any states in which we 4




---



##### 



operate and ship natural gas on an intrastate basis will not affect our
operations in any way that is materially different from the effect of such
regulation on our competitors. Regulation of Transportation of Oil: Sales of crude oil, condensate and natural gas liquids are not currently
regulated and are made at negotiated prices. The transportation of oil in
common carrier pipelines is also subject to rate regulation. FERC regulates
interstate oil pipeline transportation rates under the Interstate Commerce Act.
In general, interstate oil pipeline rates must be cost-based, although
settlement rates agreed to by all shippers are permitted and market-based rates
may be permitted in certain circumstances. Effective January 1, 1995, FERC
implemented regulations establishing an indexing system (based on inflation)
for transportation rates for oil that allowed for an increase or decrease in
the cost of transporting oil to the purchaser. A review of these regulations by
the FERC in 2000 was successfully challenged on appeal by an association of oil
pipelines. On remand, the FERC in February 2003 increased the index slightly,
effective July 2001. Intrastate oil pipeline transportation rates are subject
to regulation by state regulatory commissions. The basis for intrastate oil
pipeline regulation, and the degree of regulatory oversight and scrutiny given
to intrastate oil pipeline rates, varies from state to state. Insofar as
effective interstate and intrastate rates are equally applicable to all
comparable shippers, we believe that the regulation of oil transportation rates
will not affect our operations in any way that is materially different from the
effect of such regulation on our competitors. Further, interstate and intrastate common carrier oil pipelines must
provide service on a non-discriminatory basis. Under this open access standard,
common carriers must offer service to all shippers requesting service on the
same terms and under the same rates. When oil pipelines operate at full
capacity, access is governed by prorationing provisions set forth in the
pipelines published tariffs. Accordingly, we believe that access to oil
pipeline transportation services generally will be available to us to the same
extent as to our competitors. Regulation of Production: The production of oil and natural gas is subject to regulation under a
wide range of local, state and federal statutes, rules, orders and regulations.
Federal, state and local statutes and regulations require permits for drilling
operations, drilling bonds and plugging and abandonment and reports concerning
operations. The states in which we own and operate properties have regulations
governing conservation matters, including provisions for the unitization or
pooling of oil and natural gas properties, the establishment of maximum
allowable rates of production from oil and natural gas wells, the regulation of
well spacing, and plugging and abandonment of wells. Many states also restrict
production to the market demand for oil and natural gas, and states have
indicated interest in revising
applicable regulations. The effect of these regulations is to limit the amount
of oil and natural gas that we can produce from our wells and to limit the
number of wells or the locations at which we can drill. Moreover, each state
generally imposes a production or severance tax with respect to the production
and sale of oil, natural gas and natural gas liquids within its jurisdiction. Some of our offshore operations are conducted on federal leases that are
administered by Minerals Management Service (MMS) and are required to comply
with the regulations and orders promulgated by MMS under OCSLA. Among other
things, we are required to obtain prior MMS approval for any exploration plans
we pursue and our development and production plans for these leases. MMS
regulations also establish construction requirements for production facilities
located on our federal offshore leases and govern the plugging and abandonment
of wells and the removal of production facilities from these leases. Under
limited circumstances, MMS could require us to suspend or terminate our
operations on a federal lease. MMS also establishes the basis for royalty payments due under federal oil
and natural gas leases through regulations issued under applicable statutory
authority. State regulatory authorities establish similar standards for royalty
payments due under state oil and natural gas leases. The basis for royalty
payments established by MMS and the state regulatory authorities is generally
applicable to all federal and state oil and natural gas lessees. Accordingly,
we believe that the impact of royalty regulation on our operations should
generally be the same as the impact on our competitors. The failure to comply with these rules and regulations can result in
substantial penalties. The regulatory burden on the oil and natural gas
industry increases our cost of doing business and, consequently, affects our
profitability. Our competitors in the oil and natural gas industry are subject
to the same regulatory requirements and restrictions that affect our
operations. 5




---



##### 



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.
    
    
    15.80
    %Plains All American Inc.
    
    
    11.52
    %Gas Purchasers:Unimark LLC
    
    
    21.68
    %El Paso Industrial Energy
    
    
    10.60
    %
 Although there are no long-term purchasing agreements with these
purchasers, the Company believes that they will continue to purchase its oil
and gas products and, if not, could be replaced by other purchasers. Environmental Matters Various federal, state and local laws and regulations governing the
protection of the environment, such as the Comprehensive Environmental
Response, Compensation and Liability Act of 1980, as amended (CERCLA), the
Federal Water Pollution Control Act of 1972, as amended (the Clean Water
Act), and the Federal Clean Air Act, as amended (the Clean Air Act), affect
our operations and costs. In particular, our exploration, development and
production operations, our activities in connection with storage and
transportation of oil and other hydrocarbons and our use of facilities for
treating, processing or otherwise handling hydrocarbons and related wastes may
be subject to regulation under these and similar state legislation. These laws
and regulations:  
    
    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. 6




---



##### 



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. Superfund. CERCLA, also known as Superfund, imposes liability for
response costs and damages to natural resources, without regard to fault or the
legality of the original act, on some classes of persons that contributed to
the release of a hazardous substance into the environment. These persons
include the owner or operator of a disposal site and entities that disposed
or arranged for the disposal of the hazardous substances found at the site.
CERCLA also authorizes the Environmental Protection Agency (EPA) and, in some
instances, third parties to act in response to threats to the public health or
the environment and to seek to recover from the responsible classes of persons
the costs they incur. It is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the hazardous substances released into the environment. In the course
of our ordinary operations, we may generate waste that may fall within CERCLAs
definition of a hazardous substance. We may be jointly and severally liable
under CERCLA or comparable state statutes for all or part of the costs required
to clean up sites at which these wastes have been disposed. We currently own or lease properties that for many years have been used
for the exploration and production of oil and natural gas. Although we and our
predecessors have used operating and disposal practices that were standard in
the industry at the time, hydrocarbons or other wastes may have been disposed
or released on, under or from the properties owned or leased by us or on, under
or from other locations where these wastes have been taken for disposal. In
addition, many of these properties have been operated by third parties whose
actions with respect to the treatment and disposal or release of hydrocarbons
or other wastes were not under our control. These properties and wastes
disposed on these properties may be subject to CERCLA and analogous state laws.
Under these laws, we could be required:  
    
    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, 7




---



##### 



and we believe that compliance with OPAs financial responsibility and other
operating requirements will not have a material adverse effect on us. U.S. Environmental Protection Agency. U.S. Environmental Protection Agency
regulations address the disposal of oil and natural gas operational wastes
under three federal acts more fully discussed in the paragraphs that follow.
The Resource Conservation and Recovery Act of 1976, as amended (RCRA),
provides a framework for the safe disposal of discarded materials and the
management of solid and hazardous wastes. The direct disposal of operational
wastes into offshore waters is also limited under the authority of the Clean
Water Act. When injected underground, oil and natural gas wastes are regulated
by the Underground Injection Control program under Safe Drinking Water Act. If
wastes are classified as hazardous, they must be properly transported, using a
uniform hazardous waste manifest, documented, and disposed at an approved
hazardous waste facility. We have coverage under the Region VI National
Production Discharge Elimination System Permit for discharges associated with
exploration and development activities. We take the necessary steps to ensure
all offshore discharges associated with a proposed operation, including
produced waters, will be conducted in accordance with the permit. Resource Conservation Recovery Act. RCRA, is the principal federal
statute governing the treatment, storage and disposal of hazardous wastes. RCRA
imposes stringent operating requirements, and liability for failure to meet
such requirements, on a person who is either a generator or transporter of
hazardous waste or an owner or operator of a hazardous waste treatment,
storage or disposal facility. At present, RCRA includes a statutory exemption
that allows most oil and natural gas exploration and production waste to be
classified as nonhazardous waste. A similar exemption is contained in many of
the state counterparts to RCRA. As a result, we are not required to comply with
a substantial portion of RCRAs requirements because our operations generate
minimal quantities of hazardous wastes. At various times in the past, proposals
have been made to amend RCRA to rescind the exemption that excludes oil and
natural gas exploration and production wastes from regulation as hazardous
waste. Repeal or modification of the exemption by administrative, legislative
or judicial process, or modification of similar exemptions in applicable state
statutes, would increase the volume of hazardous waste we are required to
manage and dispose of and would cause us to incur increased operating expenses. Clean Water Act. The Clean Water Act imposes restrictions and controls on
the discharge of produced waters and other wastes into navigable waters.
Permits must be obtained to discharge pollutants into state and federal waters
and to conduct construction activities in waters and wetlands. Certain state
regulations and the general permits issued under the Federal National Pollutant
Discharge Elimination System program prohibit the discharge of produced waters
and sand, drilling fluids, drill cuttings and certain other substances related
to the oil and natural gas industry into certain coastal and offshore waters.
Further, the EPA has adopted regulations requiring certain oil and natural gas
exploration and production facilities to obtain permits for storm water
discharges. Costs may be associated with the treatment of wastewater or
developing and implementing storm water pollution prevention plans. The Clean
Water Act and comparable state statutes provide for civil, criminal and
administrative penalties for unauthorized discharges for oil and other
pollutants and impose liability on parties responsible for those discharges for
the costs of cleaning up any environmental damage caused by the release and for
natural resource damages resulting from the release. We believe that our
operations comply in all material respects with the requirements of the Clean
Water Act and state statutes enacted to control water pollution. Safe Drinking Water Act. Underground injection is the subsurface
placement of fluid through a well, such as the reinjection of brine produced
and separated from oil and natural gas production. The Safe Drinking Water Act
of 1974, as amended establishes a regulatory framework for underground
injection, with the main goal being the protection of usable aquifers. The
primary objective of injection well operating requirements is to ensure the
mechanical integrity of the injection apparatus and to prevent migration of
fluids from the injection zone into underground sources of drinking water.
Hazardous-waste injection well operations are strictly controlled, and certain
wastes, absent an exemption, cannot be injected into underground injection
control wells. In Louisiana and Texas, no underground injection may take place
except as authorized by permit or rule. We currently own and operate various
underground injection wells. Failure to abide by our permits could subject us
to civil and/or criminal enforcement. We believe that we are in compliance in
all material respects with the requirements of applicable state underground
injection control programs and our permits. Marine Protected Areas. Executive Order 13158, issued on May 26, 2000,
directs federal agencies to safeguard existing Marine Protected Areas
(MPAs)in the United States and establish new MPAs. The order requires federal
agencies to avoid harm to MPAs to the extent permitted by law and to the
maximum extent practicable. It also directs the EPA to propose new regulations
under the Clean Water Act to ensure appropriate levels of protection for the
marine environment. This order has the potential to adversely affect our
operations by restricting areas in which we may carry out future development
and exploration projects and/or causing us to incur increased operating
expenses. 8




