PRIMEENERGY CORP - 10-K Annual Report

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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

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FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ______TO ______

COMMISSION FILE NUMBER 0-7406

PRIMEENERGY CORPORATION
(Exact name of registrant as specified in its charter)

DELAWARE 84-0637348
(state or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

ONE LANDMARK SQUARE 06901
STAMFORD, CONNECTICUT (Zip Code)
(Address of principal executive offices)

Registrant's telephone number, including area code: (203) 358-5700

Securities registered pursuant to Section 12(b) of the Act:
NONE

Securities registered pursuant to Section 12(g) of the Act:
COMMON STOCK, PAR VALUE $.10 PER SHARE
(Title of Class)

Indicate whether Registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding months (or for such shorter period that the Registrant was required to
file such reports), and (2) has been subject to such filing requirements for the
past 90 days.

Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-B is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]

The Registrant's revenues for its most recent fiscal year were $42,408,000.

The aggregate market value of the voting stock of the Registrant held by
non-affiliates, computed on the average bid and asked prices of such stock in
the over-the-counter market, as of March 25, 2002, was $6,816,007.

The number of shares outstanding of each class of the Registrant's Common
Stock as of March 25, 2002 was: Common Stock, $0.10 par value, 3,763,151.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant's proxy statement to be furnished to
stockholders in connection with its Annual Meeting of Stockholders to be held in
June, 2002, are incorporated by reference in Part III hereof.

Transitional Small business Disclosure Format (check one) Yes No X
--- ---

PRIMEENERGY CORPORATION

FORM 10-K ANNUAL REPORT
FOR THE FISCAL YEAR ENDED
DECEMBER 31, 2001

PART I

ITEM 1. DESCRIPTION OF BUSINESS.

GENERAL

This report contains forward-looking statements that are based on
management's current expectations, estimates and projections. Words such as
"expects," "anticipates," "intends," "plans," "believes," "projects" and
"estimates," and variations of such words and similar expressions are intended
to identify such forward-looking statements. These statements constitute
"forward-looking statements" within the meaning of Section 27A of the Securities
Act of 1933, and are subject to the safe harbors created thereby. These
statements are not guarantees of future performance and involve risks and
uncertainties and are based on a number of assumptions that could ultimately
prove inaccurate and, therefore, there can be no assurance that they will prove
to be accurate. Actual results and outcomes may vary materially from what is
expressed or forecast in such statements due to various risks and uncertainties.
These risks and uncertainties include, among other things, volatility of oil and
gas prices, competition, risks inherent in the Company's oil and gas operations,
the inexact nature of interpretation of seismic and other geological and
geophysical data, imprecision of reserve estimates, the Company's ability to
replace and expand oil and gas reserves, and such other risks and uncertainties
described from time to time in the Company's periodic reports and filings with
the Securities and Exchange Commission. Accordingly, stockholders and potential
investors are cautioned that certain events or circumstances could cause actual
results to differ materially from those projected.

PrimeEnergy Corporation (the "Company") was organized in March, 1973,
under the laws of the State of Delaware.

The Company is engaged generally in the oil and gas business through
the acquisition, exploration, development, and production of crude oil and
natural gas. The Company's properties are located primarily in Texas, Oklahoma,
West Virginia and Louisiana. The Company's wholly-owned subsidiary, PrimeEnergy
Management Corporation ("PEMC"), acts as the managing general partner in 45 oil
and gas limited partnerships (the "Partnerships") of which four are publicly
held, and acts as the managing trustee of two asset and income business trusts
("the Trusts"). The Company, through its wholly-owned subsidiaries Prime
Operating Company, Southwest Oilfield Construction Company, Eastern Oil Well
Service Company and EOWS Midland Company, acts as operator and provides well
servicing support operations for many of the oil and gas wells in which the
Partnerships, the Trusts and the Company have an interest, and also for third
parties, primarily in Texas, Oklahoma and West Virginia. The Company is also
active in the acquisition of producing oil and gas properties through joint
ventures with industry partners and private investors.

THE PARTNERSHIPS AND TRUSTS

A substantial portion of the assets and revenues of PEMC are derived
from the interest of PEMC in the oil and gas properties acquired by the
Partnerships and Trusts. As the managing general partner in each of the
Partnerships and managing trustee of the Trusts, PEMC receives approximately
from 5% to 15% of the net revenues of each Partnership and Trust as a carried
interest in the Partnership's and Trust's properties. The Company has also
repurchased substantial limited partner interests in these entities.

Since 1975, PEMC has sponsored a total of 59 limited partnerships, 22
of which were offered publicly and 37 of which were offered in private
placements and two Delaware business trusts, both of which were offered
publicly. The aggregate number of limited partners in the Partnerships and
beneficial owners of the Trusts now administered by PEMC is approximately 4,800.
The Partnership and Trust interests were sold by broker-dealers which are
members of the National Association of Securities Dealers, Inc. through a
managing dealer. The total funds contributed to the Partnerships and Trusts was
about $157,550,000.

A significant portion of the Company's business is conducted through
the Partnerships and Trusts, either through its ownership of interests in
various properties derived through the Partnerships and Trusts, or as operator
of, and a provider of oilfield services to, oil and gas wells in which the
Partnerships and Trusts have interests.

2

PEMC, as managing general partner of the Partnerships and managing
trustee of the Trusts, is responsible for all Partnership and Trust activities,
including the review and analysis of oil and gas properties for acquisition, the
drilling of development wells and the production and sale of oil and gas from
productive wells. PEMC also provides administration, accounting and tax
preparation for the Partnerships and Trusts. PEMC is liable for all debts and
liabilities of the Partnerships and Trusts, to the extent that the assets of a
given limited partnership or trust are not sufficient to satisfy its
obligations.

JOINT VENTURES

PEMC organizes and the Company participates in various joint ventures
formed for the purpose of acquiring and developing oil and gas assets. The
Company receives varying interests in the net revenues of each joint venture as
a carried interest in the joint venture properties. The Company's participation
in the joint ventures varies from none to approximately 78%. The Company's
carried interest is generally 10% of funds contributed by outside investors.
Since 1987, our joint venture partners have invested $27.6 million with the
Company.

WELL OPERATIONS

The Company's operations are conducted through a central office in
Houston, Texas, and district offices in Houston and Midland, Texas, Oklahoma
City, Oklahoma, and Charleston, West Virginia. The Company currently operates
1,550 oil and gas wells, 411 through the Houston office, 181 through the Midland
office, 463 through the Oklahoma City office and 495 through the Charleston,
West Virginia office. Substantially all of the wells operated by the Company are
wells in which the Company, the Partnerships, the Trusts or our joint venture
partners have an interest.

The Company operates wells pursuant to operating agreements which
govern the relationship between the Company as operator and the other owners of
working interests in the properties, including the Partnerships, Trusts and
joint venture participants. For each operated well, the Company receives monthly
fees that are competitive in the areas of operations and also is reimbursed for
expenses incurred in connection with well operations.

EXPLORATION, DEVELOPMENT AND ACQUISITION ACTIVITIES; OTHER MATTERS

The Company continues to explore opportunities for the acquisition and
development of producing oil and gas properties, and will continue to engage in
exploratory operations and development drilling of properties in which it has an
interest. The Company attempts to assume the position of operator in all
acquisitions of producing properties.

RECENT ACTIVITIES

The Company participated in, and was operator of, four wells drilled on
the East Wakita prospect in Oklahoma during 2001. Three of these wells were
successfully completed, while 1 was a dry hole. Two additional wells were
successfully completed on the prospect in the first quarter of 2002.

The Company participated in, and was the operator of, two wells drilled
on the DSR prospect in Oklahoma during 2001. One of these wells was successfully
completed and one has been temporarily abandoned pending further evaluation.

The Company participated in, and was the operator of, two wells that
were successfully completed in the Weatherby field in Reagan County, Texas.

The Company successfully completed eleven wells in Upton County, Texas
during 2001.

The Company participated in, and was the operator of, a successfully
completed well on the Cadiz prospect in Bee County, Texas in March of 2001.

In March of 2001, the Company successfully reentered and recompleted a
well in the Tuleta East field in Bee County, Texas.

The Company is committed to offer to repurchase the interests of the
limited partners and trust unitholders in certain of the Partnerships, as
described more fully in Note 7 of the Financial Statements. During 2001, the
Company purchased such interests in an amount totaling $545,000.

3

The Company will continue to evaluate prospects for leasehold
acquisitions and for exploration and development operations in areas in which it
owns interests and is actively pursuing the acquisition of producing properties.

In order to diversify and broaden its asset base, the Company will
consider acquiring the assets or stock in other entities and companies in the
oil and gas business. The main objective of the Company in making any such
acquisitions will be to acquire income producing assets so as to increase the
Company's net worth and increase the Company's oil and gas reserve base.

The Company presently owns producing and non-producing properties
located primarily in Texas, Oklahoma, West Virginia and Louisiana, and owns a
substantial amount of well servicing equipment. The Company does not own any
refinery or marketing facilities, and does not currently own or lease any bulk
storage facilities or pipelines other than adjacent to and used in connection
with producing wells and the interests in certain gas gathering systems. All of
the Company's oil and gas properties and interests are located in the
continental United States.

In the past, the supply of gas has exceeded demand on a cyclical basis,
and the Company is subject to a combination of shut-in and/or reduced takes of
gas production during summer months. Prolonged shut-ins could result in reduced
field operating income from properties in which the Company acts as operator.

Exploration for oil and gas requires substantial expenditures
particularly in exploratory drilling in undeveloped areas, or "wildcat
drilling." As is customary in the oil and gas industry, substantially all of the
Company's exploration and development activities are conducted through joint
drilling and operating agreements with others engaged in the oil and gas
business.

