<PAGE>   1

                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

                                   ----------

                                   FORM 10-KSB
(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, 2000

                                       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-KSB or any amendment to
this Form 10-KSB.

     The Registrant's revenues for its most recent fiscal year were $39,182,000.

     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 21, 2001, was $5,505,258.

     The number of shares outstanding of each class of the Registrant's Common
Stock as of March 21, 2001 was: Common Stock, $0.10 par value, 3,886,511.

                       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, 2001, are incorporated by reference in Part III hereof.

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



<PAGE>   2

                             PRIMEENERGY CORPORATION

                            FORM 10-KSB ANNUAL REPORT
                            FOR THE FISCAL YEAR ENDED
                                DECEMBER 31, 2000

                                     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 47 oil
and gas limited partnerships (the "Partnerships") of which five 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 and Eastern Oil Well Service 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, primarily
in Texas, Oklahoma and West Virginia. In addition, through a subsidiary,
Southwest Oilfield Construction Company, the Company provides 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 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 12% of
the net revenues of each Partnership and Trust as a carried interest in the
Partnership's and Trust's properties.

       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 5,900. 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 oil
and gas wells in which the Partnerships and Trusts have interests.

       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
<PAGE>   3

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 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
1,603 oil and gas wells, 448 through the Houston office, 179 through the Midland
office, 475 through the Oklahoma City office and 501 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's focus is on the acquisition and development of producing
oil and gas properties. The Company will continue to engage in exploratory
operations and will continue to engage in 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

       In the year 2000, the Company operated and participated in the re-entry
of the S.R. Bridge No. 2 well located in Bee County, Texas. The well tested
various sand intervals from 8,741' to 9,410' and established economical gas
production in October of 2000 with a rate of 168 (94 net) Mcf of gas per day.
The Company owns a 72.59% working interest and a 55.88% net revenue interest in
this well.

       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.

       In April of 2000, the JJJ Ranch No. 1 well was drilled by Rio Exploration
Company in the Las Tiendas field of Webb County, Texas under a farmout of the
Company's 53.2% working interest. The Company retained an Overriding Royalty
Interest, a 15.96% back-in working interest after payout, and the right to
operate the producing well. This well was drilled to 3,815' and completed in the
upper Wilcox Formation with an initial production rate of 1,017 (148 net) Mcf
per day of dry gas. The well was subsequently dually completed into another sand
in the upper Wilcox Formation. The Company owns a 14.63% net revenue interest in
this well.

       In May of 2000, the Company operated the drilling of the Brooks Trust No.
1 well located in the Cadiz field of Bee County, Texas. The well was drilled to
a total depth of 9,499 feet and completed in the Luling Sand of the Wilcox
Formation at a production rate of 1,700 (704 net) Mcf of gas per day and 10
(4.14 net) barrels of condensate per day on a 9/64" choke with flowing tubing
pressure of 2,650 lbs. The Company owns a 52.94 % working interest and 42.35%
net revenue interest in this well.

       Also in May of 2000, the Company re-entered and re-drilled the Gott No. 1
well of the East Wakita Prospect in Grant County, Oklahoma. The well was drilled
to a total depth of 4,730'. Production casing was set and and a completion
attempt was made in the Red Fork Formation. The well began selling gas in August
at an initial rate of 1,857 (1,263 net) Mcf of dry gas per day with a flowing
tubing pressure of 1,475 lbs. The Company participated for a 85% working
interest with a before payout net revenue interest of 68%. After payout, the
Company's interest changed to a 79.69% working interest and 63.75% net revenue
interest.

       In June of 2000, the JJJ Ranch No. 2 well was drilled by Rio Exploration
Company in the Las Tiendas field of Webb County, Texas. The well was drilled to
a total depth of 3,804' and dually completed in the upper Wilcox Formation for
1,340 (270 net) Mcf per day of dry gas. The Company participated for a 13.3%
working interest and retained an overriding royalty interest and back-in
interest. The Company currently operates the well and owns a 25.27% working
interest and 20.12% net revenue interest.