---



##### 



Marine Mammal and Endangered Species. Federal Lease Stipulations address
the reduction of potential taking of protected marine species (sea turtles,
marine mammals, Gulf Sturgen and other listed marine species). MMS permit
approvals will be conditioned on collection and removal of debris resulting
from activities related to exploration, development and production of offshore
leases. MMS has issued Notices to Lessees and Operators (NTL) 2003-G06
advising of requirements for posting of signs in prominent places on all
vessels and structures and of an observing training program. Consideration of Environmental Issues in Connection with Governmental
Approvals. Our operations frequently require licenses, permits and/or other
governmental approvals. Several federal statutes, including OCSLA, the National
Environmental Policy Act (NEPA), and the Coastal Zone Management Act (CZMA)
require federal agencies to evaluate environmental issues in connection with
granting such approvals and/or taking other major agency actions. OCSLA, for
instance, requires the U.S. Department of Interior (DOI) to evaluate whether
certain proposed activities would cause serious harm or damage to the marine,
coastal or human environment. Similarly, NEPA requires DOI and other federal
agencies to evaluate major agency actions having the potential to significantly
impact the environment. In the course of such evaluations, an agency would have
to prepare an environmental assessment and, potentially, an environmental
impact statement. CZMA, on the other hand, aids states in developing a coastal
management program to protect the coastal environment from growing demands
associated with various uses, including offshore oil and natural gas
development. In obtaining various approvals from the DOI, we must certify that
we will conduct our activities in a manner consistent with an applicable
program. Lead-Based Paints. Various pieces of equipment and structures owned by us
may have been coated with lead-based paints as was customary in the industry at
the time these pieces of equipment were fabricated and constructed. These
paints may contain lead at a concentration high enough to be considered a
regulated hazardous waste when removed. If we need to remove such paints in
connection with maintenance or other activities and they qualify as a regulated
hazardous waste, this would increase the cost of disposal. High lead levels in
the paint might also require us to institute certain administrative and/or
engineering controls required by the Occupational Safety and Health Act and MMS
to ensure worker safety during paint removal. Air Pollution Control. The Clean Air Act and state air pollution laws
adopted to fulfill its mandates provide a framework for national, state and
local efforts to protect air quality. Our operations utilize equipment that
emits air pollutants subject to federal and state air pollution control laws.
These laws require utilization of air emissions abatement equipment to achieve
prescribed emissions limitations and ambient air quality standards, as well as
operating permits for existing equipment and construction permits for new and
modified equipment. Air emissions associated with offshore activities are
projected using a matrix and formula supplied by MMS, which has primacy from
the Environmental Protection Agency for regulating such emissions. Naturally Occurring Radioactive Materials (NORM). NORM are materials
not covered by the Atomic Energy Act, whose radioactivity is enhanced by
technological processing such as mineral extraction or processing through
exploration and production conducted by the oil and natural gas industry. NORM
wastes are regulated under the RCRA framework, but primary responsibility for
NORM regulation has been a state function. Standards have been developed for
worker protection; treatment, storage and disposal of NORM waste; management of
waste piles, containers and tanks; and limitations upon the release of NORM
contaminated land for unrestricted use. We believe that our operations are in
material compliance with all applicable NORM standards established by the
states, as applicable. Employees At March 23, 2004, the Company had 200 full-time and 10 part-time
employees, 15 of whom were employed by the Company at its principal offices in
Stamford, Connecticut, 23 in Houston, Texas, at the offices of Prime
Operating Company, Eastern Oil Well Service Company, EOWS Midland
Company and F-W Oil
Exploration L.L.C., and 172 employees who were primarily involved in the
district operations of the Company in Houston and Midland, Texas, Oklahoma
City, Oklahoma and Charleston, West Virginia. Item 2. PROPERTIES. The Companys executive offices are located at One Landmark Square,
Stamford, Connecticut, in leased premises of about 6265 square feet. The
executive offices of Prime Operating Company,
Eastern Oil Well Service Company, EOWS Midland Company and F-W Oil
Exploration L.L.C. are located in leased
premises in Houston, Texas, and the offices of Southwest Oilfield Construction
Company are in Oklahoma City, Oklahoma. The Company maintains district offices in Houston and Midland, Texas,
Oklahoma City, Oklahoma and Charleston, West Virginia, and has field offices in
Carrizo Springs and Midland, Texas, Kingfisher and Garvin, Oklahoma and Orma,
West Virginia. 9




---



##### 



Substantially all of the Companys oil and gas properties are subject to a
mortgage given to collateralize indebtedness of the Company, or are subject to
being mortgaged upon request by the Companys lender for additional collateral. The information set forth below concerning the Companys properties,
activities, and oil and gas reserves include the Companys interests in
affiliated entities. The following table sets forth the exploratory and development drilling
experience with respect to wells in which the Company participated during the
five years ended December 31, 2003. 2003
    
    2002
    
    2001
    
    2000
    
    1999Gross
    
    Net
    
    Gross
    
    Net
    
    Gross
    
    Net
    
    Gross
    
    Net
    
    Gross
    
    NetExploratory:Oil
    
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    1
    
    
    
    1
    
    
    
    1.000
    
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    .300Gas
    
    
    
    4
    
    
    
    1.565
    
    
    
    1
    
    
    
    .25
    
    
    
    1
    
    
    
    .602
    
    
    
    3
    
    
    
    1.279
    
    
    
    1
    
    
    
    .683Dry
    
    
    
    6
    
    
    
    1.400
    
    
    
    4
    
    
    
    2.50
    
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    .276
    
    
    
    2
    
    
    
    .510Development:Oil
    
    
    
    6
    
    
    
    2.561
    
    
    
    2
    
    
    
    1.25
    
    
    
    1
    
    
    
    .500
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Gas
    
    
    
    8
    
    
    
    4.478
    
    
    
    10
    
    
    
    7.59
    
    
    
    7
    
    
    
    4.926
    
    
    
    7
    
    
    
    4.134
    
    
    
    2
    
    
    
    .015Dry
    
    
    
    1
    
    
    
    .500
    
    
    
    6
    
    
    
    5.30
    
    
    
    2
    
    
    
    1.585
    
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    .745Total:Oil
    
    
    
    6
    
    
    
    2.56
    
    
    
    3
    
    
    
    2.25
    
    
    
    2
    
    
    
    1.500
    
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    .300Gas
    
    
    
    12
    
    
    
    6.042
    
    
    
    11
    
    
    
    7.84
    
    
    
    8
    
    
    
    5.528
    
    
    
    10
    
    
    
    5.413
    
    
    
    3
    
    
    
    .698Dry
    
    
    
    7
    
    
    
    1.900
    
    
    
    10
    
    
    
    7.80
    
    
    
    2
    
    
    
    1.585
    
    
    
    2
    
    
    
    .276
    
    
    
    4
    
    
    
    1.25525
    
    
    
    10.504
    
    
    
    24
    
    
    
    17.89
    
    
    
    12
    
    
    
    8.613
    
    
    
    12
    
    
    
    5.689
    
    
    
    8
    
    
    
    2.253
 Oil and Gas Production As of December 31, 2003, the Company had ownership interests in the
following numbers of gross and net producing oil and gas wells and gross and
net producing acres (1). Gross
    
    NetProducing wells (1)Oil Wells
    
    
    886
    
    
    
    250.97Gas Wells
    
    
    1,183
    
    
    
    323.73Producing Acres
    
    
    279,206
    
    
    
    97,654
  (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, 2003. Net
production is net after royalty interests of others are deducted and is
determined by multiplying the gross production volume of properties in which
the Company has an interest by percentage of the leasehold, mineral or royalty
interest owned by the Company. 2003
    
    2002
    
    2001
    
    2000
    
    1999Oil (barrels)
    
    
    370,000
    
    
    
    321,000
    
    
    
    306,000
    
    
    
    298,000
    
    
    
    264,000Gas (Mcf)
    
    
    3,991,000
    
    
    
    3,540,000
    
    
    
    3,764,000
    
    
    
    3,930,000
    
    
    
    3,289,000
 10




---



##### 



The following table sets forth the Companys average sales price per barrel of
crude oil and average sales prices per one thousand cubic feet (Mcf) of gas,
together with the Companys average production costs per unit of production for
the five years ended December 31, 2003. 2003
    
    2002
    
    2001
    
    2000
    
    1999Average sales price
per barrel
    
    $
    28.90
    
    
    
    23.37
    
    
    
    24.92
    
    
    
    28.34
    
    
    
    15.71Average sales price
Per Mcf
    
    $
    4.80
    
    
    
    3.06
    
    
    
    4.08
    
    
    
    3.76
    
    
    
    2.32Average production
costs per net equivalent
barrel (1)
    
    $
    12.42
    
    
    
    11.80
    
    
    
    11.88
    
    
    
    9.57
    
    
    
    7.76
    (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, 2003. Undeveloped acreage is that acreage on which wells have
not been drilled or completed to a point that would permit the production of
commercial quantities of oil and gas, regardless of whether or not such acreage
contains proved reserves. Leasehold
    
    Mineral
    
    RoyaltyInterests
    
    Interests
    
    InterestsGross
    
    Net
    
    Gross
    
    Net
    
    Gross
    
    NetState
    
    Acres
    
    Acres
    
    Acres
    
    Acres
    
    Acres
    
    AcresColorado
    
    
    
    
    
    
    
    
    
    
    799
    
    
    
    23
    
    
    
    
    
    
    
    Gulf of
Mexico
    
    
    93,690
    
    
    
    47,874
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Montana
    
    
    
    
    
    
    
    
    
    
    13,984
    
    
    
    59
    
    
    
    786
    
    
    
    5Nebraska
    
    
    
    
    
    
    
    
    
    
    2,553
    
    
    
    331
    
    
    
    
    
    
    
    North Dakota
    
    
    
    
    
    
    
    
    
    
    640
    
    
    
    1
    
    
    
    
    
    
    
    Oklahoma
    
    
    6,345
    
    
    
    3,742
    
    
    
    320
    
    
    
    1
    
    
    
    
    
    
    
    Texas
    
    
    13,383
    
    
    
    7,086
    
    
    
    680
    
    
    
    16
    
    
    
    
    
    
    
    Wyoming
    
    
    1,000
    
    
    
    125
    
    
    
    5043
    
    
    
    35
    
    
    
    140
    
    
    
    35TOTAL
    
    
    114,419
    
    
    
    56,699
    
    
    
    24,019
    
    
    
    466
    
    
    
    926
    
    
    