Summaries of the Company's oil and gas drilling activities, oil and gas
production, and undeveloped leasehold, mineral and royalty interests are set
forth under Item 2., "Description of Property," below. Summaries of the
Company's oil and gas reserves, future net revenue and present value of future
net revenue are also set forth under Item 2., "Description of Property -
Reserves" below.

REGULATION

The Company's oil and gas operations are subject to a wide variety of
federal, state and local regulations. Administrative agencies in such
jurisdictions may promulgate and enforce rules and regulations relating to,
among other things, drilling and spacing of oil and gas wells, production rates,
prevention of waste, conservation of natural gas and oil, pollution control, and
various other matters, all of which may affect the Company's future operations
and production of oil and gas. The Company's natural gas production and prices
received for natural gas are regulated by the Federal Energy Regulatory
Commission ("FERC"), the Natural Gas Act of 1938 ("NGA") and the Natural Gas
Policy Act of 1978 ("NGPA") and various state regulations. The Company is also
subject to state drilling and proration regulations affecting its drilling
operations and production rates.

Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. The Company cannot predict when or if any such
proposals might become effective, or their effect, if any, on the Company's
operations. The natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less stringent regulatory
approach recently pursued by the FERC and Congress will continue indefinitely
into the future.

In the event the Company conducts operations on federal, state or
Indian oil and gas leases, such operations must comply with numerous regulatory
restrictions, including various nondiscrimination statutes, and certain of such
operations must be conducted pursuant to certain on-site security regulations
and other appropriate permits issued by the Bureau of Land Management ("BLM") or
Minerals Management Service ("MMS") or other appropriate federal or state
agencies.

The Mineral Leasing Act of 1930 ("Mineral Act") prohibits direct or
indirect ownership of any interest in federal onshore oil and gas leases by a
foreign citizen of a country that denies "similar or like privileges' to
citizens of the United States. Such restrictions on citizens of a
"non-reciprocal" country include ownership or holding or controlling stock in a
corporation that holds a federal onshore oil and gas lease. If this restriction
is violated, the corporation's lease can be canceled in a proceeding instituted
by the United States Attorney General. Although the regulations of the BLM
(which administers the Mineral Act) provide for agency designations of
non-reciprocal countries, there are presently no such designations in effect.
The Company owns interests in federal onshore oil and gas leases. It is possible
that Common Stock could be acquired by citizens of foreign countries, which at
some time in the future might be determined to be non-reciprocal under the
Mineral Act.

4

TAXATION

The Company's oil and gas operations are affected by federal income tax
laws applicable to the petroleum industry. The Company is permitted to deduct
currently, rather than capitalize, intangible drilling and development costs
incurred or borne by it. As an independent producer, the Company is also
entitled to a deduction for percentage depletion with respect to the first 1,000
barrels per day of domestic crude oil (and/or equivalent units of domestic
natural gas) produced by it, if such percentage depletion exceeds cost
depletion. Generally, this deduction is computed based upon the lesser of 100%
of the net income, or 15% of the gross income from a property, without reference
to the basis in the property. The amount of the percentage depletion deduction
so computed which may be deducted in any given year is limited to 65% of taxable
income. Any percentage depletion deduction disallowed due to the 65% of taxable
income test may be carried forward indefinitely.

The Company is entitled to credits for producing fuel from a
non-conventional source under Section 29 of the Internal Revenue Code, primarily
from certain of the Company's operations in West Virginia.

See Notes 1 and 9 to the consolidated financial statements included in
this Report for a discussion of accounting for income taxes and availability of
federal tax net operating loss carryforwards and alternative minimum tax credit
carryforwards.

COMPETITION AND MARKETS

The business of acquiring producing properties and non-producing leases
suitable for exploration and development is highly competitive. Competitors of
the Company in its efforts to acquire both producing and non-producing
properties include oil and gas companies, independent concerns, income programs
and individual producers and operators, many of which have financial resources,
staffs and facilities substantially greater than those available to the Company.
Furthermore, domestic producers of oil and gas must not only compete with each
other in marketing their output, but must also compete with producers of
imported oil and gas and alternative energy sources such as coal, nuclear power
and hydroelectric power. Competition among petroleum companies for favorable oil
and gas properties and leases can be expected to increase.

The availability of a ready market for any oil and gas produced by the
Company at acceptable prices per unit of production will depend upon numerous
factors beyond the control of the Company, including the extent of domestic
production and importation of oil and gas, the proximity of the Company's
producing properties to gas pipelines and the availability and capacity of such
pipelines, the marketing of other competitive fuels, fluctuation in demand,
governmental regulation of production, refining, transportation and sales,
general national and worldwide economic conditions, and use and allocation of
oil and gas and their substitute fuels. There is no assurance that the Company
will be able to market all of the oil or gas produced by it or that favorable
prices can be obtained for the oil and gas production.

Listed below are the percent of the Company's total oil and gas sales
made to each of the customers whose purchases represented more than 10% of the
Company's oil and gas sales.

Texon Distributing L.P. 19.70%
Unimark LLC 13.79%

Although there are no long-term purchasing agreements with these
purchasers, the Company believes that they will continue to purchase its oil and
gas products and, if not, could be replaced by other purchasers.

ENVIRONMENTAL MATTERS

Over the past 30 years, the petroleum industry has been affected by a
wide variety of environmental issues. Throughout the 1970's and 1980's federal
and state environmental regulations have been enacted that affect all aspects of
the Company's operations. These regulations have primarily focused on correcting
existing environmental concerns and implementing preventive controls to reduce
future pollution.

The Company's activities are subject to existing federal, state and
local laws and regulations governing environmental quality and pollution
control. It is anticipated that, absent the occurrence of an extraordinary
event, compliance with existing federal, state and local laws, rules and
regulations regulating the release of materials in the environment or otherwise
relating to the protection of the environment will not have a material effect
upon the operations, capital expenditures, earnings or the competitive position
of the Company. The Company cannot predict what effect additional regulation or
legislation, enforcement policies thereunder, and claims for damages to
property, employees, other persons and the environment resulting from the
Company's operations or ownership of its property could have on its activities.

5

Activities of the Company with respect to oil and gas facilities,
including the operation and construction of pipelines, plants and other
facilities for transporting, processing, treating or storing oil and gas and
other products, are subject to stringent environmental regulation by state and
federal authorities including the Environmental Protection Agency ("EPA"). Such
regulation can increase the cost of planning, designing, installing and
operating such facilities. In most instances, the regulatory requirements relate
to water and air pollution control measures. Although the Company believes that
compliance with environmental regulations will not have a material adverse
effect on it, risks of substantial costs and liabilities are inherent in oil and
gas facility operations, and there can be no assurance that significant costs
and liabilities will not be incurred. Moreover, it is possible that other
developments, such as stricter environmental laws and regulations, and claims
for damages to property or persons resulting from operation of oil and gas
facilities, would result in substantial costs and liabilities to the Company.

The Company currently owns or leases, and has in the past owned or
leased, numerous properties that have been used for production of oil and gas
for many years. Although the Company has utilized operating and disposal
practices that were standard in the industry at the time, hydrocarbons or other
wastes may have been disposed of or released on or under the properties owned or
leased by the Company. In addition, many of these properties have been operated
by third parties over whom the Company had no control as to such entities'
treatment of hydrocarbons or other wastes and the manner in which such
substances may have been disposed of or released. State and federal laws
applicable to oil and gas wastes and properties have gradually become stricter.
Under these new laws, the Company could be required to remove or remediate
previously disposed wastes (including wastes disposed of or released by prior
owners or operators) or property contamination (including groundwater
contamination) or to perform remedial plugging operations to prevent future
contamination.

The Company may generate wastes, including hazardous wastes, that are
subject to the Federal Resource Conservation and Recovery Act and comparable
state statutes. The EPA has limited the disposal options for certain hazardous
wastes and is considering the adoption of stricter disposal standards for
non-hazardous wastes. Furthermore, certain wastes generated by the Company's oil
and gas operations that are currently exempt from treatment as "hazardous
wastes" may in the future be designated as "hazardous wastes," and therefore be
subject to more rigorous and costly operating and disposal requirements.

In addition, legislation has been proposed in Congress from time to
time that would reclassify certain oil and gas exploration and production wastes
as "hazardous wastes," which would make the reclassified wastes subject to much
more stringent handling, disposal and clean-up requirements. If such legislation
were to be enacted, it could have a significant impact on the operating costs of
the Company, as well as the oil and gas industry in general. Initiatives to
further regulate the disposal of oil and gas wastes are also pending in certain
states, and these various initiatives could have a similar impact on the
Company.

The Federal Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "Superfund" law, imposes joint and
several liability, without regard to fault or the legality of the original
conduct, on certain classes of persons with respect to the release of a
"hazardous substance" into the environment. These persons include the current
owner and operator of a site and persons that disposed of or arranged for the
disposal of the hazardous substances found at a site. CERCLA also authorizes the
EPA and, in some cases, third parties to take actions in response to threats to
the public health or the environment and to seek to recover from the responsible
classes of persons the costs of such action. In the course of its operations,
the Company may have generated and may generate wastes that fall within CERCLA'S
definition of "hazardous substances." The Company may also be an owner of sites
on which "hazardous substances" have been released by previous owners or
operators. The Company may be responsible under CERCLA for all or part of the
costs to clean up sites at which such wastes have been released. Neither the
Company nor, to its knowledge, its predecessors has been named a potentially
responsible person under CERCLA, nor does the Company know of any prior owners
or operators of its properties that are named as potentially responsible parties
related to their ownership or operation of such property.

The Company has a proactive environmental policy that management feels
benefits the Company through increased operating profits, improved landowner
relations and an overall enhanced Company image. To this end, the Company has
also adopted a stringent environmental evaluation prior to purchasing a
property. This pre-acquisition assessment, usually referred to as an
Environmental Site Assessment, typically consists of a historical review of the
property combined with a site inspection and limited testing, when necessary.
The objective of this pre-acquisition assessment is to document conditions at
the time of acquisition and to assign liability to the seller for past
operations.