       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.



                                       2
<PAGE>   4

       In July of 2000, the Company re-entered the A.A. Uribe No. 1 well located
in the JJ&J field of Zapata County, Texas. The well was cleaned out and
production re-established in the Wilcox 9,000' Sand at a production rate of 405
(240 net) Mcf of gas per day and three (1.77 net) barrels of condensate with a
flowing tubing pressure of 900 lbs. The Company owns a 69% working interest and
51.75% net revenue interest in this well.

       In August of 2000, the Company operated the drilling of the Brooks Trust
No. 2 well located in the Cadiz field of Bee County, Texas. The well was drilled
to a total depth of 9,299 feet and was completed in the Slick Sand of the Wilcox
Formation. The Initial production rate was 400 (165 net) Mcf of gas per day and
7 (2.9 net) barrels of oil with a flowing tubing pressure of 45 lbs. The Company
owns a 51.80% working interest and 42.53% net revenue interest in this well.

       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.

       Also in September of 2000, the Company conducted a re-entry operation of
the LeBlanc No. 1 well. A fracture stimulation attempt in November of 2000
failed to achieve a sustainable gas completion; however, in March of 2001, the
Company conducted a successful acid treatment. The well is currently testing gas
at approximately 340 (245 net) Mcf of gas and 155 barrels of water per day with
a flowing tubing pressure of 1,860 lbs. The Company owns a 83.08% working
interest and 72% net revenue interests in this well.

       In October of 2000, the Company participated for a 16.88 % working
interest in the drilling of the OCS-G 21141 No. 1 well operated by I. P.
Petroleum Corporation and located in Main Pass Block 114 of the offshore federal
waters of the Gulf of Mexico. The well was drilled as a straight hole to a total
depth of 12,005'. Gas cores and log analysis indicated a possible accumulation
of hydrocarbon. Production pipe was run and a completion attempt failed to
establish economical production. The well was plugged and abandoned as a dry
hole.

       Also in October of 2000, the Company participated for a 10.74% working
interest in the drilling of the OCS-G 21534 No. 1 well operated by I. P.
Petroleum Corporation and located in West Cameron Block 57 of the offshore
federal waters of the Gulf of Mexico. The well was drilled as a straight hole to
a total depth of 11,500'. The objective sand was encountered, but no
accumulation of hydrocarbon was found. The well was plugged and abandoned as a
dry hole.

       In November of 2000, the Company began its participation in the drilling
and testing of the Bear Creek Unit No. 1A well operated by McMurry Energy and
located in Sec. 26 Township 38 North, Range 75 West of Converse County, Wyoming.
The well was drilled to a total depth of 11,117'. Production pipe has been run
and a completion of the Shannon Formation is in progress. The prospective
formation was perforated and fracture stimulated and is presently swab testing
oil while production facilities are being installed. The company' owns a 21.75%
working interest and an 18.79 % net revenue interest in this property.

       In December of 2000, the Company participated for a 26.60% working
interest in the drilling of the Rio Exploration Company JJJ Ranch No. 3 well
located in the Las Tiendas field of Webb County, Texas. The well was drilled to
a total depth of 3,460 feet and dually completed in the upper Wilcox Formation
for an initial rate of 1,263 (327 net) Mcf of dry gas per day. The Company
retained an overriding royalty interest and a back-in interest. The well has
paid out and the Company now operates the well with a 34.58% working interest
and a 28.59% net revenue interest.

       In January of 2001, the Company operated the drilling of the Devore
Foundation No. 1 well of the East Wakita Prospect in Grant County, Oklahoma. The
well was drilled to a total depth of 4,906' and logged. No economical
accumulation of hydrocarbon was encountered and the well was plugged and
abandoned as a dry hole. The Company's working interest participation in this
well was 80.48%.