    40
 Reserves The Companys interests in proved developed and undeveloped oil and gas
properties have been evaluated by Ryder Scott Company, L.P. for each of the
five years ended December 31, 2003. All of the Companys reserves are located
within the continental United States. The following table summarizes the
Companys oil and gas reserves at each of the respective dates (figures
rounded): Reserve CategoryProved Developed
    
    Proved Undeveloped
    
    TotalAs of
    
    Oil
    
    Gas
    
    Oil
    
    Gas
    
    Oil
    
    Gas12-31
    
    (bbls)
    
    (Mcf)
    
    (bbls)
    
    (Mcf)
    
    (bbls)
    
    (Mcf)1999
    
    
    2,110,000
    
    
    
    22,046,000
    
    
    
    
    
    
    
    156,000
    
    
    
    2,110,000
    
    
    
    22,202,0002000
    
    
    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
    
    
    
    39,005,000
 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, 2003, 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 Revenue1999
    
    $
    41,103,000
    
    
    
    26,057,000
    
    
    
    258,000
    
    
    
    151,000
    
    
    
    41,361,000
    
    
    
    26,208,0002000
    
    $
    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
    
    
    
    103,096,000
 11




---



##### 



Proved developed oil and gas reserves are reserves that can be expected
to be recovered from existing wells with existing equipment and operating
methods. Proved undeveloped oil and gas reserves are reserves that are
expected to be recovered from new wells on undrilled acreage, or from existing
wells where a relatively major expenditure is required for recompletion. In accordance with FASB Statement No. 69, December 31 market prices are
determined using the daily oil price or daily gas sales price (spot price)
adjusted for oilfield or gas gathering hub and wellhead price differentials
(e.g. grade, transportation, gravity, sulfur, and BS&W) as appropriate. Also
in accordance with SEC and FASB specifications, changes in market prices
subsequent to December 31 are not considered. The spot price for gas at December 31, 2003 and 2002 were $5.97 and $4.75
per MMBTU, respectively. The range of spot prices during the year 2003 was a
low of $3.96 and a high of $12.20 and the average was $5.48. The range during
the first quarter of 2004 has been from $5.08 to $7.01 with an average of $5.65.
The recent futures market prices have been in the around $5.50. The NYMEX price for oil at December 31, 2003 and 2002 was $32.55 and
$31.23 per barrel, respectively. The range of NYMEX prices during the year
2003 was a low of $22.00 and a high of $34.50 and the average was $27.67
Range during the first quarter of 2004 has been from $29.50 to $34.75 with an
average of $31.95 The recent futures market prices have fluctuated around
$37.00. While it may reasonably be anticipated that the prices received by the
Company for the sale of its production may be higher or lower than the prices
used in this evaluation, as described above, and the operating costs relating
to such production may also increase or decrease from existing levels, such
possible changes in prices and costs were, in accordance with rules adopted by
the SEC, omitted from consideration in making this evaluation for the SEC case.
Actual volumes produced, prices received and costs incurred by the Company may
vary significantly from the SEC case. Since January 1, 2004, the Company has not filed any estimates of its oil
and gas reserves with, nor were any such estimates included in any reports to,
any federal authority or agency, other than the Securities and Exchange
Commission, except Form EIA-23, Annual Survey of Domestic Oil and Gas Reserves,
filed with The Energy Information Administration of the U.S. Department of
Energy. Item 3. LEGAL PROCEEDINGS. From time to time, the Company is party to certain legal actions and
claims arising in the ordinary course of business. While the outcome of these
events cannot be predicted with certainty, management does not expect these
matters to have a materially adverse effect on the financial position or
results of operations of the Company. Item 4. SUBMISSION OF
MATTERS TO A VOTE OF SECURITY HOLDERS. No matters were submitted during the fourth quarter of the fiscal year
ended December 31, 2003 to a vote of the Companys security-holders through the
solicitation of proxies or otherwise. 12




---



##### 



PART II 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, 2003, were as follows: 2003
    
    High
    
    LowFirst Quarter
    
    
    9.43
    
    
    
    8.00Second Quarter
    
    
    9.70
    
    
    
    8.05Third Quarter
    
    
    10.56
    
    
    
    9.50Fourth Quarter
    
    
    14.61
    
    
    
    9.43
 2002
    
    High
    
    LowFirst Quarter
    
    $
    8.53
    
    
    $
    7.90Second Quarter
    
    
    9.07
    
    
    
    8.00Third Quarter
    
    
    9.01
    
    
    
    8.00Fourth Quarter
    
    
    8.25
    
    
    
    8.00
 The above quotations reflect inter-dealer prices, without retail mark-up,
mark-down or commissions, and may not represent actual transactions. The number of record holders of the Companys Common Stock as of March 25,
2004 was 998. No dividends have been declared or paid during the past two years on the
Companys Common Stock. Provisions of the Companys line of credit agreement
restrict the Companys ability to pay dividends. Such dividends may be
declared out of funds legally available therefore, when and as declared by the
Companys Board of Directors. Item 6. SELECTED FINANCIAL DATA The following table summarizes certain selected financial data to
highlight significant trends in the Companys financial condition and results
of operations for the periods indicated. The selected financial data should be
read in conjunction with the Financial Statements and related notes included
elsewhere in this Report. 2003
    
    2002
    
    2001
    
    2000
    
    1999Revenues
    
    $
    48,428,000
    
    
    
    35,934,000
    
    
    
    42,408,000
    
    
    
    39,182,000
    
    
    
    25,520,000Income (loss) from operations
    
    $
    8,047,000
    
    
    
    2,168,000
    
    
    
    6,968,000
    
    
    
    6,148,000
    
    
    
    (2,116,000
    )Net Income (loss)
    
    $
    5,702,000
    
    
    
    1,757,000
    
    
    
    5,413,000
    
    
    
    5,365,000
    
    
    
    (2,138,000
    )Income (loss) per common share
    
    $
    1.56
    
    
    
    0.47
    
    
    
    1.39
    
    
    
    1.26
    
    
    
    (0.48
    )Net Cash provided by operations
    
    $
    19,622,000
    
    
    
    9,644,000
    
    
    
    12,313,000
    
    
    
    11,498,000
    
    
    
    7,677,000Total Assets
    
    $
    58,255,000
    
    
    
    44,887,000
    
    
    
    35,816,000
    
    
    
    35,094,000
    
    
    
    30,475,000Long-term obligations
    
    $
    26,925,000
    
    
    
    23,734,000
    
    
    
    16,958,000
    
    
    
    18,213,000
    
    
    
    19,217,000Cash 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. Liquidity And Capital Resources Cash flow provided by operations for the year ended December 31,
2003,increased by $10 million, compared to the prior year, primarily due
to a 14% increase in production and an increase in oil and gas prices
throughout the entire year, combined with changes in our working
capital accounts. We expect sufficient cash flow to be provided by
operations during
2004 because of higher projected production from new properties,
combined with oil and gas prices consistent with 2003 and steady operating,
general and administrative, interest and financing costs. Excluding the effects of significant unforeseen expenses or other income,
our cash flow from operations fluctuates primarily because of variations in oil
and gas production and prices or changes in working capital accounts. Our oil
and gas production will vary based on actual well performance but may be
curtailed due to factors beyond our control. Hurricanes in the Gulf of Mexico
may shut down our production for the duration of the storms presence in the
Gulf or damage production facilities so that we cannot produce from a
particular property for an extended amount of time. In addition, downstream
activities on major pipelines in the Gulf of Mexico can also cause us to
shut-in production for various lengths of time. 13




---



##### 



Our realized oil and gas prices vary due to world political events, supply
and demand of products, product storage levels, and weather patterns. We sell
the vast majority of our production at spot market prices. Accordingly, product
price volatility will affect our cash flow from operations. To mitigate price
volatility we sometimes lock in prices for some portion of our production
through the use of financial instruments. Currently we have no such
arrangements in place. We expect to continue to make significant capital expenditures over the
next several years as part of our long-term growth strategy. We have budgeted
$16 million for drilling expenditures in 2004. We project that we
will spend $10 million in the Gulf of Mexico and $6 million on onshore wells. If our exploratory drilling results in significant new discoveries, we
will have to expend additional capital in order to finance the completion,
development, and potential additional opportunities generated by our success.
We believe that, because of the additional reserves resulting from the success
and our record of reserve growth in recent years, we will be able to access
sufficient additional capital through additional bank financing. Effective
February 2004, we agreed with our lenders to increase the borrowing base
from $28,999,996 million to $47,066,662 million and to extend the maturity of the loan facility
from March 2005 to March 2007. As of December 31, 2003, $28,800,000 million was borrowed under the
facility. The banks review the borrowing base semi-annually and, at their
discretion, may decrease or propose an increase to the borrowing base relative
to a redetermined estimate of proved oil and gas reserves. Our oil and gas
properties are pledged as collateral for the line of credit and we are subject
to certain financial covenants defined in the agreement. We are currently in
compliance with these financial covenants. If we do not comply with these
covenants on a continuing basis, the lenders have the right to refuse to
advance additional funds under the facility and/or declare all principal and
interest immediately due and payable. It is the goal of the Company to increase its oil and gas reserves and
production through the acquisition and development of oil and gas properties.
The Company also continues to explore and consider opportunities to further
expand its oilfield servicing revenues through additional investment in field
service equipment. However, the majority of the Companys capital spending is
discretionary, and the ultimate level of expenditures will be dependent on the
Companys assessment of the oil and gas business environment, the number and
quality of oil and gas prospects available, the market for oilfield services,
and oil and gas business opportunities in general. Results of Operations: 2003 as compared to 2002 The Company had net income of $5,702,000 in 2003 as compared to $1,757,000
in 2002 Oil
and gas 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
 District operating incomeincreased to $16,630,000 in 2003 from
$15,308,000 in 2002. This increase reflects higher utilization of
equipment during 2003. 14