EMPLOYEES

At March 25, 2002, the Company had 196 full-time and 11 part-time
employees, 19 of whom were employed by the Company at its principal offices in
Stamford, Connecticut, 23 in Houston, Texas, at the offices of Prime Operating
Company, Eastern Oil Well Service Company and EOWS Midland Company and 165
employees who were

6

primarily involved in the district operations of the Company in Houston and
Midland, Texas, Oklahoma City, Oklahoma and Charleston, West Virginia.

ITEM 2. DESCRIPTION OF PROPERTY.

The Company's executive offices and those of PEMC, are located at One
Landmark Square, Stamford, Connecticut, in leased premises of about 8,860 square
feet. The executive offices of Prime Operating Company, Eastern Oil Well Service
Company and EOWS Midland Company are located in leased premises in Houston,
Texas, and the offices of Southwest Oilfield Construction Company are in
Oklahoma City, Oklahoma.

The Company maintains district offices in Houston and Midland, Texas,
Oklahoma City, Oklahoma and Charleston, West Virginia, and has field offices in
Carrizo Springs and Midland, Texas, Kingfisher and Garvin, Oklahoma and Orma,
West Virginia.

The Company owns several parcels of land in Oklahoma, on which oil and
gas wells it owns and operates are located. These properties were purchased
primarily to simplify operations of these properties.

Substantially all of the Company's oil and gas properties are subject
to a mortgage given to collateralize indebtedness of the Company, or are subject
to being mortgaged upon request by the Company's lender for additional
collateral.

The information set forth below concerning the Company's properties,
activities, and oil and gas reserves include the Company's interests in the
Partnerships, Trusts and joint ventures.

The following table sets forth the exploratory and development drilling
experience with respect to wells in which the Company participated during the
five years ended December 31, 2001.

OIL AND GAS PRODUCTION

As of December 31, 2001, the Company had ownership interests in the
following numbers of gross and net producing oil and gas wells and gross and net
producing acres (1).

(1) A gross well or gross acre is a well or an acre in which a working
interest is owned. A net well or net is the sum of the fractional
revenue interests owned in gross wells or gross acres. Wells are
classified by their primary product. Some wells produce both oil and
gas.

The following table shows the Company's net production of crude oil and
natural gas for each of the five years ended December 31, 2001. "Net" production
is net after royalty interests of others are deducted and is determined by
multiplying the gross production volume of properties in which the Company has
an interest by percentage of the leasehold, mineral or royalty interest owned by
the Company.

7

The following table sets forth the Company's average sales price per
barrel of crude oil and average sales prices per one thousand cubic feet ("Mcf")
of gas, together with the Company's average production costs per unit of
production for the five years ended December 31, 2001.

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(1) Net equivalent barrels are computed at a rate of 6 Mcf per barrel.

UNDEVELOPED ACREAGE

The following table sets forth the approximate gross and net
undeveloped acreage in which the Company has leasehold, mineral and royalty
interests as of December 31, 2001. "Undeveloped acreage" is that acreage on
which wells have not been drilled or completed to a point that would permit the
production of commercial quantities of oil and gas, regardless of whether or not
such acreage contains proved reserves.

RESERVES

The Company's interests in proved developed and undeveloped oil and gas
properties have been evaluated by Ryder Scott & Company L.P. for the years ended
December 31, 1997, 1998, 1999, 2000 and 2001. All of the Company's reserves are
located within the continental United States. The following table summarizes the
Company's oil and gas reserves at each of the respective dates (figures
rounded):

The estimated future net revenue (using current prices and costs as of
those dates, exclusive of income taxes) and the present value of future net
revenue (at a 10% discount for estimated timing of cash flow) for the Company's
proved developed and proved undeveloped oil and gas reserves at the end of each
of the five years ended December 31, 2001, are summarized as follows (figures
rounded):

8

"Proved developed" oil and gas reserves are reserves that can be
expected to be recovered from existing wells with existing equipment and
operating methods. "Proved undeveloped" oil and gas reserves are reserves that
are expected to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required for
recompletion.

In accordance with FASB Statement No. 69, December 31 market prices are
determined using the daily oil price or daily gas sales price ("spot price")
adjusted for oilfield or gas gathering hub and wellhead price differentials
(e.g. grade, transportation, gravity, sulfur, and BS&W) as appropriate. Also in
accordance with SEC and FASB specifications, changes in market prices subsequent
to December 31 are not considered. The spot price for gas at December 31, 2001
and 2000 were $2.63 and $9.23 per MMBTU, respectively. The range of spot prices
during the year 2001 was a low of $1.77 and a high of $10.29 and the average was
$3.94. The range during the first quarter of 2002 has been from $2.01 to $3.58
with an average of $2.50. The recent futures market prices have been in the
$3.00 to $3.50 range. While it may reasonably be anticipated that the prices
received by the Company for the sale of its production may be higher or lower
than the prices used in this evaluation, as described above, and the operating
costs relating to such production may also increase or decrease from existing
levels, such possible changes in prices and costs were, in accordance with rules
adopted by the SEC, omitted from consideration in making this evaluation for the
SEC case. Actual volumes produced, prices received and costs incurred by the
Company may vary significantly from the SEC case.

Since January 1, 2002, the Company has not filed any estimates of its
oil and gas reserves with, nor were any such estimates included in any reports
to, any federal authority or agency, other than the Securities and Exchange
Commission, except Form EIA-23, Annual Survey of Domestic Oil and Gas Reserves,
filed with The Energy Information Administration of the U.S. Department of
Energy.

ITEM 3. LEGAL PROCEEDINGS.

From time to time, the Company is party to certain legal actions and
claims arising in the ordinary course of business. While the outcome of these
events cannot be predicted with certainty, management does not expect these
matters to have a materially adverse effect on the financial position or results
of operations of the Company.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS.

No matters were submitted during the fourth quarter of the fiscal year
ended December 31, 2001, to a vote of the Company's security-holders through the
solicitation of proxies or otherwise.

PART II

ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.

The Company's Common Stock is traded in the NASDAQ Stock Market,
trading symbol "PNRG". The high and low bid quotations for each quarterly period
during the two years ended December 31, 2001, were as follows:

9

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

The approximate number of record holders of the Company's Common Stock
as of March 25, 2002 was 1,051.

No dividends have been declared or paid during the past two years on
the Company's Common Stock. Provisions of the Company's line of credit agreement
restrict the Company's ability to pay dividends. Such dividends may be declared
out of funds legally available therefore, when and as declared by the Company's
Board of Directors.

ITEM 6. SELECTED FINANCIAL DATA

The following table summarizes certain selected financial data to
highlight significant trends in the Company's financial condition and results of
operations for the periods indicated. The selected financial data should be read
in conjunction with the Financial Statements and related notes included
elsewhere in this Report.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION.

This discussion should be read in conjunction with the financial
statements of the Company and notes thereto. The Company's subsidiaries are
defined in Note 1 of the financial statements. PEMC is the managing general
partner or managing trustee in several Limited Partnerships and Trusts
(collectively, the "Partnerships").

LIQUIDITY AND CAPITAL RESOURCES

Net cash provided by operations was $12,313,000 in 2001, $11,498,000 in
2000, and $7,677,000 in 1999.

The Company has been party to a series of credit agreements with its
primary lender or its predecessors since 1983. The current agreement, entered
into in April, 1995, provides for borrowings under a Master Note. Advances under
the agreement, as amended, are limited to the borrowing base as defined in the
agreement. The borrowing base is re-determined by the lender on a semi-annual
basis. Since the beginning of 1999, the borrowing base has ranged from $20
million to $23.7 million. The credit agreement provides for interest on
outstanding borrowings at the bank's base rate, as defined, payable monthly, or
at rates ranging from 1 1/2% to 2% over the London Inter-Bank Offered Rate (LIBO
rate) depending upon the Company's utilization of the available line of credit,
payable at the end of the applicable interest period.

The average interest rates paid on outstanding borrowings subject to
interest at the bank's base rate during 2001 and 2000 were 6.92% and 9.46%,
respectively. During the same periods, the average rates paid on outstanding
borrowings bearing interest based upon the LIBO rate were 5.98% and 8.46%. As of
December 31, 2001 and 2000, the total outstanding borrowings were $16,950,000
and $17,200,000, respectively, with an additional $6,050,000 and $1,750,000
available, and $14,950,000 and $13,500,000 of the amounts outstanding accruing
interest at the LIBO rate option.

The Company's oil and gas properties as well as certain receivables and
equipment are pledged as security under the loan agreement. The agreement
requires the Company to maintain, as defined, a minimum current ratio, tangible
net worth, debt coverage ratio and interest coverage ratio, and restrictions are
placed on the payment of dividends and the amount of treasury stock the Company
may purchase.

The Company spent approximately $1,386,000 developing the East Wakita
field during 2001. Three successful wells were drilled on this property in 2001,
and two more successful wells were drilled in the first quarter of 2002. Further
development of this prospect is planned for the future.

The Company spent $1,100,000 developing the DSR prospect in Garvin
County, Oklahoma. First sales from this field occurred in January, 2002.
Additional development of this field is planned for 2002.

10

In total, the Company spent $6,650,000 on the acquisition and
development of oil and gas properties during 2001, including $545,000 spent to
repurchase limited partnership interests from investors in its oil and gas
partnerships.

The Company spent $2,054,000 on field service equipment during 2001,
and an additional $108,000 on computers, software and related equipment. The
Company spent $3,156,000 to repurchase shares of its treasury stock in 2001. As
of the date of this report, the Company had spent an additional $182,000 on
treasury stock purchases in 2002.

It is the goal of the Company to increase its oil and gas reserves and
production through the acquisition and development of oil and gas properties.
The Company also continues to explore and consider opportunities to further
expand its oilfield servicing revenues through additional investment in field
service equipment. However, the majority of the Company's capital spending is
discretionary, and the ultimate level of expenditures will be dependent on the
Company's assessment of the oil and gas business environment, the number and
quality of oil and gas prospects available, the market for oilfield services,
and oil and gas business opportunities in general.