       Also in January of 2001, the Company operated the drilling of the ANI No.
1 well located in Calhoun County, Texas. The well was drilled to a total depth
of 5,050 feet and was unsuccessful in discovering economical quantities of gas.
The well was plugged and abandoned as a dry hole. The Company participated for
40% of the project drilling cost.

       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 6 of the Financial Statements. During 2000, the
Company purchased such interests in an amount totaling $1,257,000.

       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



                                       3
<PAGE>   5

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.

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 8 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.



                                       4
<PAGE>   6

COMPETITION AND MARKETS

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

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

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

<TABLE>
<S>                                         <C>
        Unimark LLC                         23.85%
        Texon Distributing L.P.             18.55%
        El Paso Energy Marketing            11.76%
        Plains All American Inc.            10.82%
</TABLE>

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

ENVIRONMENTAL MATTERS

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

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

       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.



                                       5
<PAGE>   7

       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 21, 2001, the Company had 179 full-time and 17 part-time
employees, 22 of whom were employed by the Company at its principal offices in
Stamford, Connecticut, 24 in Houston, Texas, at the offices of Prime Operating
Company and Eastern Oil Well Service Company, and 150 employees who were
primarily involved in the district operations of the Company in Houston and
Midland, Texas, Oklahoma City, Oklahoma and Charleston, West Virginia.

ITEM 2. 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 and Eastern Oil Well
Service 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, 2000.



                                       6
<PAGE>   8

<TABLE>
<CAPTION>
                             2000              1999              1998              1997              1996
                        --------------    --------------    --------------    --------------    --------------
                        Gross     Net     Gross     Net     Gross     Net     Gross     Net     Gross     Net
                        -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
<S>                     <C>      <C>      <C>     <C>       <C>     <C>       <C>      <C>      <C>     <C>
Exploratory:
    Oil                    --       --        1     .300        1     .468       --       --       --       --
    Gas                     3    1.279        1     .683        2     .387        2       .8       --       --
    Dry                     2     .276        2     .510        2     .686        2     .509        1        1
Development:
    Oil                    --       --       --       --        1     .145        5     .796        3     .740
    Gas                     7    4.134        2     .015        5     .316        5    2.037       17    1.292
    Dry                    --       --        2     .745       --       --        3    1.030        1     .371
Total:
    Oil                    --       --        1     .300        2     .613        5     .796        3     .740
    Gas                    10    5.413        3     .698        7     .703        7    2.837       17    1.292
    Dry                     2     .276        4    1.255        2     .686        5    1.539        2    1.371
                        -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
                           12    5.689        8    2.253       11    2.002       17    5.172       22    3.403
                        =====    =====    =====    =====    =====    =====    =====    =====    =====    =====
</TABLE>

OIL AND GAS PRODUCTION

       As of December 31, 2000, the Company had ownership interests in the
following numbers of gross and net producing oil and gas wells and gross and net
producing acres (1).

<TABLE>
<CAPTION>
       Producing wells (1):                                               Gross           Net
                                                                        ----------     ----------
<S>                                                                     <C>           <C>
           Oil Wells ..............................................          1,010         192.90
           Gas Wells ..............................................          1,208         183.27
       Producing Acres ............................................        296,876         66,206

</TABLE>

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

       The following table shows the Company's net production of crude oil and
natural gas for each of the five years ended December 31, 2000. "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.

<TABLE>
<CAPTION>
                                                          2000           1999           1998           1997           1996
                                                       ----------     ----------     ----------     ----------     ----------
<S>                                                    <C>            <C>            <C>            <C>            <C>
Oil (barrels)  ...................................        298,000        264,000        277,000        277,000        249,000
Gas (Mcf) ........................................      3,930,000      3,289,000      3,621,000      3,901,000      2,888,000
</TABLE>

       The following table sets forth the Company's average sales price per
barrel of crude oil and average sales prices per one thousand cubic feet ("Mcf")
of gas, together with the Company's average production costs per unit of
production for the five years ended December 31, 2000.