---



##### 



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. Administrative revenue, which represents the reimbursement of general and
administrative overhead expended on behalf of the Partnerships and the
Companys joint venture partners remained unchanged. In both years, amounts
received from certain of the Partnerships were substantially less than the
amounts allocable to these Partnerships under the partnership agreements. The
lower amounts reflect PEMCs continuing efforts to reduce costs, both incurred
and allocated to the Partnerships. Reporting and management feesare earned from providing the accounting and
reporting functions for certain of the Partnerships. The Company receives reimbursement for costs incurred related to the
evaluation and acquisition of properties on behalf of the Partnerships and
other joint venture partners. To the extent that these property acquisition
costs are expended at the district level, the reimbursements are recorded as a
reduction of total district operating expenses. When expenses are incurred at
the corporate headquarters level, such reimbursements are recorded as a
reduction of total general and administrative expenses. During 2003 and 2002,
the Companys total reimbursements for property acquisition costs were
approximately $327,000 and $450,000, respectively. General and administrative expensesincreased to $5,135,000 in 2003 as
compared to $ 4,888,000 in 2002 . This increase reflects the addition
of FWs costs and increased ownership in the Partnerships offset by savings
related to reduced personnel costs in the Connecticut office Depreciation and 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 costs of $519,000 were incurred during 2003 drilling seven dry holes. Exploration costs of
$894,000 were incurred during 2002 drilling five dry holes. Interest 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 expense of $2,446,000 in 2003 represents a 30% effective rate
as compared to the effective rate of 20% in 2002. Current tax expense in 2003
was $867,000 with the remainder being attributable to an increase in the
Companys deferred tax liability. The primary reason that the Companys federal tax expense for 2003 is well below the statutory rate is that the Company is allowed to deduct currently,
rather than capitalize, intangible drilling costs as incurred. The current deduction of these costs, which are capitalized for financial accounting purposes,
is also the primary reason for the increase in the Companys deferred tax liability between 2002 and 2003. 15




---



##### 



2002 as compared to 2001 The Company had net income of $1,757,000 in 2002 as compared to
$5,413,000 in 2001. The decrease in net income is primarily due to lower
commodity prices. Oil and gas saleswere $18,330,000 in 2002 as compared to $22,998,000 in
2001 A chart summarizing oil and gas production and revenue, including the
Companys share of production and revenue from the Partnerships, follows. 2002
    
    2001
    
    Increase (Decrease)Barrels of Oil Produced
    
    
    321,384
    
    
    
    306,016
    
    
    
    15,368Average Price Received
    
    $
    23.37
    
    
    $
    24.92
    
    
    ($
    1.55
    )Oil Revenue
    
    $
    7,510,000
    
    
    $
    7,626,000
    
    
    ($
    117,000
    )Mcf of Gas Produced
    
    
    3,540,000
    
    
    
    3,763,605
    
    
    
    (259,605
    )Average Price Received
    
    $
    3.0564
    
    
    $
    4.08
    
    
    ($
    1.03
    )Gas Revenue
    
    $
    10,820,000
    
    
    $
    15,372,000
    
    
    ($
    4,552,000
    )Total Oil & Gas Revenue
    
    $
    18,330,000
    
    
    $
    22,998,000
    
    
    ($
    4,668,000
    )
 District operating incomedecreased from $17,082,000 in 2001 to
$15,308,000 in 2002 This decrease is due to reduced utilization of equipment
combined with discounted rates in effect during the first half of 2002. Lease operating expensesdecreased by 8% to $10,210,000 in 2002 as
compared to $11,083,000 in 2001. The difference is attributable to production
taxes related to lower prices combined with discounts on expenses due to the
weak price environment in the first half of 2002 Administrative revenue, which represents the reimbursement of general and
administrative overhead expended on behalf of the Partnerships and the
Companys joint venture partners decreased by 4% to $1,473,000 in 2002 as
compared to $1,535,000 in 2001. In both years, amounts received from certain
of the Partnerships were substantially less than the amounts allocable to these
Partnerships under the partnership agreements. The lower amounts reflect
PEMCs continuing efforts to reduce costs, both incurred and allocated to the
Partnerships. Reporting and management feesare earned from providing the accounting and
reporting functions for certain of the Partnerships. The Company receives reimbursement for costs incurred related to the
evaluation and acquisition of properties on behalf of the Partnerships and
other joint venture partners. To the extent that these property acquisition
costs are expended at the district level, the reimbursements are recorded as a
reduction of total district operating expenses. When expenses are incurred at
the corporate headquarters level, such reimbursements are recorded as a
reduction of total general and administrative expenses. During 2002 and 2001,
the Companys total reimbursements for property acquisition costs were
approximately $450,000 and $558,000, respectively. General
and administrative expensesincreased to $4,888,000 in 2002 as
compared to $4,310,000 in 2001. This increase reflects the change in cost
reimbursement combined with an increase in the Companys share of general and
administrative expenses incurred by the Partnerships. Depreciation and depletionof oil and gas properties decreased by 12% to
$3,988,000 in 2002 as compared to $4,522,000 in 2001 as a result of increases
in estimates of proved reserves. Exploration costsof $894,000 were incurred during 2002 drilling five dry
holes. Exploration costs of $509,000 in 2001 consist primarily of the cost of
three dry holes drilled in 2001. 16




---



##### 



Interest expensedeclined to $766,000 in 2002 as compared to $895,000 in
2001 due to a combination of lower interest rates and lower average outstanding
debt. The average interest rates paid on outstanding
borrowings subject to interest at the banks base rate during 2002 and
2001 were 4.25% and 6.92%, respectively. During the same periods, the average
rates paid on outstanding borrowings bearing interest based upon the LIBO rate
were 3.58% and 5.98% As of December 31, 2002 and 2001, the total outstanding
borrowings were$24,500,000 and $16,950,000, respectively. Income tax expense of $443,000 in 2002 represents a 20% effective rate as
compared to the effective rate of 24% in 2001. Current tax expense in 2002 was
$199,000 with the remainder being attributable to an increase in the Companys
deferred tax liability. The low current tax expense is primarily attributable
to federal tax credits for producing fuel from a nonconventional source,
percentage depletion deductions, larger depreciation deductions allowed for tax
purposes, and the utilization of federal net operating loss carry forward. All of the Companys net operating loss carry forwards will have been used
or expired as of the end of 2002, and under current law the credit for
producing fuel from a nonconventional source will no longer be allowed after
2002, it is possible that the companys current and overall tax rates may be
significantly higher in future years Item 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. The Company is exposed to interest rate risk on its line of credit, which
has variable rates based upon the lenders base rate, as defined, and the London
Inter-Bank Offered rate. Based on the balance outstanding at December 31,
2003, a hypothetical 2% increase in the applicable interest rates would
increase interest expense by approximately $401,000. Oil and gas prices have historically been extremely volatile, and have
been particularly so in recent years. The Company did not enter into
significant hedging transactions during 2003, and had no open hedging
transactions at December 31, 2003. Declines in domestic oil and gas prices
could have a material adverse effect on the Companys revenues, operating
results, estimates of economically recoverable reserves and the net revenue
there from. Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. Included on pages F-1 through F-26 of this Report. The Index to
Financial Statements is at page F-1 of this Report. Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None. 17




---



##### 



Item 9A. INTERNAL CONTROLS AND PROCEDURES. Based upon an evaluation within the 90 days prior to the filing date of
this report, our Chief Executive Officer and Chief Financial Officer have each
concluded that our disclosure controls and procedures as defined in Rules
13a-14 and 15d-14 of the Securities Exchange Act of 1934, as amended, are
effective, as of the evaluation date, in timely alerting them to material
information relating to our Company required to be included in our reports
filed or submitted under the Exchange Act. Since the date of the evaluation,
there have been no significant changes in our internal controls or in other
factors that could significantly affect such controls, including any corrective
actions with regard to significant deficiencies and material weaknesses. Our management, including the Chief Executive Officer and Chief Financial
Officer, does not expect that our disclosure controls and procedures or our
internal controls will prevent all errors and all fraud. A control system, no
matter how well conceived and operated, can provide only reasonable, not
absolute, assurance that the objectives of the control system are met. Further,
the design of a control system must reflect the fact that there are resource
constraints, and the benefits of controls must be considered relative to their
costs. Because of the inherent limitations in all control systems, no
evaluation of controls can provide absolute assurance that all control issues
and instances of fraud, if any, within the company have been detected. These
inherent limitations include the realities that judgments in decision-making
can be faulty, and that breakdowns can occur because of simple error or
mistake. Additionally, controls can be circumvented by the individual acts of
some persons or by collusion of two or more people. The design of any system of
controls also is based in part upon certain assumptions about the likelihood of
future events, and there can be no assurance that any design will succeed in
achieving its stated goals under all potential future conditions; over time,
controls may become inadequate because of changes in conditions, or the degree
of compliance with the policies or procedures may deteriorate. Because of the
inherent limitations in a cost-effective control system, misstatements due to
error or fraud may occur and not be detected. Accordingly, our disclosure
controls and procedures are designed to provide reasonable, not absolute,
assurance that the objectives of our disclosure control system are met and, as
set forth above, our Chief Executive Officer and Chief Financial Officer have
concluded, based on their evaluation as of the end of the period, that our
disclosure controls and procedures were sufficiently effective to provide
reasonable assurance that the objectives of our disclosure control system were
met. PART III Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information relating to the Companys Directors, nominees for Directors
and executive officers is included in the Companys definitive proxy statement
relating the Companys Annual Meeting of Stockholders to be held
in June, 2004,
which will be filed with the U.S. Securities and Exchange Commission within 120
days of December 31, 2003 and which is incorporated herein by reference.. Item 11. EXECUTIVE COMPENSATION. Information relating to executive compensation is included in the
Companys definitive proxy statement relating to the Companys Annual Meeting
of Stockholders to be held in June, 2004, which will be filed with the U.S.
Securities and Exchange Commission within 120 days of December 31, 2003 and
which is incorporated herein by reference. 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, 2004, which
will be filed with the U.S. Securities and Exchange Commission within 120 days
of December 31, 2003 and which is incorporated herein by reference. Item 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS. Information relating to certain transactions by Directors and executive
officers of the Company is included in the Companys definitive proxy statement
relating the Companys Annual Meeting of Stockholders to be held
in June, 2004,
which will be filed with the U.S. Securities and Exchange Commission within 120
days of December 31, 2003 and which is incorporated herein by reference. 18




---



##### 



Item 14. PRINCIPAL
ACCOUNTANT FEES AND SERVICES. Information relating to principal accountant fees and services is included in
the Companys definitive proxy statement relating to the Companys Annual
Meeting of Stockholders to be held in June, 2004, which will be filed with the
U.S. Securities and Exchange Commission within 120 days of December 31, 2003
and which is incorporated herein by reference. 19




---



##### 



PART IV Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.  (a)
    
    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 No.3.1
    
    Restated Certificate of Incorporation of PrimeEnergy Corporation.
(Incorporated herein by reference to Exhibit 3.1 of PrimeEnergy Corporation Form 10-KSB
for the year ended December 31, 1999)3.2
    
    Bylaws of PrimeEnergy Corporation. (Incorporated herein by
reference to Exhibit 3.2 of PrimeEnergy Corporation Form 10-KSB for
the year ended December 31, 1999)10.3.1
    
    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 (filed herewith)(1)10.17
    
    Amended Marketing Agreement between PrimeEnergy Management
Corporation and Charles E. Drimal, Jr. (Incorporated herein by
reference to Exhibit 10.17 of PrimeEnergy Corporation Form 10-KSB for
the year ended December 31, 1994) (1)10.18
    