RESULTS OF OPERATIONS:

2001 AS COMPARED TO 2000

The Company had net income of $5,413,000 in 2001, as compared to
$5,365,000 in 2000. Oil and gas production and revenue remained flat, and
district operating income increased by 26% to $17,082,000, contributing to an 8%
increase in overall revenues to $42,408,000.

Oil and gas sales were $22,998,000 in 2001 as compared to $23,223,000
in 2000, a drop of less than 1%. A chart summarizing oil and gas production and
revenue, including the Company's share of production and revenue from the
Partnerships, follows.

The Company completed a successful well on its Cadiz field in Bee
County, Texas during 2001. Two successful wells had been completed on this
prospect in 2000. These three wells contributed 3,400 barrels of oil, 380,000
Mcf of gas and $1,624,000 in revenue in 2001, as compared to 1,200 barrels,
168,000 Mcf of gas and $853,000 in 2000. No further drilling is currently
planned for this prospect.

The Company spent $1,386,000 developing the East Wakita field in
Oklahoma during 2001, including the drilling of three successful gas wells. Two
additional successful wells were drilled on this prospect in the first quarter
of 2002, and additional development is planned for the future. This prospect
contributed $915,000 to oil and gas revenues in 2001.

The Francis Martin well experienced a natural decline in gas and oil
production and increase in water production as well as shut-ins for mechanical
work during 2001. This well contributed 2,000 barrels of oil, 115,000 Mcf of gas
and $654,000 in revenue in 2001, as compared to 6,000 barrels, 371,000 Mcf and
$1,654,000 in 2000.

District operating income increased 26% to $17,082,000 in 2001 as
compared to $13,585,000 in 2000. This increase reflects the utilization of the
over $2,000,000 in field service equipment the Company purchased during the
year, and its focus on expanding the amount of work performed for third parties
on wells not operated by the Company. This increase also reflects full
administrative overhead charges on marginal properties where the Company had
previously discounted such fees.

11

Lease operating expenses increased by 22% to $11,083,000 in 2001 as
compared to $9,114,000 in 2000. Approximately $874,000 of this amount is
attributable to properties purchased or developed during 2000 or 2001. The
remainder of the difference is primarily attributable to an increase in repair
and fix-up work performed, and a decrease in discounts received in
administrative overhead due to the strong price environment in 2001.

Administrative revenue, which represents the reimbursement of general
and administrative overhead expended on behalf of the Partnerships and the
Company's joint venture partners decreased by 7% to $1,535,000 in 2001 as
compared to $1,655,000 in 2000. In both years, amounts received from certain of
the Partnerships were substantially less than the amounts allocable to these
Partnerships under the partnership agreements. The lower amounts reflect PEMC's
continuing efforts to reduce costs, both incurred and allocated to the
Partnerships.

Reporting and management fees are earned from providing the accounting
and reporting functions for certain of the Partnerships.

The Company receives reimbursement for costs incurred related to the
evaluation and acquisition of properties on behalf of the Partnerships and other
joint venture partners. To the extent that these property acquisition costs are
expended at the district level, the reimbursements are recorded as a reduction
of total district operating expenses. When expenses are incurred at the
corporate headquarters level, such reimbursements are recorded as a reduction of
total general and administrative expenses. During 2001 and 2000, the Company's
total reimbursements for property acquisition costs were approximately $558,000
and $1,100,000, respectively.

General and administrative expenses increased 7% to $4,310,000 in 2001
as compared to $4,033,000 in 2000. This increase reflects the change in cost
reimbursement offset by savings related to overhead efficiencies.

Depreciation and depletion of oil and gas properties decreased by 11%
to $4,522,000 in 2001 as compared to $5,060,000 in 2000, while impairments
increased to $753,000 in 2001 as compared to $295,000 in 2000. Total depletion
and impairment expense in 2001 was $5,275,000 in 2001 as compared to $5,355,000
in 2000, a decline of approximately 1%.

Exploration costs of $509,000 in 2001 consist primarily of the cost of
three dry holes drilled in 2001. Exploration costs of $1,797,000 in 2000
consisted primarily of dry hole costs relating to the drilling of two offshore
wells in the fourth quarter of that year.

Interest expense decreased by 40% to $895,000 in 2001 as compared to
$1,500,000 in 2000 due to a combination of lower interest rates and lower
average outstanding debt. The average interest rates paid on outstanding
borrowings subject to interest at the bank's base rate during 2001 and 2000 were
6.92% and 9.46%, respectively. During the same periods, the average rates paid
on outstanding borrowings bearing interest based upon the LIBO rate were 5.98%
and 8.46%. As of December 31, 2001 and 2000, the total outstanding borrowings
were $16,950,000 and $17,200,000, respectively, with an additional $6,050,000
and $1,750,000 available, and $14,950,000 and $13,500,000 of the amounts
outstanding accruing interest at the LIBO rate option.

Income tax expense increased by 112% to $1,721,000 in 2001 as compared
to $811,000 in 2000. The effective rate was 24% in 2001 as compared to 13% in
2000. In both 1998 and 1999, the Company had large federal net operating losses.
The value of these loss carryforwards was fully reserved against due to the
uncertainty as to whether the Company would have future net income against which
these losses could be offset. The use of these previously reserved against
carryforwards were the primary reason for the low effective rate in 2000.

Current tax expense in 2001 was $38,000, with the remainder of expense
being attributable to an increase in the Company's deferred tax liability. The
Company generates approximately $350,000 of federal tax credits under Internal
Revenue Code Section 29 for producing fuel from a non-conventional source. These
credits, which significantly lower current tax expense, are scheduled to expire
after 2002. Another contributing factor to the extremely low current expense is
that the Company is allowed to deduct currently for income tax purposes
intangible drilling costs which are capitalized for financial reporting
purposes. The Company had over $5,000,000 in such costs during 2001. The amount
of intangible drilling costs which will be incurred in future years will depend
on many factors and cannot be reliably predicted.

2000 AS COMPARED TO 1999

The Company had net income of $5,365,000 in 2000, as compared to a net
loss of $2,138,000 in 1999. The improved results in 2000 are due to a
combination of sharply higher prices received for the Company's oil and

12

gas production, increases in production volumes, and the expansion of the
Company's oilfield services operations. The 1999 loss was caused primarily by a
$2,703,000 impairment on the Ramrod Property, located in Matagorda County, Texas

Oil and gas sales increased by 97%, to $23,223,000 in 2000 as compared
to $11,763,000 in 1999, due to a combination of higher prices and increased
production.. A chart summarizing oil and gas revenue in those two years,
including the Company's share of production and revenue from the partnerships,
follows.

On November 15, 1999, the Company purchased interests in approximately
131 oil and gas wells located in various counties in Oklahoma. These properties
contributed 433,000 Mcf of gas, 29,000 barrels of oil and $2,215,000 of revenue
in the year 2000, as compared to 72,000 Mcf of gas, 6,800 barrels of oil and
$337,000 of revenue during the 1 1/2 months the Company owned these properties
in 1999.

In the second quarter of 2000 the Company completed the Brooks Trust #1
well in Bee County, Texas, and in the third quarter drilled the Brooks Trust #
2. These wells produced a combined 168,000 Mcf of gas, and contributed $853,000
in revenue net to the Company's interest in 2000.

In August of 2000 the Company had first sales from a well drilled and
completed on the East Wakita Prospect in Oklahoma. This well produced 147,000
Mcf of gas and contributed $597,000 of revenue net to the Company's interest
through December 31, 2000.

District operating income increased by 19% to $13,585,000 in 2000 as
compared to $11,407,000 in 1999. This increase reflects the utilization of field
service equipment purchased during the year, and the Company's continued focus
on expanding its field service operations, particularly the amount of work
performed on wells operated by third parties. The Company spent $1,582,000 to
purchase equipment used in its field service operations in 2000.

Lease operating expenses increased by 45% in 2000 to $9,114,000 as
compared to $6,305,000 in 1999, primarily due to higher volumes produced and a
greater amount of repair and fix up work performed in 2000 than in 1999, when
prices were extremely depressed. The additional interests in Oklahoma properties
purchased in November 1999 accounted for $382,000 of this increase.

Administrative revenue, which represents the reimbursement of general
and administrative overhead expended on behalf of the Partnerships and the
Company's joint venture partners decreased slightly to $1,655,000 in 2000 as
compared to $1,673,000 in 1999. In both years, amounts received from certain of
the Partnerships were substantially less than the amounts allocable to these
Partnerships under the partnership agreements. The lower amounts reflect PEMC's
continuing efforts to reduce costs, both incurred and allocated to the
Partnerships.

Reporting and management fees are earned from providing the accounting
and reporting functions for certain of the Partnerships.

The Company receives reimbursement for costs incurred related to the
evaluation and acquisition of properties on behalf of the Partnerships and other
joint venture partners. To the extent that these property acquisition costs are
expended at the district level, the reimbursements are recorded as a reduction
of total district operating expenses. When expenses are incurred at the
corporate headquarters level, such reimbursements are recorded as a reduction of
total general and administrative expenses. During 2000 and 1999, the Company's
total reimbursements for property acquisition costs were approximately
$1,100,000 and $1,450,000, respectively.

13

General and administrative expenses increased 28% to $4,033,000 in 2000
as compared to $3,149,000 in 1999. The change in cost reimbursement, previously
discussed, and increased compensation costs contributed to this increase.
Compensation and benefit costs increased due to nonrecurring employee benefit
costs related to the resignation of a company employee and generally higher
compensation costs attributable to the expansion of the Company's operating
activities.

Depreciation and depletion of oil and gas properties increased by 10%
to $5,060,000 in 2000 as compared to $4,581,000 in 1999 due to higher volumes
produced.