<TABLE>
<CAPTION>
                                                     2000           1999           1998           1997           1996
                                                  ----------     ----------     ----------     ----------     ----------
<S>                                               <C>            <C>            <C>            <C>            <C>
Average sales price
   per barrel ...............................     $    28.34          15.71          12.39          19.35          21.11

Average sales price
   Per Mcf ..................................     $     3.76           2.32           2.19           2.57           2.36

Average production
  costs per net equivalent
  barrel (1) ................................     $     9.57           7.76           7.60           7.59           8.09
</TABLE>

----------

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

UNDEVELOPED ACREAGE

         The following table sets forth the approximate gross and net
undeveloped acreage in which the Company has leasehold, mineral and royalty
interests as of December 31, 2000. "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.



                                       7
<PAGE>   9

<TABLE>
<CAPTION>
                               Leasehold                  Mineral                   Royalty
                               Interests                 Interests                 Interests
                         ---------------------     ---------------------     ---------------------
                          Gross         Net         Gross         Net         Gross         Net
         State            Acres        Acres        Acres        Acres        Acres        Acres
         -----           --------     --------     --------     --------     --------     --------
<S>                      <C>          <C>         <C>           <C>          <C>          <C>

Colorado                       --           --          799           23           --           --
Louisiana                       8            1           --           --           --           --
Montana                        --           --       13,984           59          786            5
Nebraska                       --           --        2,553          331           --           --
North Dakota                   --           --          640            1           --           --
Oklahoma                    2,228        1,794          320            1           --           --
Texas                      15,919        5,376          680           16           --           --
Wyoming                     1,000          125         5043           35          140           35
                         --------     --------     --------     --------     --------     --------
TOTAL                      19,155        7,296       24,019          466          926           40
                         ========     ========     ========     ========     ========     ========
</TABLE>

RESERVES

         The Company's interests in proved developed and undeveloped oil and gas
properties have been evaluated by Ryder Scott & Company L.P. for the years ended
December 31, 1996, 1997, 1998, 1999 and 2000. All of the Company's reserves are
located within the continental United States. The following table summarizes the
Company's oil and gas reserves at each of the respective dates (figures
rounded):

<TABLE>
<CAPTION>
                                            Reserve Category
                      ---------------------------------------------------------------
                            Proved Developed                 Proved Undeveloped                      Total
                      -----------------------------     -----------------------------     -----------------------------
        As of             Oil              Gas              Oil              Gas              Oil              Gas
        12-31            (bbls)           (Mcf)            (bbls)           (Mcf)            (bbls)           (Mcf)
        -----         ------------     ------------     ------------     ------------     ------------     ------------

<S>                   <C>             <C>                <C>             <C>              <C>             <C>
        1996             1,453,000       19,036,000           13,000           29,000        1,466,000       19,065,000
        1997             1,364,000       16,661,000           77,000               --        1,441,000       16,661,000
        1998             1,122,000       17,341,000           78,000               --        1,200,000       17,341,000
        1999             2,110,000       22,046,000               --          156,000        2,110,000       22,202,000
        2000             2,362,000       27,029,000               --               --        2,362,000       27,029,000
</TABLE>

         The estimated future net revenue (using current prices and costs as of
those dates, exclusive of income taxes) and the present value of future net
revenue (at a 10% discount for estimated timing of cash flow) for the Company's
proved developed and proved undeveloped oil and gas reserves at the end of each
of the five years ended December 31, 2000, are summarized as follows (figures
rounded):

<TABLE>
<CAPTION>
                           Proved Developed                  Proved Undeveloped                      Total
                      -----------------------------     -----------------------------     -----------------------------
                                      Present Value                     Present Value                     Present Value
       As of           Future Net       Of Future        Future Net       Of Future        Future Net       Of Future
       12-31            Revenue        Net Revenue        Revenue        Net Revenue        Revenue        Net Revenue
       -----          ------------    -------------     ------------    -------------     ------------    -------------
<S>                   <C>             <C>               <C>             <C>               <C>             <C>