    Composite copy of Non-Statutory Option Agreements (Incorporated
by reference to Exhibit 10.18 of PrimeEnergy Corporation for 10-KSB for
the year ended December 31, 1997) (1)10.22
    
    Credit Agreement dated as of December 19, 2002 between
PrimeEnergy Corporation, PrimeEnergy Management Corporation, 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)10.22.1
    
    First Amendment to Credit Agreement dated as of effective as of
June 1, 2003 between PrimeEnergy Corporation, PrimeEnergy Management
Corporation, Eastern Oil Well Service Company, Southwest Oilfield
Construction Company, EOWS Midland Company and Guaranty Bank , FSB
(filed herewith)10.22.2
    
    Second Amendment to Credit Agreement effective as of September 22,
2003 between PrimeEnergy Corporation, PrimeEnergy Management
Corporation, 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)10.23
    
    Mortgage, Deed of Trust, Security Agreement, Financing Statement
and Assignment of Production from PrimeEenrgy 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)
 20




---



##### 



Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. continued 10.23.1
    
    Ratification of and Amendment to Mortgage, Deed of trust,
Indenture, Security Agreement, Financing Statement and Assignment of
Production effective September 22, 2003 by PrimeEnergy Corporation,
PrimeEnergy Management Corporation, Eastern Oil Well Service Company,
and Southwest Oilfield Construction Company for the benefit of
Guaranty Bank , FSB ( filed herewith)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)21
    
    Subsidiaries. (filed herewith)22
    
    Consent of Ryder Scott & Company L.P. Company. (filed herewith)31.1
    
    Certification of Chief Executive Officer pursuant to Rule
13(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 Rule
13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as
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).
    (1)
    
    Management contract or compensatory plan or arrangement required to be
filed as an Exhibit to this Form 10-K.  (a)
    
    Reports on Form 8-K:None 21




---



##### 



SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Report to be signed
on its behalf by the undersigned, thereunto duly authorized, on the 30th day of
March, 2004. PrimeEnergy CorporationBy:
    /s/ CHARLES E. DRIMAL, JR.Charles E. Drimal, Jr.President Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below by the following persons on behalf of the
Registrant and in the capacities indicated and on the 30th day of March, 2004. /s/CHARLES E. DRIMAL, JR.

Charles E. Drimal, Jr.
    
    Director and President;
The Principal Executive Officer/s/ BEVERLY A. CUMMINGS

Beverly A. Cummings
    
    Director, Vice President and Treasurer;
The Principal Financial and Accounting OfficerDirector
    
    /s/ CLINT HURT
    
    DirectorJames P. Boldrick
    
    
    
    Clint HurtDirector
    
    
    
    DirectorSamuel R. Campbell
    
    
    
    Jarvis SladeDirector
    
    /s/ JAN K. SMEETS
    
    DirectorJames E. Clark
    
    
    
    Jan K. Smeets/s/ MATTHIAS ECKENSTEIN
    
    Director
    
    /s/ GAINES WEHRLE
    
    DirectorMatthias Eckenstein
    
    
    
    Gaines Wehrle/s/ H. GIFFORD FONG
    
    Director
    
    
    
    DirectorH. Gifford Fong
    
    
    
    Michael Wehrle/s/
THOMAS S.T. GIMBEL
    
    DirectorThomas S.T. Gimbel
 22




---



##### 



INDEX TO FINANCIAL STATEMENTS Financial
Statements (Included herein at pages F-1 through F-26):Report of Independent Public Accountants
    
    
    F-2Financial StatementsConsolidated Balance Sheets  December 31, 2003 and 2002
    
    
    F-3Consolidated Statements of Operations  for the years ended December 31,
2003, 2002 and 2001
    
    
    F-5Consolidated Statement of Stockholders Equity  for the years ended
December 31, 2003, 2002 and 2001
    
    
    F-6Consolidated Statements of Cash Flows  for the years ended December 31,
2003, 2002 and 2001
    
    
    F-7Notes to Consolidated Financial Statements
    
    
    F-8Supplementary Information:
    
    
    F-19Capitalized Costs Relating to Oil and Gas Producing Operations
December 31, 2003, 2002 and 2001
    
    
    F-21Costs Incurred in Oil and Gas Property Acquisition, Exploration and
Development Activities, years ended December 31, 2003, 2002 and 2001
    
    
    F-21Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas reserves, years ended December 31, 2003,
2002 and 2001
    
    
    F-22Standardized Measure of Discounted Future Net Cash Flows and Changes
Therein Relating to Proved Oil an Gas Reserves, years ended December 31,
2003, 2002 and 2001
    
    
    F-23Reserve Quantity Information, years ended December 31, 2003, 2002
and 2001
    
    
    F-24Results of Operations from Oil and Gas Producing Activities, years ended
December 31, 2003, 2002 and 2001
    
    
    F-25Notes to Supplementary Information
    
    
    F-26
 F-1




---



##### 



REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Stockholders of      PrimeEnergy
Corporation and Subsidiaries: We have audited the accompanying consolidated balance sheets of PrimeEnergy
Corporation and Subsidiaries as of December 31, 2003 and 2002, and the related
consolidated statements of operations, stockholders equity, and cash flows for
the years ended December 31 2003, 2002 and 2001. These financial statements are
the responsibility of the Corporations management. Our responsibility is to
express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of PrimeEnergy
Corporation and Subsidiaries as of December 31, 2003 and 2002, and the
consolidated results of its operations and cash flows for the years ended
December 31, 2003, 2002 and 2001 in conformity with accounting principles
generally accepted in the United States of America. PUSTORINO, PUGLISI & CO., LLP
New York, New York
March 30, 2004 F-2




---



##### 



PRIMEENERGY CORPORATION and SUBSIDIARIES CONSOLIDATED BALANCE SHEETS, December 31, 2003 and 2002 2003
    
    2002ASSETS:Current assets:Cash and cash equivalents
    
    $
    3,891,000
    
    
    $
    1,886,000Restricted cash and cash equivalents
    
    
    1,479,000
    
    
    
    750,000Accounts receivable, net
    
    
    7,108,000
    
    
    
    4,126,000Due from related parties (less allowance for doubtful
accounts $800,000 in 2002)
    
    
    209,000
    
    
    
    4,771,000Prepaid expenses
    
    
    336,000
    
    
    
    239,000Other current assets
    
    
    297,000
    
    
    
    322,000Deferred income taxes
    
    
    374,000
    
    
    
    309,000Total current assets
    
    
    13,694,000
    
    
    
    12,403,000Property and equipment, at cost :Oil and gas properties (successful efforts method):Proved
    
    
    91,012,000
    
    
    
    74,319,000Unproved
    
    
    3,091,000
    
    
    
    1,134,000Furniture, fixtures and equipment including leasehold
improvements
    
    
    9,389,000
    
    
    
    8,949,000103,492,000
    
    
    
    84,402,000Accumulated depreciation, depletion and amortization
    
    
    (59,160,000
    )
    
    
    (52,102,000
    )Net property and equipment
    
    
    44,332,000
    
    
    
    32,300,000Other assets
    
    
    229,000
    
    
    
    206,000Total assets
    
    $
    58,255,000
    
    
    $
    44,909,000
 The accompanying notes are an integral part of the consolidated financial statements. F-3




---



##### 



PRIMEENERGY CORPORATION and SUBSIDIARIES CONSOLIDATED BALANCE SHEETS, December 31, 2003 and 2002 2003
    
    2002LIABILITIES and STOCKHOLDERS EQUITY:Current liabilities:Accounts payable
    
    $
    8,528,000
    
    
    $
    6,100,000Current portion of other long-term obligations
    
    
    692,000
    
    
    
    824,000Accrued liabilities:Payroll,
Benefits, Interest and Other
    
    
    3,504,000
    
    
    
    1,779,000Due to related parties
    
    
    933,000
    
    
    
    1,485,000Total current liabilities
    
    
    13,657,000
    
    
    
    10,208,000Long-term bank debt
    
    
    26,613,000
    
    
    
    23,700,000Other long-term obligations
    
    
    12,000
    
    
    
    34,000Asset retirement obligations
    
    
    300,000
    
    
    
    Deferred income taxes
    
    
    4,237,000
    
    
    
    2,592,000Total liabilities
    
    
    44,819,000
    
    
    
    36,534,000Stockholders 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 2003 and 2002
    
    
    769,000
    
    
    
    769,000Paid in capital
    
    
    11,024,000
    
    
    
    11,024,000Retained earnings
    
    
    15,378,000
    
    
    
    9,676,00027,171,000
    
    
    
    21,469,000Treasury stock, at cost 4,065,768 common shares in 2003
and 4,001,964 in 2002
    
    
    (13,735,000
    )
    
    
    (13,094,000
    )Total stockholders equity
    
    
    13,436,000
    
    
    
    8,375,000Total liabilities and stockholders equity
    
    $
    58,255,000
    
    
    $
    44,909,000
 The accompanying notes are an integral part of the consolidated financial statements. F-4




---



##### 



PRIMEENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS of OPERATIONS for the years ended December 31, 2003, 2002 and 2001 2003
    
    2002
    
    2001Revenue:Oil and gas sales
    
    $
    29,855,000
    
    
    $
    18,330,000
    
    
    $
    22,998,000District operating income
    
    
    16,630,000
    
    
    
    15,308,000
    
    
    
    17,082,000Administrative revenue
    
    
    1,474,000
    
    
    
    1,473,000
    
    
    
    1,535,000Reporting and management fees
    
    
    234,000
    
    
    
    275,000
    
    
    
    297,000Gains/(losses) on derivative instruments net
    
    
    (52,000
    )
    
    
    (113,000
    )
    
    
    Interest income
    
    
    46,000
    
    
    
    52,000
    
    
    
    138,000Other income
    
    
    241,000
    
    
    
    609,000
    
    
    
    358,00048,428,000
    
    
    
    35,934,000
    
    
    
    42,408,000Costs and expenses:Lease operating expense
    
    
    12,783,000
    
    
    
    10,210,000
    
    
    
    11,083,000District operating expense
    
    
    14,781,000
    
    
    
    13,020,000
    
    
    
    13,368,000Depreciation and depletion of
oil and gas properties
    
    
    6,283,000
    
    
    
    3,988,000
    
    
    
    4,522,000Impairment of oil and gas properties
    
    
    
    
    
    
    
    
    
    
    753,000General and administrative expense
    
    
    5,135,000
    
    
    
    4,888,000
    
    
    
    4,310,000Exploration costs
    
    
    519,000
    
    
    
    894,000
    
    
    