Impairment of oil and gas properties of $295,000 in 2000 related to
several of the Company's less significant properties. The $2,703,000 impairment
in 1999 related entirely to the impairment of a single property, the Ramrod
field located in Matagorda County, Texas.

Exploration costs of $1,797,000 in 2000 consisted primarily of dry hole
costs relating to the drilling of two offshore wells in the fourth quarter of
the year. 1999 costs of $869,000 consisted primarily of dry hole costs on wells
which were part of the Company's 1998 drilling program.

1999 AS COMPARED TO 1998

The Company incurred a loss of $2,138,000 in 1999 as compared to a loss
of $1,692,000 in 1998. The 1999 loss was caused by a $2,703,000 impairment on
the Ramrod Property, located in Matagorda County, Texas. The 1998 loss was
primarily caused by exploration costs of $1,706,000 combined with extremely low
oil and gas prices.

The Company sold 50% of its interest in the Ramrod field and turned
over operations to the purchaser in November 1998. The new operator increased
flow rates on the most significant well on this property, the St. George # 1,
and soon afterwards the well began to experience mechanical problems. Despite
several expensive attempts to repair this well throughout 1999, production rates
at the end of 1999 were about an eighth of what they were before the mechanical
problems began, and the estimated future reserves at January 1, 2000 declined
drastically from the prior year estimates. Additionally, the Company incurred
$1,582,000 in drilling costs on the property in 1999, and while some reserves
were found, the future net revenue associated with these reserves is greatly
below the costs incurred.

Oil and gas sales increased by $409,000, to $11,763,000 in 1999 as
compared to $11,354,000 in 1998, as increased prices more than offset production
declines.

Oil production declined by 13,000 barrels, to 264,000 barrels in 1999
as compared to 277,000 barrels in 1998, due primarily to natural decline curves
on existing properties. Gas production declined by 332,000 Mcf to 3,289,000 Mcf
in 1999 from 3,621,000 Mcf in 1998, as a drop of 561,000 Mcf in production from
the Ramrod property and the natural decline curve of existing properties was
only partially offset by production from additional interests in properties
purchased during the year, and wells which came on line in 1999. The most
significant well to come on line in 1999 was the Francis Martin well, which
began production in January and produced 510,000 Mcf of gas during the year. The
Company's participation in this well was subject to a provision whereby the
Company's interest is reduced when it reaches payout and again upon reaching
200% of payout. These events occurred in August 1999 and February 2000. The
Company's original 13.44% net revenue interest has been reduced to 9.33%.

The Oklahoma properties purchased in November of 1999 produced 72,000
Mcf of gas and 6,800 barrels of oil during the 1 1/2 months the Company owned
these properties in 1999.

The average price received for a barrel of oil increased to $15.71 in
1999 as compared to $12.39 in 1998, and the average gas price received increased
to $2.32 in 1999, as compared to $2.19 in 1998.

Lease operating expenses decreased by $306,000 to $6,305,000 in 1999 as
compared to $6,611,000 in 1998, due to lower volumes produced.

District operating income increased by $462,000, to $11,407,000 in 1999
as compared to $10,945,000 in 1998, as the Company continued to expand its well
servicing operations.

Administrative revenue, which represents the reimbursement of general
and administrative overhead expanded on behalf of the Partnerships and the
Company's joint venture partners decreased by $50,000 to $1,673,000 in 1999 as
compared to $1,723,000 in 1998. In both years, amounts received from certain of
the

14

Partnerships were substantially less than the amounts allocable to these
Partnerships under the partnership agreements. The lower amounts reflect PEMC's
continuing efforts to reduce costs, both incurred and allocated to the
Partnerships.

Reporting and management fees are earned from providing the accounting
and reporting functions for certain of the Partnerships.

The Company receives reimbursement for costs incurred related to the
evaluation and acquisition of properties on behalf of the Partnerships and other
joint venture partners. To the extent that these property acquisition costs are
expended at the district level, the reimbursements are recorded as a reduction
of total district operating expenses. When expenses are incurred at the
corporate headquarters level, such reimbursements are recorded as a reduction of
total general and administrative expenses. During 1999 and 1998 the Company's
total reimbursements for property acquisition costs were approximately
$1,450,000 and $1,690,000 respectively.

Depreciation and depletion of oil and gas properties decreased by
$1,393,000 to $4,581,000 in 1999 as compared to $5,974,000 in 1998 due to lower
volumes produced, and lower depletion rates on many properties due to increased
reserve estimates at year-end. These increased reserve estimates were partly due
to an increase in prices.

Exploration costs of $869,000 in 1999 consisted primarily of dry hole
costs on wells which were part of the Company's 1998 drilling program.

ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

The Company is exposed to interest rate risk on its line of credit,
which has variable rates based upon the lenders base rate, as defined, and the
London Inter-Bank Offered rate. Based on the balance outstanding at December 31,
2001, a hypothetical 2% increase in the applicable interest rates would increase
interest expense by approximately $339,000.

Oil and gas prices have historically been extremely volatile, and have
been particularly so in recent years. The Company did not enter into significant
hedging transactions during 2001, and had no open hedging transactions at
December 31, 2001. Declines in domestic oil and gas prices could have a material
adverse effect on the Company's revenues, operating results and the estimates of
economically recoverable reserves and the net revenue therefrom.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Included on pages F-1 through F-26 of this Report. The Index to
Financial Statements is at page F-1 of this Report.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Information relating to the Company's Directors, nominees for Directors
and executive officers is included in the Company's definitive proxy statement
relating to the Company's Annual Meeting of Stockholders to be held in June,
2002, which will be filed with the Securities and Exchange Commission within 120
days of December 31, 2001, and which is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION.

Information relating to executive compensation is included in the
Company's definitive proxy statement relating to the Company's Annual Meeting of
Stockholders to be held in June, 2002, which will be filed with the Securities
and Exchange Commission within 120 days of December 31, 2001, and which is
incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

Information relating to security ownership of certain beneficial owners
and management is included in the Company's definitive proxy statement relating
to the Company's Annual Meeting of Stockholders to be held in June, 2002, which
will be filed with the Securities and Exchange Commission within 120 days of
December 31, 2001, and which is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

Information relating to certain transactions by Directors and executive
officers of the Company is included in the Company's definitive proxy statement
relating to the Company's Annual Meeting of Stockholders to be held in June,
2002, which will be filed with the Securities and Exchange Commission within 120
days of December 31, 2001, and which is incorporated herein by reference.

15

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.

(a) Exhibits:

No.
---
3.1 Restated Certificate of Incorporation of PrimeEnergy
Corporation. (Incorporated herein by reference to
Exhibit 3.1 of PrimeEnergy Corporation Form 10-KSB for
the year ended December 31, 1999)

3.2 Bylaws of PrimeEnergy Corporation. (Incorporated herein
by reference to Exhibit 3.2 of PrimeEnergy Corporation
Form 10-KSB for the year ended December 31, 1999)

10.1 PrimeEnergy Corporation 1983 Incentive Stock Option Plan
(Incorporated herein by reference to Exhibit 10.1 of
PrimeEnergy Corporation Form 10-KSB for the year ended
December 31, 1994)(1)

10.3 Massachusetts Mutual Flexinvest 401(k) Plan as amended
and restated. (Incorporated herein by reference to
Exhibit 10.3 of PrimeEnergy Corporation Form 10-KSB for
the year ended December 31, 1994)(1)

10.7 Credit Agreement dated April 26, 1995, between
PrimeEnergy Corporation, PrimeEnergy Management
Corporation and Bank One, Texas, National Association.
(Incorporated herein by reference to Exhibit 10.7 to
PrimeEnergy Corporation Form 8-K dated April 26, 1995)

10.7.1 First Amendment to Credit Agreement Among PrimeEnergy
Corporation and PrimeEnergy Management Corporation, as
Borrowers, Bank One, Texas, National Association, as
Agent, and the Lenders Signatory Hereto, effective as of
October 6, 1995. (Incorporated herein by reference to
Exhibit 10.7.1 to PrimeEnergy Corporation Form 10-KSB
for the year ended December 31, 1995)

10.7.2 Second Amendment to Credit Agreement Among PrimeEnergy
Corporation and PrimeEnergy Management Corporation, as
Borrowers, Bank One, Texas, National Association, as
Agent, and the Lenders Signatory Hereto, effective as of
February 6, 1997. (Incorporated by reference to Exhibit
10.7.2 of PrimeEnergy Corporation Form 10-KSB for the
year ended December 31, 1996)

10.7.3 Third Amendment to Credit Agreement Among PrimeEnergy
Corporation and PrimeEnergy Management Corporation, as
Borrowers, Bank One, Texas, National Association, as
Agent, and the Lenders Signatory Hereto, effective as of
January 2, 1998 (Incorporated by reference to Exhibit
10.7.3 of PrimeEnergy Corporation Form 10-KSB for the
year ended December 31, 1997)

10.8 Mortgage, Deed or Trust, Indenture, Security Agreement,
Financing Statement and Assignment of Production dated
May 27, 1994, as ratified and amended April 26, 1995,
between PrimeEnergy Corporation, PrimeEnergy Management
Corporation and Bank One, Texas, National Association.
(Incorporated by reference to Exhibit 10.8 of
PrimeEnergy Corporation Form 8-K dated April 26, 1995)

10.17 Amended Marketing Agreement between PrimeEnergy
Management Corporation and Charles E. Drimal, Jr.
(Incorporated herein by reference to Exhibit 10.17 of
PrimeEnergy Corporation Form 10-KSB for the year ended
December 31, 1994)(1)

10.18 Composite copy of Non-Statutory Option Agreements
(Incorporated by reference to Exhibit 10.18 of
PrimeEnergy Corporation for 10KSB for the year ended
December 31, 1997)(1)

10.21 Purchase and Sale Agreement dated November 16, 1999
between Southern Pacific Petroleum U.S.A. and
PrimeEnergy Corporation (Incorporated herein by
reference to Exhibit 10.21 to PrimeEnergy Corporation
Form 8-K dated November 24, 1999)

16

21 Subsidiaries. (filed herewith)

23 Consent of Ryder Scott & Company L.P. Company. (filed
herewith)

- ----------

(1) Management contract or compensatory plan or arrangement required to be
filed as an Exhibit to this Form 10-K.