        1996          $ 51,077,000       35,025,000          273,000          167,000       51,350,000       35,192,000
        1997          $ 30,056,000       21,306,000          833,000          531,000       30,889,000       21,837,000
        1998          $ 20,839,000       13,444,000          359,000          212,000       21,198,000       13,656,000
        1999          $ 41,103,000       26,057,000          258,000          151,000       41,361,000       26,208,000
        2000          $199,376,000      113,137,000               --               --      199,376,000      113,137,000
</TABLE>

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

         In accordance with FASB Statement No. 69, December 31, 2000 market
prices were 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, 2000 were not considered. The spot
price for gas at December 31, 2000 was $9.23 per MMBTU. The range of spot prices
during the year 2000 was a low of $2.14 and a high of $10.50 and the average was
$4.28. The range during the first quarter of 2001 has been from $4.67 to $10.69
with an average of $6.42. The recent futures market prices have been in the
$5.00 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, 2001, 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,



                                       8
<PAGE>   10

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.

         Neither the Company nor any of its subsidiaries is a party to, nor is
any of their property the subject of, any material pending legal proceedings.

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, 2000, 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, 2000, were as follows:

<TABLE>
<CAPTION>
              1999                                High       Low
              ----                               ------     ------
<S>                                              <C>        <C>

First Quarter ..............................     $ 5.59     $ 5.32

Second Quarter .............................       4.94       4.74

Third Quarter ..............................       5.13       5.08

Fourth Quarter .............................       4.93       4.82
</TABLE>

<TABLE>
<CAPTION>
              2000                                High       Low
              ----                               ------     ------
<S>                                              <C>        <C>

First Quarter ..............................     $ 4.91     $ 4.83

Second Quarter .............................       4.56       4.40

Third Quarter ..............................       5.84       5.78

Fourth Quarter .............................       7.38       7.23
</TABLE>

         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 22, 2001 was 1,085.

         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. 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

         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 2000 and 1999 were 9.46% and 7.48%,
respectively. During the same periods, the average rates paid on outstanding
borrowings bearing interest based upon the LIBO rate were 8.46% and 7.34%. As of
December 31, 2000 and 1999, the total outstanding borrowings were $17.2 million
and $19.2 million, respectively, with an additional $1.75 million and $3.45
million available, and $13.5 million and $15.5 million 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.

         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 interests in, and was the operator of, the majority of the
properties purchased. The Company paid $1,813,000 for the properties, and under
terms of the agreement, must pay additional



                                       9
<PAGE>   11

compensation to the seller to the extent that the cash flow generated by the
properties purchased exceeds the purchase price in the first three years after
the sale. The Company currently estimates that $1,850,000 will be due under this
agreement, to be paid in 2001 and 2002. Such amount has been accrued by the
Company and included in oil and gas properties.

         In total, $9,933,000 was spent on the acquisition and development of
oil and gas properties in 2000, including $1,257,000 spent to repurchase limited
partnership interests from investors in its oil and gas Partnerships.

         The Company spent $1,582,000 on field service equipment in 2000, and an
additional $107,000 on computers, software, and related equipment. The Company
spent $1,323,000 to repurchase shares of its treasury stock in 2000. As of the
date of this report the Company spent an additional $1,624,000 on treasury stock
purchases in 2001.

         Most 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 of oil and gas prospects, and
oil and gas business opportunities in general.