    509,000Interest expense
    
    
    880,000
    
    
    
    766,000
    
    
    
    895,00040,381,000
    
    
    
    33,766,000
    
    
    
    35,440,000Income from operations
    
    
    8,047,000
    
    
    
    2,168,000
    
    
    
    6,968,000Other income:Gain on sale and exchange of assets
    
    
    101,000
    
    
    
    32,000
    
    
    
    166,000Income before provision for income taxes
    
    
    8,148,000
    
    
    
    2,200,000
    
    
    
    7,134,000Provision for income taxes
    
    
    2,446,000
    
    
    
    443,000
    
    
    
    1,721,000Net income
    
    $
    5,702,000
    
    
    $
    1,757,000
    
    
    $
    5,413,000Basic net income per common share
    
    $
    1.56
    
    
    $
    0.47
    
    
    $
    1.39Diluted net income per common share
    
    $
    1.31
    
    
    $
    0.40
    
    
    $
    1.18
 The accompanying notes are an integral part of the consolidated financial statements. F-5




---



##### 



PRIMEENERGY CORPORATION and SUBSIDIARIES CONSOLIDATED STATEMENT of STOCKHOLDERS EQUITY for the years ended December 31, 2003, 2002 and 2001 AdditionalCommon Stock
    
    Paid In
    
    Retained
    
    TreasuryShares
    
    Amount
    
    Capital
    
    Earnings
    
    Stock
    
    TotalBalance at December 31, 2000
    
    
    7,607,970
    
    
    $
    761,000
    
    
    $
    10,902,000
    
    
    $
    2,506,000
    
    
    $
    (9,193,000
    )
    
    $
    4,976,000Exercised stock options
    
    
    87,000
    
    
    
    8,000
    
    
    
    122,000
    
    
    
    
    
    
    
    
    
    
    
    130,000Purchased 420,160 shares of
common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (3,156,000
    )
    
    
    (3,156,000
    )Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5,413,000
    
    
    
    
    
    
    
    5,413,000Balance 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
    )
    
    $
    13,436,000
 The accompanying notes are an integral part of the consolidated financial statements. F-6




---



##### 



PRIMEENERGY CORPORATION and SUBSIDIARIES CONSOLIDATED STATEMENTS of CASH FLOWS for the years ended December 31, 2003, 2002 and 2001 2003
    
    2002
    
    2001Cash flows from operating activities:Net income
    
    $
    5,702,000
    
    
    $
    1,757,000
    
    
    $
    5,413,000Adjustments to reconcile net loss to net cash
provided
by operating activities:Depreciation, depletion and amortization
    
    
    7,525,000
    
    
    
    5,231,000
    
    
    
    5,599,000Impairment of oil and gas properties
    
    
    
    
    
    
    
    
    
    
    753,000Dry hole and abandonment costs
    
    
    519,000
    
    
    
    894,000
    
    
    
    496,000Gain on sale of properties
    
    
    (101,000
    )
    
    
    (32,000
    )
    
    
    (166,000
    )Provision for deferred income taxes
    
    
    1,580,000
    
    
    
    243,000
    
    
    
    1,684,000Changes in assets and liabilities:(Increase) decrease in accounts receivable
    
    
    (2,982,000
    )
    
    
    (328,000
    )
    
    
    1,865,000(Increase) decrease in due from related parties
    
    
    4,562,000
    
    
    
    153,000
    
    
    
    (578,000
    )(Increase) decrease in other assets
    
    
    3,000
    
    
    
    682,000
    
    
    
    (874,000
    )(Increase) decrease in prepaid expenses
    
    
    (97,000
    )
    
    
    (175,000
    )
    
    
    48,000Increase (decrease) in accounts payable
    
    
    1,699,000
    
    
    
    736,000
    
    
    
    (1,086,000
    )Increase (decrease) in accrued liabilities
    
    
    1,712,000
    
    
    
    (19,000
    )
    
    
    (559,000
    )Increase (decrease) in due to related parties
    
    
    (500,000
    )
    
    
    502,000
    
    
    
    (282,000
    )Net cash provided by operating activities
    
    
    19,622,000
    
    
    
    9,644,000
    
    
    
    12,313,000Cash flows from investing activitiesProceeds from sale of properties and equipment
    
    
    101,000
    
    
    
    32,000
    
    
    
    520,000Additions to property and equipment
    
    
    (19,835,000
    )
    
    
    (14,442,000
    )
    
    
    (8,527,000
    )Net cash used in investing activities
    
    
    (19,734,000
    )
    
    
    (14,410,000
    )
    
    
    (8,007,000
    )Cash flows from financing activitiesPurchase of stock for treasury
    
    
    (641,000
    )
    
    
    (745,000
    )
    
    
    (3,156,000
    )Repayment of long-term bank debt and other
long-term
obligations
    
    
    (43,679,000
    )
    
    
    (43,260,000
    )
    
    
    (40,619,000
    )Increase in long-term bank debt and other
long-term obligations
    
    
    46,437,000
    
    
    
    50,572,000
    
    
    
    38,740,000Proceeds from exercised stock options
    
    
    
    
    
    
    
    
    
    
    130,000Net cash provided by (used in) financing activities
    
    
    2,117,000
    
    
    
    6,567,000
    
    
    
    (4,905,000
    )Net increase (decrease) in cash
    
    
    2,005,000
    
    
    
    1,801,000
    
    
    
    (599,000
    )Cash and cash equivalents, beginning of year
    
    
    1,886,000
    
    
    
    85,000
    
    
    
    684,000Cash and cash equivalents, end of year
    
    $
    3,891,000
    
    
    $
    1,886,000
    
    
    $
    85,000Supplemental disclosures:Income taxes paid during the year
    
    $
    83,500
    
    
    
    
    
    
    $
    1,200,000Net income tax refunds received during the year
    
    
    
    
    
    $
    745,000
    
    
    
    Interest paid during the year
    
    $
    880,000
    
    
    $
    766,000
    
    
    $
    901,000
 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




---



##### 



PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS  1.
    
    Description of Operations and Significant Accounting PoliciesNature of Operations:PrimeEnergy Corporation (PEC), a Delaware corporation, was organized in
March 1973. PrimeEnergy Management Corporation (PEMC), a wholly-owned
subsidiary, acts as the managing general partner, providing
administration, accounting and tax preparation services for 18 private and
publicly-held limited partnerships and 2 trusts (collectively, the
Partnerships). During the course of 2003 PrimeEnergy dissolved 20
private limited partnerships. 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. Field service revenues and the
administrative overhead fees earned as operator are reported as District
operating income on the consolidated statement of operations. During 2003
PEC acquired a sixty percent interest in F-W Oil Exploration LLC, (FW),
which ownes and operates properties in the Gulf of Mexico. PrimeEnergy
Corporation and its subsidiaries are herein referred to as the Company.The Company is engaged in the development, acquisition and production of
oil and natural gas properties. The Company owns leasehold, mineral and
royalty interests in producing and non-producing oil and gas properties
across the 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 re-working operations, both in connection with the
Companys activities and providing contract services for third parties.
The Company is publicly traded on the NASDAQ under the symbol PNRG.The markets for the Companys products are highly competitive, as oil and
gas are commodity products and prices depend upon numerous factors beyond
the control of the Company, such as economic, political and regulatory
developments and competition from alternative energy sources.Principles of Consolidation:The consolidated financial statements include the accounts of
PrimeEnergy Corporation, 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.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




---



##### 



PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS  Property and EquipmentThe 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 our 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.Our 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.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




---



##### 



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.Recently Issued Accounting Standards:In July 2001, the Financial Accounting Standards Board (FASB)
issued SFAS No. 141, Business Combinations. SFAS No. 141 is intended to
improve the transparency of the accounting and reporting for business
combinations by requiring that all business combinations be accounted for
under a single method - the purchase method. SFAS 141 is effective for all
transactions completed after June 30, 2001, except transactions using the
pooling-of-interests method that were initiated prior to July 1, 2001. The
adoption of SFAS 141 did not have an impact on the Companys consolidated
financial statements. F-10




---



##### 



PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS  In July 2001, the FASB issued SFAS No. 142, Goodwill and Other
Intangible Assets. This statement applies to intangibles and goodwill
acquired after June 30, 2001, as well as goodwill and intangibles
previously acquired. Under this statement, goodwill as well as other
intangibles determined to have an infinite life will no longer be
amortized; however, these assets will be reviewed for impairment on a
periodic basis. The adoption of SFAS 142 did not have an impact on the
Companys consolidated financial statements.In August 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligations. SFAS No. 143 requires the fair value of a
liability for an asset retirement obligation to be recognized in the
period in which it is incurred if a reasonable estimate of fair value can
be made. The associated asset retirement costs are capitalized as part of
the carrying amount of the long-lived asset. SFAS No. 143 is effective for
fiscal years beginning after June 15, 2002. The adoption of SFAS no 143
did not have a material effect on the Companys financial statements as of
December 31, 2003.In October 2001, the FASB issued SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets. SFAS No. 144 requires that
long-lived assets be measured at the lower of carrying amount or fair
value less cost to sell, whether reported in continuing operations or in
discontinued operations. Therefore, discontinued operations will no longer
be measured at net realizable value or include amounts for operating
losses that have not yet occurred. SFAS No. 144 is effective for financial
statements issued for fiscal years beginning after December 15, 2001 and
generally, is to be applied prospectively. The adoption of SFAS 144 did
not have an impact on the Companys consolidated financial statements.

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. F-11




---



##### 



PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to 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.2.
    
    Significant Acquisitions and DispositionsAs 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 $695,673 in 2003, $1,203,500 in 2002 and $545,000 in
2001. 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.F-W Oil Exploration L.L.C. Acquisition: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 ReceivableAccounts receivable at December 31, 2003 and 2002 consisted of the
following: December 31,2003
    
    2002Joint interest billing
    
    $
    1,174,000
    
    
    $
    571,000Trade receivables
    
    
    1,607,000
    
    
    
    1,243,000Oil and gas sales
    
    
    3,878,000
    
    
    
    2,070,000Other
    
    
    906,000
    
    
    
    561,0007,565,000
    
    
    
    4,445,000Less, allowance for doubtful accounts
    
    
    (457,000
    )
    
    
    (319,000
    )Total
    
    $
    7,108,000
    
    
    $
    4,126,000
 F-12




---



##### 



PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS  4.
    
    Other Current AssetsOther current assets at December 31, 2003 and 2002 consisted of the
following: December 31,2003
    
    2002Tax overpayments
    
    $
    
    
    
    $
    73,000Field service inventory
    
    
    278,000
    
    
    
    249,000Other
    
    
    19,000
    
    
    
    Total
    
    $
    297,000
    
    
    $
    322,000
  5.
    