(a) Reports on Form 8-K:

None

17

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, on the 30th day of
March, 2002.

PrimeEnergy Corporation

By: /s/ CHARLES E. DRIMAL, JR.
---------------------------
Charles E. Drimal, Jr.
President

Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities indicated and on the 30th day of March, 2002.

/s/ CHARLES E. DRIMAL, JR. Director and President;
- -------------------------- The Principal Executive Officer
Charles E. Drimal, Jr.

/s/ BEVERLY A. CUMMINGS Director, Vice President and Treasurer;
- -------------------------- The Principal Financial and Accounting Officer
Beverly A. Cummings

/s/ JAMES P. BOLDRICK Director /s/ CLINT HURT Director
- -------------------------- --------------------
James P. Boldrick Clint Hurt

/s/ SAMUEL R. CAMPBELL Director Director
- -------------------------- --------------------
Samuel R. Campbell Robert de Rothschild

Director /s/ JARVIS K. SLADE Director
- -------------------------- --------------------
James E. Clark Jarvis Slade

/s/ MATTHIAS ECKENSTEIN Director /s/ JAN K. SMEETS Director
- -------------------------- --------------------
Matthias Eckenstein Jan K. Smeets

/s/ H. GIFFORD FONG Director /s/ GAINES WEHRLE Director
- -------------------------- --------------------
H. Gifford Fong Gaines Wehrle

Director Director
- -------------------------- --------------------
Thomas S.T. Gimbel Michael Wehrle

18

INDEX TO FINANCIAL STATEMENTS

Financial Statements (Included herein at pages F-1 through F-23):

Report of Independent Public Accountants F-2

Financial Statements

Consolidated Balance Sheets -- December 31, 2001 and 2000 F-3

Consolidated Statements of Operations -- for the years ended December 31,
2001, 2000 and 1999 F-5

Consolidated Statements of Stockholders' Equity -- for the years ended
December 31, 2001, 2000 and 1999 F-6

Consolidated Statements of Cash Flows -- for the years ended December 31,
2001, 2000 and 1999 F-7

Notes to Consolidated Financial Statements F-8

Supplementary Information: F-20

Capitalized Costs Relating to Oil and Gas Producing Activities
December 31, 2001, 2000 and 1999 F-21

Costs Incurred in Oil and Gas Property Acquisition, Exploration and
Development Activities, years ended December 31, 2001, 2000 and 1999 F-21

Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas Reserves, years ended December 31, 2001, 2000 and
1999 F-22

Standardized Measure of Discounted Future Net Cash Flows and Changes
Therein Relating to Proved Oil and Gas Reserves, years ended December 31,
2001, 2000 and 1999 F-23

Reserve Quantity Information, years ended December 31, 2001, 2000 and 1999 F-24

Results of Operations from Oil and Gas Producing Activities, years ended
December 31, 2001, 2000 and 1999 F-25

Notes to Supplementary Information F-26

F-1

PUSTORINO, PUGLISI, & CO., LLP

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Stockholders of
PrimeEnergy Corporation:

We have audited the accompanying consolidated balance sheets of PrimeEnergy
Corporation and Subsidiaries as of December 31, 2001 and 2000, and the related
consolidated statements of operations, stockholders' equity and cash flows for
the years then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on the
financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of PrimeEnergy
Corporation and Subsidiaries as of December 31, 2001 and 2000, and the
consolidated results of their operations and their cash flows for the years
ended December 31, 2001, 2000 and 1999 in conformity with accounting principles
generally accepted in the United States of America.

/s/ PUSTORINO, PUGLISI & CO., LLP
Pustorino, Puglisi & Co., LLP
New York, New York
March 29, 2002

F-2

PRIMEENERGY CORPORATION and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, December 31, 2001 and 2000

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

F-3

PRIMEENERGY CORPORATION and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, December 31, 2001 and 2000

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

F-4

PRIMEENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS of OPERATIONS

for the years ended December 31, 2001, 2000 and 1999

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

F-5

PRIMEENERGY CORPORATION and SUBSIDIARIES

CONSOLIDATED STATEMENT of STOCKHOLDERS' EQUITY

for the years ended December 31, 2001, 2000 and 1999

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

F-6

PRIMEENERGY CORPORATION and SUBSIDIARIES

CONSOLIDATED STATEMENTS of CASH FLOWS

for the years ended December 31, 2001, 2000 and 1999

----------

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

F-7

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

----------

1. DESCRIPTION OF OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations:

PrimeEnergy Corporation ("PEC"), a Delaware corporation, was organized
in March 1973. PrimeEnergy Management Corporation ("PEMC"), a
wholly-owned subsidiary, acts as the managing general partner,
providing administration, accounting and tax preparation services for
45 private and publicly-held limited partnerships and 2 trusts
(collectively, the "Partnerships"). PEC owns Eastern Oil Well Service
Company ("EOWSC"), EOWS Midland Company and Southwest Oilfield
Construction Company ("SOCC"), all of which perform oil and gas field
servicing. PEC also owns Prime Operating Company ("POC"), which serves
as operator for most of the producing oil and gas properties owned by
the Company and affiliated entities. Field service revenues and the
administrative overhead fees earned as operator are reported as
'District operating income' on the consolidated statement of
operations. PrimeEnergy Corporation and its wholly-owned subsidiaries
are herein referred to as the "Company."

The Company is engaged in the development, acquisition and production
of oil and natural gas properties. The Company owns leasehold, mineral
and royalty interests in producing and non-producing oil and gas
properties across the continental United States, including Colorado,
Kansas, Louisiana, Mississippi, Montana, Nebraska, New Mexico, North
Dakota, Oklahoma, Texas, Utah, West Virginia and Wyoming. The Company
operates 1,550 wells and owns non-operating interests in over 800
additional wells. Additionally, the Company provides well-servicing
support operations, site-preparation and construction services for oil
and gas drilling and re-working operations, both in connection with the
Company's activities and providing contract services for third parties.
The Company is publicly traded on the NASDAQ under the symbol "PNRG."

The markets for the Company's products are highly competitive, as oil
and gas are commodity products and prices depend upon numerous factors
beyond the control of the Company, such as economic, political and
regulatory developments and competition from alternative energy
sources.

Principles of Consolidation:

The consolidated financial statements include the accounts of
PrimeEnergy Corporation and its wholly-owned subsidiaries. All material
inter-company accounts and transactions between these entities have
been eliminated. Oil and gas properties include ownership interests in
the Partnerships. The statement of operations includes the Company's
proportionate share of revenue and expenses related to oil and gas
interests owned by the Partnerships.

Use of Estimates:

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ
from those estimates.

Estimates of oil and gas reserves, as determined by independent
petroleum engineers, are continually subject to revision based on
price, production history and other factors. Depletion expense, which
is computed based on the units of production method, could be
significantly impacted by changes in such estimates. Additionally, FAS
121 requires that if the expected future cash flow from an asset is
less than its carrying cost, that asset must be written down to its
fair market value. As the fair market value of an oil and gas property
will usually be significantly less than the total future net revenue
expected from that property, small changes in the estimated future net
revenue from an asset could lead to the necessity of recording a
significant impairment of that asset.

F-8

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

----------

Property and Equipment:

The Company follows the "successful efforts" method of accounting for
its oil and gas properties. Under the successful efforts method, costs
of acquiring undeveloped oil and gas leasehold acreage, including lease
bonuses, brokers' fees and other related costs are capitalized.
Provisions for impairment of undeveloped oil and gas leases are based
on periodic evaluations. Annual lease rentals and exploration expenses,
including geological and geophysical expenses and exploratory dry hole
costs, are charged against income as incurred. Costs of drilling and
equipping productive wells, including development dry holes and related
production facilities, are capitalized. Costs incurred by the Company
related to the exploration, development and acquisition of oil and gas
properties on behalf of the Partnerships or joint ventures are deferred
and charged to the related entity upon the completion of the
acquisition. To the extent that the Company acquires an interest in the
property, an appropriate allocation of internal costs are capitalized
as part of the depletable base of the property.

All other property and equipment are carried at cost. Depreciation and
depletion of oil and gas production equipment and properties are
determined under the unit-of-production method based on estimated
proved recoverable oil and gas reserves. Depreciation of all other
equipment is determined under the straight-line method using various
rates based on useful lives. The cost of assets and related accumulated
depreciation is removed from the accounts when such assets are disposed
of, and any related gains or losses are reflected in current earnings.

Income Taxes:

The Company records income taxes in accordance with Statement of
Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income
Taxes." SFAS No. 109 is an asset and liability approach to accounting
for income taxes, which requires the recognition of deferred tax assets
and liabilities for the expected future tax consequences of events that
have been recognized in the Company's financial statements or tax
returns.

Deferred tax liabilities or assets are established for temporary
differences between financial and tax reporting bases and are
subsequently adjusted to reflect changes in the rates expected to be in
effect when the temporary differences reverse. A valuation allowance is
established for any deferred tax asset for which realization is not
likely.

General and Administrative Expenses:

General and administrative expenses represent costs and expenses
associated with the operation of the Company. Certain of the
Partnerships sponsored by the Company reimburse general and
administrative expenses incurred on their behalf.

Income Per Common Share:

Income per share of common stock has been computed based on the
weighted average number of common shares outstanding during the
respective periods in accordance with SFAS No. 128, "Earnings per
Share".

Statements of cash flows:

For purposes of the consolidated statements of cash flows, the Company
considers short-term, highly liquid investments with original
maturities of less than ninety days to be cash equivalents.