RESULTS OF OPERATIONS:

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

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

<TABLE>
<CAPTION>
                                                2000             1999           Increase
                                            ------------     ------------     ------------
<S>                                         <C>              <C>              <C>

         Barrels of Oil Produced                 297,562          263,980           33,582
         Average Price Received             $    28.3354     $    15.7111     $    12.6243
                                            ------------     ------------     ------------
               Oil Revenue                  $  8,432,000     $  4,147,000     $  4,285,000
                                            ------------     ------------     ------------

           Mcf of Gas Produced                 3,929,532        3,289,463          640,069
         Average Price Received             $     3.7641     $     2.3153     $     1.4488
                                            ------------     ------------     ------------
               Gas Revenue                  $ 14,791,000     $  7,616,000     $  7,175,000
                                            ------------     ------------     ------------

         Total Oil & Gas Revenue            $ 23,223,000     $ 11,763,000     $ 11,460,000
                                            ============     ============     ============
</TABLE>

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

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

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

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

         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.



                                       10
<PAGE>   12

         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.

         General and administrative expenses increased 28% to $4,033,0000 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. The Company drilled 2
dry holes in the first quarter of 2001, on which it expects to recognize expense
of approximately $285,000.

         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.



                                       11
<PAGE>   13

         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 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 7.  FINANCIAL STATEMENTS.

         Included on pages F-1 through F-24 of this Report. The Index to
Financial Statements is at page F-1 of this Report.

ITEM 8.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURE.

         None.

                                    PART III

ITEM 9.  DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS;
         COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT.

         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,
2001, which will be filed with the Securities and Exchange Commission within 120
days of December 31, 2000, and which is incorporated herein by reference.

ITEM 10. 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, 2001, which will be filed with the Securities
and Exchange Commission within 120 days of December 31, 2000, and which is
incorporated herein by reference.

ITEM 11. 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, 2001, which
will be filed



                                       12
<PAGE>   14

with the Securities and Exchange Commission within 120 days of December 31,
2000, and which is incorporated herein by reference.

ITEM 12. 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,
2001, which will be filed with the Securities and Exchange Commission within 120
days of December 31, 2000, and which is incorporated herein by reference.

                                     PART IV

ITEM 13. EXHIBITS 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)

       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)



                                       13
<PAGE>   15

       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-KSB.

         (a)      Reports on Form 8-K:

                  None




                                       14
<PAGE>   16

                                   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, 2001.

                                        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, 2001.

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

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

/s/ SAMUEL R. CAMPBELL            Director
-----------------------------
Samuel R. Campbell

/s/ JAMES E. CLARK                Director
-----------------------------
James E. Clark

/s/ MATTHIAS ECKENSTEIN           Director
-----------------------------
Matthias Eckenstein

/s/ H. GIFFORD FONG               Director
-----------------------------
H. Gifford Fong

                                  Director
-----------------------------
Thomas S.T. Gimbel

/s/ CLINT HURT                    Director
-----------------------------
Clint Hurt

                                  Director
-----------------------------
Robert de Rothschild

/s/ JARVIS K. SLADE               Director
-----------------------------
Jarvis J. Slade

/s/ JAN K. SMEETS                 Director
-----------------------------
Jan K. Smeets

/s/ GAINES WEHRLE                 Director
-----------------------------
Gaines Wehrle

/s/ MICHAEL WEHRLE                Director
-----------------------------
Michael Wehrle
</TABLE>



                                       15
<PAGE>   17

                          INDEX TO FINANCIAL STATEMENTS

<TABLE>
<S>                                                                                                                <C>
      Financial Statements (Included herein at pages F-1 through F-24):

      Report of Independent Public Accountants                                                                     F-2

      Financial Statements:

             Consolidated Balance Sheets -- December 31, 2000 and 1999                                             F-3

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

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

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

             Notes to Consolidated Financial Statements                                                            F-8

             Supplementary Information:                                                                            F-18

                      Capitalized Costs Relating to Oil and Gas Producing Operations,
                      December 31, 2000 and 1999                                                                   F-19

                      Costs Incurred in Oil and Gas Property Acquisition, Exploration and
                      Development Activities, years ended December 31, 2000 and 1999                               F-19

                      Standardized Measure of Discounted Future Net Cash Flows Relating
                      to Proved Oil and Gas reserves, years ended December 31, 2000 and 1999                       F-20