    Long-Term Bank DebtAs 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 current borrowing base is $25 million and includes a Term Loan of $4
million. The Term Loan will be paid back in monthly installments of
$66,667 beginning January 2003 and continuing until December 19, 2004
when such Term Loan shall be paid in full. 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
periodThe Company had been party to a series of credit agreements with its
former lender or its predecessors since 1983. The agreement, entered into
in April 1995, provided for borrowings under a Master Note. Advances
under the agreement, as amended, were limited to the borrowing base as
defined in the agreement and re-determined by the lender on a semi-annual
basis. Since the beginning of 2000, the borrowing base ranged from $20
million to $23.7 million. The credit agreement provided for interest on
outstanding borrowings at the banks base rate, as defined, payable
monthly, or at rates ranging from 1 1/2% to 2% over the London
Inter-Bank Offered Rate (LIBO rate) depending upon the Companys
utilization of the available line of credit, payable at the end of the
applicable interest period. This credit agreement was assigned to the
Companys primary lender effective December 2002.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, with an
additional $133,333 and $500,000 available. As of December 31, 2003
$24,280,000 of total bank debt was paying interest at LIBO rate option per the
credit agreement.

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 with no
additional availability. 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 $28,800,000.


As of February 2004 the agreement was amended in conjunction with the
semi-annual borrowing base determination. Pursuant to this amendment
the borrowing base including the Term Loan was increased to
$47,066,662 and the maturities were extended to March 31, 2007.
Advances to FW and FWs liability to the lender in accordance with this amendment are limited to $10,120,000.


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




---



##### 



PRIMEENERGY CORPORATION and SUBSIDIARIES 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
    
    Leases2004
    
    
    245,000
    
    
    
    26,0002005
    
    
    336,000
    
    
    
    11,0002006
    
    
    337,000
    
    
    
    2007
    
    
    189,000
    
    
    
    Thereafter
    
    
    370,000
    
    
    
    Total minimum payments
    
    $
    1,477,000
    
    
    
    37,000Less imputed interest
    
    
    
    
    
    
    (1,000
    )Present value of minimum
Lease payments
    
    
    
    
    
    $
    36,000
 7. Contingent Liabilities The Company, as managing general partner of the affiliated Partnerships,
is responsible for all Partnership activities, including the review and
analysis of oil and gas properties for acquisition, the drilling of
development wells and the production and sale of oil and gas from
productive wells. The Company also provides the administration,
accounting and tax preparation work for the Partnerships, and is liable
for all debts and liabilities of the affiliated Partnerships, to the
extent that the assets of a given limited Partnership are not sufficient
to satisfy its obligations. PrimeEnergy
Corporation and each of its subsidiaries are borrowers under a credit
agreement with the Companys lender, as more fully described in
Footnote 5. The pledge of properties owned by FW is limited to
the amounts available to FW. The Companys assets are pledged as
security under that agreement to all outstanding borrowings including
FWs. The lender reviews the assets of FW in conjunction with the
semi-annual borrowing base determinations and limits amounts
available to FW to a level consistent with the ability of FW to repay
such borrowings. The Company is liable to the extent that the assets
of FW are not sufficient to satisfy FWs obligations under the
agreement. Based on the borrowing base determination as of February
2004 the maximum additional amount the Company would be committed to
pay is $4,048,000. The Company is subject to environmental laws and regulations. Management
believes that future expenses, before recoveries from third parties, if
any, will not have a material effect on the Companys financial condition.
This opinion is based on expenses incurred to date for remediation and
compliance with laws and regulations which have not been material to the
Companys results of operations. As a general partner, the Company is committed to offer to purchase the
limited partners interest in certain of its managed Partnerships at
various annual intervals. Under the terms of a partnership agreement, the
Company is not obligated to purchase an amount greater than 10% of the
total partnership interest outstanding. In addition, the Company will be
obligated to purchase interests tendered by the limited partners only to
the extent of one hundred fifty percent of the revenues received by it
from such partnership in the previous year. Purchase prices are based
upon annual reserve reports of independent petroleum engineering firms
discounted by a risk factor. Based upon historical production rates and
prices, management estimates that if all such offers were to be accepted,
the maximum annual future purchase commitment would be approximately
$500,000. The Company owns approximately a 27% interest in a limited partnership
which owns a shopping center in Alabama. The Company is a guarantor on a
mortgage secured by the shopping center. The Company believes the cash
flow from the center is sufficient to service the mortgage. The market
value of the center is currently substantially higher than the balance
owed on the mortgage. If the partnership were unable to pay its
obligations under the mortgage agreement, the maximum amount the Company
is committed to pay is $300,000. F-14




---



##### 



PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS, 8. Stock Options and Other Compensation In May 1989, non-statutory stock options were granted by the Company to
four key executive officers for the purchase of shares of common stock.
At December 31, 2003 and 2002, options on 767,500 shares were outstanding
and exercisable at prices ranging from $1.00 to $1.25. On January 27, 1983, the Company adopted the 1983 Incentive Stock Option
Plan. At December 31, 2000, options on 87,000 shares were exercisable at
$1.50 per share. During July 2001, all outstanding options under this
plan were exercised. PEMC has a marketing agreement with its President to provide assistance
and advice to PEMC in connection with the organization and marketing of
oil and gas partnerships and joint ventures and other investment
vehicles of which PEMC is to serve as general or managing partner. The
Company had a similar agreement with its former Chairman. Although that
agreement expired, the former Chairman was still entitled to receive
certain payments relating to partnerships formed during the time the
agreement was in effect. In October 2002, the President and the former
Chairman sold and assigned all rights, title and interest related to
certain Partnerships formed under these marketing agreements to the
Company. The President is still entitled to a percentage of the Companys
carried interest depending on total capital raised and annual performance
of other Partnerships and joint ventures. 9. Income Taxes The components of the provision for income taxes for the years ended
December 31, 2003, 2002 and 2001 are as follows: 2003
    
    2002
    
    2001Federal:Current
    
    $
    696,000
    
    
    $
    95,000
    
    
    $
    25,000Deferred
    
    
    1,460,000
    
    
    
    216,000
    
    
    
    1,500,000State:Current
    
    
    171,000
    
    
    
    104,000
    
    
    
    13,000Deferred
    
    
    119,000
    
    
    
    28,000
    
    
    
    183,000Total
    
    $
    2,446,000
    
    
    $
    443,000
    
    
    $
    1,721,000
 F-15




---



##### 



PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued The components of net deferred tax assets (liabilities) are as follows: December 31,
    
    December 31,2003
    
    2002Current assets:Compensation and benefits
    
    $
    196,000
    
    
    $
    184,000Allowance for doubtful accounts
    
    
    178,000
    
    
    
    125,000374,000
    
    
    
    309,000Noncurrent assets:Depreciation
    
    
    163,000
    
    
    
    485,000Due from related parties reserve
    
    
    
    
    
    
    312,000Percentage depletion carryforwards
    
    
    
    
    
    
    297,000Alternative minimum tax credits
    
    
    393,000
    
    
    
    1,040,000556,000
    
    
    
    2,134,000Noncurrent liabilities:Basis differences relating to limited partnerships
    
    
    1,351,000
    
    
    
    1,211,000Depletion
    
    
    3,442,000
    
    
    
    3,515,0004,793,000
    
    
    
    4,726,000Net deferred tax liabilities:
    
    $
    3,863,000
    
    
    $
    2,283,000
 The total provision for income taxes for the years ended December 31,
2003, 2002 and 2001 varies from the federal statutory tax rate as a result
of the following: December 31,
    
    December 31,
    
    December 31,2003
    
    2002
    
    2001Expected tax expense
    
    $
    2,770,000
    
    
    $
    748,000
    
    
    $
    2,426,000State income tax, net of federal benefit
    
    
    195,000
    
    
    
    132,000
    
    
    
    196,000Credit for producing fuel from a
non-conventional source
    
    
    
    
    
    
    (134,000
    )
    
    
    (299,000
    )Percentage depletion
    
    
    (400,000
    )
    
    
    (303,000
    )
    
    
    (602,000
    )Other
    
    
    (119,000
    )
    
    
    
    
    
    
    Tax expense
    
    $
    2,446,000
    
    
    $
    443,000
    
    
    $
    1,721,000
 F-16




---



##### 



PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued 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 have either been 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. The company expects to
utilize approximately $553,000 of the alternative minimum tax credits when
it files its return for 2003, and have a carry forward of $393,000 to the
2004 tax year. 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 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. 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 2003. Oil Purchasers:
    
    
    
    Gas Purchasers:Texon Distributing L.P.
    
    15.80%
    
    Unimark LLC
    
    21.68%Plains All American Inc.
    
    11.52%
    
    El Paso Industrial Energy
    
    10.60%
 Although there are no long-term oil and gas purchasing agreements
with these purchasers, the Company believes that they will continue to
purchase its oil and gas products and, if not, could be replaced by other
purchasers. 11. Related Party Transactions PEMC 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 $695,673 in 2003, $1,203,500 in 2002 and $545,000 in 2001. During 2003
the Company dissolved 20 of the 40 partnerships in which the Company
owns General and Limited partnership interests. In conjunction with
the liquidation of these partnerships the Company offset the Due from
Affiliates account for its share of the remaining Partnerships assets and liabilities, net of the $800,000 previously reserved. The Partnership agreements allow PEMC to receive management fees for various services to the Partnerships as well as a reimbursement for property acquisition and development costs incurred on behalf of the Partnerships and general and administrative overhead, which is reported in the statements of operations as administrative revenue. Due to
related parties at December 31, 2003 and 2002 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 $933,000 and $1,485,000 at December 31, 2003 and 2002, respectively. Receivables from related parties consist of reimbursable general and administrative costs, lease operating expenses and reimbursements for property acquisitions, development, and related costs. F-17




---



##### 



PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued Treasury stock purchases in 2003 and 2002 included shares acquired from
related parties. Purchases from related parties include a total of
37,350 shares purchased for a total consideration of $398,838 in
2003, and 49,267 shares purchased for a total consideration of $394,000 in 2002. 12. Restricted Cash and Cash Equivalents Restricted cash and cash equivalents includes $1,479,000 and $750,000 at
December 31, 2003 and 2002, respectively, of cash primarily pertaining to
unclaimed royalty payments. There were corresponding accounts payable
recorded at December 31, 2003 and 2002 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 $259,000
and $261,000 in 2003 and 2002, 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, 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-18




---



##### 



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
 Year ended December 31, 2001Number of
    
    Per shareNet Income
    
    Shares
    
    AmountNet income per common share
    
    $
    5,413,000
    
    
    