Concentration of Credit Risk:

The Company maintains significant banking relationships with financial
institutions in the State of Texas. The Company limits its risk by
periodically evaluating the relative credit standing of these financial
institutions. The Company's oil and gas production purchasers consist
primarily of independent marketers and major gas pipeline companies.

F-9

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

----------

Hedging:

From time to time, the Company may enter into futures contracts in
order to reduce its exposure related to changes in oil and gas prices.
In accordance with Statement of Financial Accounting Standards No. 133,
any gain or loss on such contracts is treated as an adjustment to oil
and gas revenue. Cash activity related to hedging transactions is
treated as operating activity on the Statements of Cash Flows.

Recently Issued Accounting Standards:

In December 1999, the Securities and Exchange Commission issued Staff
Accounting Bulletin No.101, Revenue Recognition in Financial Statements
("SAB No. 101"). SAB No. 101 provides guidance for revenue recognition
under certain circumstances. The adoption of SAB 101 in 2000 did not
have a significant impact on the Company's financial position, results
of operations or cash flows.

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

In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other
Intangible Assets." This statement applies to intangibles and goodwill
acquired after June 30, 2001, as well as goodwill and intangibles
previously acquired. Under this statement, goodwill as well as other
intangibles determined to have an infinite life will no longer be
amortized; however, these assets will be reviewed for impairment on a
periodic basis. This statement is effective for the Company for the
first quarter in the fiscal year ending December 31, 2002. Management
does not believe that the adoption of this statement will have a
material effect on the Company's financial statements.

In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 requires the fair value of a
liability for an asset retirement obligation to be recognized in the
period in which it is incurred if a reasonable estimate of fair value
can be made. The associated asset retirement costs are capitalized as
part of the carrying amount of the long-lived asset. SFAS No. 143 is
effective for fiscal years beginning after June 15, 2002. Management
has not yet determined the impact of the adoption of this statement.

In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 requires
that long-lived assets be measured at the lower of carrying amount or
fair value less cost to sell, whether reported in continuing operations
or in discontinued operations. Therefore, discontinued operations will
no longer be measured at net realizable value or include amounts for
operating losses that have not yet occurred. SFAS No. 144 is effective
for financial statements issued for fiscal years beginning after
December 15, 2001 and generally, is to be applied prospectively.
Management does not believe that the adoption of this statement will
have a material effect on the Company's financial statements.

2. SIGNIFICANT ACQUISITIONS AND DISPOSITIONS

2001

As more fully described in Note 7, the Company is committed to offer to
repurchase the interests of the limited partners and trust unitholders
in certain of the Partnerships. During 2001, the Company purchased such
interests in an amount totaling $545,000.

F-10

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

----------

2000

Effective January 1, 2000, the Company purchased additional interests
in the San Pedro Ranch field of Dimmit and Maverick Counties, Texas for
$150,000.

Effective April 1, 2000, the Company purchased additional interest in
the Eola Robberson field of Garvin County, Oklahoma for $400,000. These
interests are related to certain contingency payments created at the
time the Company made its original acquisition of the field in 1988,
and are based on property performance.

Effective July 1, 2000, the Company invested $265,000 in the purchase
of various interests in five leases located in Garvin County, Oklahoma.
These leases contain 26 producing wells and 5 salt-water injection
wells. The Company assumed operation of the wells, which at the time of
the acquisition were collectively producing 61 (26.63 net) barrels of
oil per day.

In September of 2000, the Company purchased nine wells in Upton Co.
Texas. In October, the Company began a series of workovers to tap
additional oil and gas behind pipe reserves in the wells. Through
March, 2001 the Company has performed workovers on five of the nine
wells, resulting in a three fold increase in oil production and over a
six fold increase in gas production. Currently the acquisition is
producing at a rate of 55 (39 net) barrels of oil per day and 250 (177
net) Mcf of gas per day. The Company owns from 94% to 100% working
interest and 69% to 73% net revenue interest in the properties.

As more fully described in Note 7, the Company is committed to offer to
repurchase the interests of the limited partners and trust unitholders
in certain of the Partnerships. During 2000, the Company purchased such
interests in an amount totaling $1,257,000.

1999

On November 15, 1999, the Company purchased interests in approximately
131 oil and gas wells located in various counties in Oklahoma. The
Company already owned, and was the operator of, the majority of the
properties purchased.

As more fully described in Note 7, the Company is committed to offer to
repurchase the interests of the limited partners and trust unitholders
in certain of the Partnerships. During 1999, the Company purchased such
interests in an amount totaling $1,038,000.

3. ACCOUNTS RECEIVABLE

Accounts receivable at December 31, 2001 and 2000 consisted of the
following:

F-11

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

----------

4. OTHER CURRENT ASSETS

Other current assets at December 31, 2001 and 2000 consisted of the
following:

During 2001 the Company estimated that its liability for the 2001 tax
year would be approximately $1,000,000, and made estimated tax payments
accordingly. Due primarily to a significant investment in tax
deductible intangible drilling costs, along with a sharp drop in oil
and gas prices, the current estimate is substantially less. The Company
expects to receive approximately $500,000 in tax refunds during the
second quarter of 2002, with the remainder of the overpaid amount being
applied to estimated 2002 tax year liabilities. See Note 9 for a
further discussion of the company's tax situation.

5. LONG-TERM BANK DEBT

The Company has been party to a series of credit agreements with its
primary lender or its predecessors since 1983. The current agreement,
entered into in April 1995, provides for borrowings under a Master
Note. Advances under the agreement, as amended, are limited to the
borrowing base as defined in the agreement. The borrowing base is
re-determined by the lender on a semi-annual basis. Since the beginning
of 1999, the borrowing base has ranged from $20 million to $23.7
million. The credit agreement provides for interest on outstanding
borrowings at the bank's base rate, as defined, payable monthly, or at
rates ranging from 1 1/2% to 2% over the London Inter-Bank Offered Rate
(LIBO rate) depending upon the Company's utilization of the available
line of credit, payable at the end of the applicable interest period.

The average interest rates paid on outstanding borrowings subject to
interest at the bank's base rate during 2001 and 2000 were 6.92% and
9.46%, respectively. During the same periods, the average rates paid on
outstanding borrowings bearing interest based upon the LIBO rate were
5.98% and 8.46%. As of December 31, 2001 and 2000, the total
outstanding borrowings were $16,950,000 and $17,200,000, respectively,
with an additional $6,050,000 and $1,750,000 available, and $14,950,000
and $13,500,000 of the amounts outstanding accruing interest at the
LIBO rate option.

The Company's oil and gas properties as well as certain receivables and
equipment are pledged as security under the loan agreement. The
agreement requires the Company to maintain, as defined, a minimum
current ratio, tangible net worth, debt coverage ratio and interest
coverage ratio, and restrictions are placed on the payment of dividends
and the amount of treasury stock the Company may purchase.

6. COMMITMENTS

Operating Leases:

The Company has several noncancelable operating leases, primarily for
rental of office space, that have a term of more than one year.

Capital Leases:

The Company has one capital lease for office equipment in other
long-term obligations.

F-12

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

----------

Future minimum lease payments under operating and capital leases are as
follows:

7. CONTINGENT LIABILITIES

The Company, as managing general partner of the affiliated
Partnerships, is responsible for all Partnership activities, including
the review and analysis of oil and gas properties for acquisition, the
drilling of development wells and the production and sale of oil and
gas from productive wells. The Company also provides the
administration, accounting and tax preparation work for the
Partnerships, and is liable for all debts and liabilities of the
affiliated Partnerships, to the extent that the assets of a given
limited Partnership are not sufficient to satisfy its obligations.

The Company is subject to environmental laws and regulations.
Management believes that future expenses, before recoveries from third
parties, if any, will not have a material effect on the Company's
financial condition. This opinion is based on expenses incurred to date
for remediation and compliance with laws and regulations which have not
been material to the Company's results of operations.

As a general partner, the Company is committed to offer to purchase the
limited partners' interest in certain of its managed Partnerships at
various annual intervals. Under the terms of a partnership agreement,
the Company is not obligated to purchase an amount greater than 10% of
the total partnership interest outstanding. In addition, the Company
will be obligated to purchase interests tendered by the limited
partners only to the extent of one hundred fifty percent of the
revenues received by it from such partnership in the previous year.
Purchase prices are based upon annual reserve reports of independent
petroleum engineering firms discounted by a risk factor. Based upon
historical production rates and prices, management estimates that if
all such offers were to be accepted, the maximum annual future purchase
commitment would be approximately $500,000.

In connection with the purchase of oil and gas properties located in
various counties in Oklahoma in November of 1999, the Company is
committed to pay contingent consideration to the seller based upon the
performance of the properties purchased. As of December 31, 2000, the
total amount of contingent consideration estimated to be paid under the
agreement was $1,850,000. $1,000,000 of this obligation was included in
'Other long-term obligations' with the remaining $850,000 included in
'Current portion of other long-term obligations'. In 2001 the total
estimated amount of consideration to be paid was reduced by $862,000 to
$988,000 of which $763,000 was paid during 2001, leaving a net
estimated amount due of $225,000 as of December 31, 2001, all of which
is included in 'Current portion of other long-term obligations'.

F-13

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued

----------

8. STOCK OPTIONS AND OTHER COMPENSATION

In May 1989, non-statutory stock options were granted by the Company to
four key executive officers for the purchase of shares of common stock.
At December 31, 2001 and 2000, options on 767,500 shares were
outstanding and exercisable at prices ranging from $1.00 to $1.25.

On January 27, 1983, the Company adopted the 1983 Incentive Stock
Option Plan. At December 31, 2000, options on 87,000 shares were
exercisable at $1.50 per share. During July 2001, all outstanding
options under this plan were exercised.