    3,882,721
    
    
    $
    1.39Effect of dilutive securities:Options
    
    
    
    
    
    
    709,384Diluted net income per common share
    
    $
    5,413,000
    
    
    
    4,592,105
    
    
    $
    1.18
 15. Selected Quarterly Financial Information (Unaudited) December
    
    Fourth
    
    Third
    
    Second
    
    First31, 2003
    
    Quarter
    
    Quarter
    
    Quarter
    
    QuarterRevenue
    
    $
    48,428,000
    
    
    $
    13,162,000
    
    
    
    7,709,000
    
    
    
    10,934,000
    
    
    
    11,865,000Operating 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
 December
    
    Fourth
    
    Third
    
    Second
    
    First31, 2002
    
    Quarter
    
    Quarter
    
    Quarter
    
    QuarterRevenue
    
    $
    35,934,000
    
    
    $
    9,764,000
    
    
    
    9,580,000
    
    
    
    8,434,000
    
    
    
    8,155,000Operating income
    
    
    2,168,000
    
    
    
    752,000
    
    
    
    795,000
    
    
    
    593,000
    
    
    
    85,000Net income
    
    
    1,757,000
    
    
    
    585,000
    
    
    
    642,000
    
    
    
    475,000
    
    
    
    70,000Net income per
common share
    
    $
    0.47
    
    
    $
    0.16
    
    
    $
    0.17
    
    
    $
    0.13
    
    
    $
    0.02Diluted net income
per common share
    
    $
    0.40
    
    
    $
    0.13
    
    
    $
    0.15
    
    
    $
    0.11
    
    
    $
    0.02
 F-19




---



##### 



PRIMEENERGY CORPORATION and SUBSIDIARIES SUPPLEMENTARY INFORMATION (Unaudited) F-20




---



##### 



PRIMEENERGY CORPORATION and SUBSIDIARIES CAPITALIZED COSTS RELATING to OIL and GAS PRODUCING ACTIVITIES December 31, 2003, 2002 and 2001 (Unaudited) 2003
    
    2002
    
    2001Developed oil and gas properties
    
    $
    91,012,000
    
    
    $
    74,319,000
    
    
    $
    63,418,000Undeveloped oil and gas properties
    
    
    3,091,000
    
    
    
    1,134,000
    
    
    
    286,00094,103,000
    
    
    
    75,453,000
    
    
    
    63,704,000Accumulated depreciation,
depletion and valuation allowance
    
    
    53,196,000
    
    
    
    46,912,000
    
    
    
    42,924,000Net capitalized costs
    
    $
    40,907,000
    
    
    $
    28,541,000
    
    
    $
    20,780,000
 COSTS INCURRED in OIL and GAS PROPERTY ACQUISITION,
EXPLORATION and DEVELOPMENT ACTIVITIES Years ended December 31, 2003, 2002 and 2001 (Unaudited) 2003
    
    2002
    
    2001Acquisition of PropertiesDeveloped
    
    $
    5,023,000
    
    
    $
    1,668,000
    
    
    $
    316,000Undeveloped
    
    
    873,000
    
    
    
    848,000
    
    
    
    164,000Exploration Costs
    
    
    519,000
    
    
    
    894,000
    
    
    
    509,000Development Costs
    
    
    12,294,000
    
    
    
    8,385,000
    
    
    
    5,661,000
 See accompanying notes to supplementary information. F-21




---



##### 



PRIMEENERGY CORPORATION and SUBSIDIARIES STANDARDIZED MEASURE of DISCOUNTED FUTURE
NET CASH FLOWS RELATING to PROVED OIL and GAS RESERVES Years ended December 31, 2003, 2002 and 2001 (Unaudited) 2003
    
    2002
    
    2001Future cash inflows
    
    $
    302,876,000
    
    
    $
    201,750,000
    
    
    $
    102,916,000Future production and development costs
    
    
    (138,929,000
    )
    
    
    (104,232,000
    )
    
    
    (60,841,000
    )Future income tax expenses
    
    
    (47,696,000
    )
    
    
    (24,230,000
    )
    
    
    (7,930,000
    )Future net cash flows
    
    
    116,251,000
    
    
    
    73,288,000
    
    
    
    34,145,00010% annual discount for estimated timing of cash flow
    
    
    (42,999,000
    )
    
    
    (30,512,000
    )
    
    
    (13,179,000
    )Standardized measure of discounted future net cash
flows
    
    $
    73,252,000
    
    
    $
    42,776,000
    
    
    $
    20,966,000
 See accompanying notes to supplementary information. F-22




---



##### 



PRIMEENERGY CORPORATION and SUBSIDIARIES STANDARDIZED MEASURE of DISCOUNTED FUTURE
NET CASH FLOWS and CHANGES THEREIN RELATING
to PROVED OIL and GAS RESERVES Years ended December 31, 2003, 2002 and 2001 (Unaudited) The following are the principal sources of change in the standardized measure
of discounted future net cash flows during 2003, 2002 and 2001: 2003
    
    2002
    
    2001Sales of oil and gas produced, net of
production costs
    
    $
    (17,072,000
    )
    
    $
    (8,120,000
    )
    
    $
    (11,915,000
    )Net changes in prices and production costs
    
    
    24,732,000
    
    
    
    18,488,000
    
    
    
    (92,118,000
    )Extensions, discoveries and improved
recovery
    
    
    14,133,000
    
    
    
    8,462,000
    
    
    
    3,335,000Revisions of previous quantity estimates
    
    
    2,491,000
    
    
    
    5,192,000
    
    
    
    422,000Reserves purchased, net of development
costs
    
    
    9,667,000
    
    
    
    5,824,000
    
    
    
    1,082,000Net change in development costs
    
    
    8,217,000
    
    
    
    (311,000
    )
    
    
    (594,000
    )Accretion of discount
    
    
    4,278,000
    
    
    
    2,097,000
    
    
    
    8,001,000Net change in income taxes
    
    
    (15,705,000
    )
    
    
    (9,809,000
    )
    
    
    33,127,000Other
    
    
    (265,000
    )
    
    
    (13,000
    )
    
    
    (384,000
    )Net change
    
    
    30,476,000
    
    
    
    21,810,000
    
    
    
    (59,044,000
    )Standardized measure of discounted future
net cash flow:Beginning of year
    
    
    42,776,000
    
    
    
    20,966,000
    
    
    
    80,010,000End of year
    
    $
    73,252,000
    
    
    
    42,776,000
    
    
    $
    20,966,000
 See accompanying notes to supplementary information F-23




---



##### 



PRIMEENERGY CORPORATION and SUBSIDIARIES RESERVE QUANTITY INFORMATION Years ended December 31, 2003, 2002 and 2001 (Unaudited) 2003
    
    2002
    
    2001Gas
    
    Oil
    
    Gas
    
    Oil
    
    Gas
    
    Oil(Mcf)
    
    (bbls.)
    
    (Mcf)
    
    (bbls.)
    
    (Mcf)
    
    (bbls.)Proved developed and
undeveloped reserves:Beginning of year
    
    
    29,917,000
    
    
    
    2,319,000
    
    
    
    24,719,000
    
    
    
    1,996,000
    
    
    
    27,029,000
    
    
    
    2,362,000Extensions, discoveries
and improved recovery
    
    
    4,245,000
    
    
    
    541,000
    
    
    
    3,011,000
    
    
    
    273,000
    
    
    
    2,764,000
    
    
    
    136,000Revisions of previous
estimates
    
    
    263,000
    
    
    
    171,000
    
    
    
    2,798,000
    
    
    
    198,000
    
    
    
    (2,458,000
    )
    
    
    (307,000
    )Purchases
    
    
    8,571,000
    
    
    
    243,000
    
    
    
    2,929,000
    
    
    
    173,000
    
    
    
    1,148,000
    
    
    
    111,000Production
    
    
    (3,991,000
    )
    
    
    (370,000
    )
    
    
    (3,540,000
    )
    
    
    (321,000
    )
    
    
    (3,764,000
    )
    
    
    (306,000
    )End of year
    
    
    39,005,000
    
    
    
    2,905,000
    
    
    
    29,917,000
    
    
    
    2,319,000
    
    
    
    24,719,000
    
    
    
    1,996,000Proved developed reserves
    
    
    34,045,000
    
    
    
    2,865,000
    
    
    
    29,917,000
    
    
    
    2,319,000
    
    
    
    24,226,000
    
    
    
    1,996,000
 See accompanying notes to supplementary information F-24




---



##### 



PRIMEENERGY CORPORATION and SUBSIDIARIES RESULTS of OPERATIONS from OIL and GAS PRODUCING ACTIVITIES Years ended December 31, 2003, 2002 and 2001 (Unaudited) 2003
    
    2002
    
    2001Revenue:Oil and gas sales
    
    $
    29,855,000
    
    
    $
    18,330,000
    
    
    $
    22,998,000Costs and expenses:Lease operating expense
    
    
    12,783,000
    
    
    
    10,210,000
    
    
    
    11,083,000Exploration costs
    
    
    519,000
    
    
    
    894,000
    
    
    
    509,000Depreciation and depletion
    
    
    6,283,000
    
    
    
    3,988,000
    
    
    
    4,522,000Write down of oil and gas properties
    
    
    
    
    
    
    
    
    
    
    753,000Income tax expense
    
    
    2,446,000
    
    
    
    443,000
    
    
    
    1,721,00022,031,000
    
    
    
    15,535,000
    
    
    
    18,588,000Results of operations from producing activities
    
    $
    7,824,000
    
    
    $
    2,735,000
    
    
    $
    4,410,000(excluding corporate overhead and interest costs)
 See accompanying notes to supplementary information F-25




---



##### 



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 flows relating oil and
gas reserves and the changes of standardized measure of discounted future
net cash flows relating to proved oil and gas reserves were prepared in
accordance with the provisions of SFAS 69.Future cash inflows are computed as described in Note 2 by applying
current prices to year-end quantities of proved reserves.Future production and development costs are computed estimating the
expenditures to be incurred in developing and producing the oil and gas
reserves at year-end, based on year-end costs and assuming continuation of
existing economic conditions.Future income tax expenses are calculated by applying the year-end U.S.
tax rate to future pre-tax cash inflows relating to proved oil and gas
reserves, less the tax basis of properties involved. Future income tax
expenses give effect to permanent differences and tax credits and
allowances relating to the proved oil and gas reserves.Future net cash flows are discounted at a rate of 10% annually (pursuant
to SFAS 69) to derive the standardized measure of discounted future net
cash flows. This calculation does not necessarily represent an estimate
of fair market value or the present value of such cash flows since future
prices and costs can vary substantially from year-end and the use of a 10%
discount figure is arbitrary. F-26