PEMC has a marketing agreement with its current President to provide
assistance and advice to PEMC in connection with the organization and
marketing of oil and gas partnerships and joint ventures and other
investment vehicles of which PEMC is to serve as general or managing
partner. The Company had a similar agreement with its former Chairman.
Although that agreement has expired, the former Chairman is still
entitled to receive certain payments relating to partnerships formed
during the time the agreement was in effect. The President is entitled
to a percentage of the Company's carried interest depending on total
capital raised and annual performance of the Partnerships and joint
ventures.

9. INCOME TAXES

The components of the provision for income taxes for the years ended
December 31, 2001, 2000 and 1999 are as follows:

F-14

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued

----------

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

The total provision for income taxes for the years ended December 31, 2001, 2000
and 1999 varies from the federal statutory tax rate as a result of the
following:

In both 1998 and 1999 the Company had large federal net operating losses. The
value of these loss carryforwards was fully reserved against due to the
uncertainty as to whether the Company would have

F-15

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued

----------

future net income against which these losses could be offset. The use
of these previously reserved against carryforwards were the primary
reason for the low federal rate in the 2000 tax year.

Subject to certain limitations, the Company is allowed to deduct,
rather than capitalize, intangible drilling costs incurred on
successful wells. The Company incurred over $5,000,000 of intangible
drilling costs in 2001, and these deductions are largely responsible
for the extremely low current tax expense. However, the deduction of
these items for tax, while they are capitalized for financial reporting
purposes, create differences in the depletable basis of oil and gas
properties which create deferred tax liability and expense.

The Company has $366,000 of net operating loss carryforwards for both
regular and alternate minimum tax purposes. These carryforwards expire
in 2002.

The Company currently generates approximately $350,000 per year in
federal tax credits for producing fuel from a non-conventional source.
These credits may be used to reduce the regular tax, but not the
alternative minimum tax liability of the taxpayer. To the extent they
cannot be utilized due to the alternative minimum tax, they become part
of the Company's alternative minimum tax credit carryforward. This
credit is scheduled to expire at the end of the 2002 tax year.

The Company has percentage depletion carryforwards of approximately
$942,000 for regular tax purposes and $168,000 for alternative minimum
tax purposes. The Company has approximately $943,000 in alternative
minimum tax credit carryforwards. Both the percentage depletion
deductions and the alternative minimum tax credits may be carried
forward indefinitely for tax purposes.

10. SEGMENT INFORMATION AND MAJOR CUSTOMERS

The Company operates in one industry - oil and gas exploration,
development, operation and servicing. The Company's oil and gas
activities are entirely in the continental United States.

The Company sells its oil and gas production to a number of purchasers.
Listed below are the percent of the Company's total oil and gas sales
made to each of the customers whose purchases represented more than 10%
of the Company's oil and gas sales in the year 2001.

Texon Distributing L.P. 19.70%
Unimark LLC 13.79%

Although there are no long-term oil and gas purchasing agreements with
these purchasers, the Company believes that they will continue to
purchase its oil and gas products and, if not, could be replaced by
other purchasers.

11. RELATED PARTY TRANSACTIONS

PEMC is a general partner in several oil and gas Partnerships in which
certain directors have limited and general partnership interests. As
the managing general partner in each of the Partnerships, PEMC receives
approximately 5% to 15% of the net revenues of each Partnership as a
carried interest in the Partnerships' properties.

The Partnership agreements allow PEMC to receive management fees for
various services to the Partnerships as well as a reimbursement for
property acquisition and development costs incurred on behalf of the
Partnerships and general and administrative overhead, which is reported
in the statements of operations as administrative revenue.

Due to related parties at December 31, 2001 and 2000 primarily
represent receipts collected by the Company, as agent, from oil and gas
sales net of expenses. The amount of such receipts due the

F-16

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued

----------

affiliated Partnerships was $983,000 and $1,265,000 at December 31,
2001 and 2000, respectively. Receivables from related parties consist
of reimbursable general and administrative costs, lease operating
expenses and reimbursements for property acquisitions, development, and
related costs.

Treasury stock purchases in 2001 and 2000 included shares acquired from
related parties. Purchases from related parties include a total of
228,800 shares purchased for a total consideration of $1,676,000 in
2001, and 40,700 shares purchased for a total consideration of $276,900
in 2000.

12. RESTRICTED CASH AND CASH EQUIVALENTS

Restricted cash and cash equivalents includes $1,174,000 and $1,128,000
at December 31, 2001 and 2000, respectively, of cash primarily
pertaining to unclaimed royalty payments. There were corresponding
accounts payable recorded at December 31, 2001 and 2000 for these
liabilities.

13. SALARY DEFERRAL PLAN

The Company maintains a salary deferral plan (the "Plan") in accordance
with Internal Revenue Code Section 401(k), as amended. The Plan
provides for discretionary and matching contributions which
approximated $255,000 and $226,000 in 2001 and 2000, respectively.

14. ACCOUNTS PAYABLE

A summary of accounts payable at December 31, 2001 and 2000 is as
follows:

15. EARNINGS PER SHARE

Basic earnings per share are computed by dividing earnings available to
common stockholders by the weighted average number of common shares
outstanding during the period. Diluted earnings per share reflect per
share amounts that would have resulted if dilutive potential common
stock had been converted to common stock. The following reconciles
amounts reported in the financial statements:

F-17

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued

----------

(1) For the year ended December 31, 1999, the number of options
excluded from diluted loss per common share calculations was
706,604 as the conversion of these would have had an anti-dilutive
effect on net loss per share.

16. SUBSEQUENT EVENTS

In February of 2002, the Company reached a settlement regarding a claim
for additional drilling costs incurred by the Company as a result of a
third party's negligence. The $350,000 received in regard to this claim
will be recognized as income in the first quarter of 2002.

17. SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

F-18

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued

----------

F-19

PRIMEENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION

----------

(UNAUDITED)

F-20

PRIMEENERGY CORPORATION and SUBSIDIARIES

CAPITALIZED COSTS RELATING to OIL and GAS PRODUCING ACTIVITIES

December 31, 2001, 2000 and 1999

----------

(Unaudited)

COSTS INCURRED in OIL and GAS PROPERTY ACQUISITION,
EXPLORATION and DEVELOPMENT ACTIVITIES

Years ended December 31, 2001, 2000 and 1999

----------

(Unaudited)

See accompanying notes to supplementary information.

F-21

PRIMEENERGY CORPORATION and SUBSIDIARIES

STANDARDIZED MEASURE of DISCOUNTED FUTURE
NET CASH FLOWS RELATING to PROVED OIL and GAS RESERVES

Years ended December 31, 2001, 2000 and 1999

----------

(Unaudited)

See accompanying notes to supplementary information.

F-22

PRIMEENERGY CORPORATION and SUBSIDIARIES

STANDARDIZED MEASURE of DISCOUNTED FUTURE
NET CASH FLOWS and CHANGES THEREIN RELATING
to PROVED OIL and GAS RESERVES

Years ended December 31, 2001, 2000 and 1999

----------

(Unaudited)

The following are the principal sources of change in the standardized measure of
discounted future net cash flows during 2001, 2000 and 1999:

See accompanying notes to supplementary information

F-23

PRIMEENERGY CORPORATION and SUBSIDIARIES

RESERVE QUANTITY INFORMATION

Years ended December 31, 2001, 2000 and 1999

----------

(Unaudited)

See accompanying notes to supplementary information

F-24

PRIMEENERGY CORPORATION and SUBSIDIARIES

RESULTS of OPERATIONS from OIL and GAS PRODUCING ACTIVITIES

Years ended December 31, 2001, 2000 and 1999

----------

(Unaudited)

See accompanying notes to supplementary information

F-25

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to SUPPLEMENTARY INFORMATION

----------

(Unaudited)

1. PRESENTATION OF RESERVE DISCLOSURE INFORMATION

Reserve disclosure information is presented in accordance with the
provisions of Statement of Financial Accounting Standards No. 69 ("SFAS
69"), "Disclosures About Oil and Gas Producing Activities".

2. DETERMINATION OF PROVED RESERVES

The estimates of the Company's proved reserves were determined by an
independent petroleum engineer in accordance with the provisions of
SFAS 69. The estimates of proved reserves are inherently imprecise and
are continually subject to revision based on production history,
results of additional exploration and development and other factors.
Estimated future net revenues were computed by reserves, less estimated
future development and production costs based on current costs.

3. RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES

The results of operations from oil and gas producing activities were
prepared in accordance with the provisions of SFAS 69. General and
administrative expenses, interest costs and other unrelated costs are
not deducted in computing results of operations from oil and gas
activities.

4. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES
THEREIN RELATING TO PROVED OIL AND GAS RESERVES

The standardized measure of discounted future net flows relating oil
and gas reserves and the changes of standardized measure of discounted
future net cash flows relating to proved oil and gas reserves were
prepared in accordance with the provisions of SFAS 69.

Future cash inflows are computed as described in Note 2 by applying
current prices to year-end quantities of proved reserves.

Future production and development costs are computed estimating the
expenditures to be incurred in developing and producing the oil and gas
reserves at year-end, based on year-end costs and assuming continuation
of existing economic conditions.

Future income tax expenses are calculated by applying the year-end U.S.
tax rate to future pre-tax cash inflows relating to proved oil and gas
reserves, less the tax basis of properties involved. Future income tax
expenses give effect to permanent differences and tax credits and
allowances relating to the proved oil and gas reserves.

Future net cash flows are discounted at a rate of 10% annually
(pursuant to SFAS 69) to derive the standardized measure of discounted
future net cash flows. This calculation does not necessarily represent
an estimate of fair market value or the present value of such cash
flows since future prices and costs can vary substantially from
year-end and the use of a 10% discount figure is arbitrary.

F-26

EXHIBIT INDEX

- ----------

(1) Management contract or compensatory plan or arrangement required to be
filed as an Exhibit to this Form 10-K.