                      Standardized Measure of Discounted Future Net Cash Flows and Changes
                      Therein Relating to Proved Oil an Gas Reserves, years ended December 31,
                      2000 and 1999                                                                                F-21

                      Reserve Quantity Information, years ended December 31, 2000 and 1999                         F-22

                      Results of Operations from Oil and Gas Producing Activities, years
                      ended December 31, 2000 and 1999                                                             F-22

                      Notes to Supplementary Information                                                           F-24
</TABLE>




                                      F-1
<PAGE>   18

                         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, 2000 and 1999, 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, 2000 and 1999, and the
consolidated results of their operations and their cash flows for the years then
ended, in conformity with generally accepted accounting principles.

 /s/ PUSTORINO, PUGLISI & CO., LLP
Pustorino, Puglisi & Co., LLP
New York, New York
March 30, 2001




                                      F-2
<PAGE>   19

                    PrimeEnergy Corporation and Subsidiaries

             Consolidated Balance Sheets, December 31, 2000 and 1999


<TABLE>
<CAPTION>
                                                                2000              1999
                                                            ------------      ------------
<S>                                                         <C>               <C>
ASSETS:
Current assets:
     Cash and cash equivalents                              $    684,000      $  1,771,000
     Restricted cash and cash
        equivalents (Note 11)                                  1,128,000         1,854,000
     Accounts receivable, net (Note 3)                         5,663,000         3,635,000
     Due from related parties (less allowance for
        doubtful accounts of $800,000 in 2000
        and 1999) (Note 10)                                    4,346,000         2,844,000
     Prepaid expenses                                            134,000            84,000
     Other current assets                                        112,000           204,000
     Deferred income taxes (Notes 1 and 8)                       155,000                --
                                                            ------------      ------------
         Total current assets                                 12,222,000        10,392,000
                                                            ------------      ------------

Property and equipment, at cost (Notes 1 and 2):
     Oil and gas properties (successful
       efforts method):
         Proved                                               57,439,000        49,249,000
         Unproved                                                159,000           235,000
     Furniture, fixtures and equipment
       including leasehold improvements                        7,433,000         6,395,000
                                                            ------------      ------------
                                                              65,031,000        55,879,000
     Accumulated depreciation, depletion and
       amortization                                          (42,361,000)      (36,742,000)
                                                            ------------      ------------
       Net property and equipment                             22,670,000        19,137,000
                                                            ------------      ------------

Other assets (Note 10)                                           202,000           621,000
Due from affiliates (Note 10)                                         --           325,000
                                                            ------------      ------------
       Total assets                                         $ 35,094,000      $ 30,475,000
                                                            ============      ============
</TABLE>


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



                                      F-3
<PAGE>   20

                    PrimeEnergy Corporation and Subsidiaries

             Consolidated Balance Sheets, December 31, 2000 and 1999


<TABLE>
<CAPTION>
                                                                               2000              1999
                                                                           ------------      ------------
<S>                                                                        <C>               <C>
LIABILITIES and STOCKHOLDERS' EQUITY:
Current liabilities:
     Accounts payable (Note 13)                                            $  6,828,000      $  7,900,000
     Current portion of other long-term obligations (Notes 5 and 6)             854,000             4,000
     Accrued liabilities:
       Payroll, Benefits and Related Items                                      934,000           798,000
       Taxes (Notes 1 and 8)                                                    455,000            53,000
       Interest and other                                                     1,058,000           626,000
     Due to related parties (Note 10)                                         1,265,000           943,000
                                                                           ------------      ------------
       Total current liabilities                                             11,394,000        10,324,000
                                                                           ------------      ------------

Long-term bank debt (Note 4)                                                 17,200,000        19,200,000
Other long term obligations (Notes 5 and 6)                                   1,013,000            17,000
Deferred income taxes (Notes 1 and 8)                                           511,000                --
                                                                           ------------      ------------
       Total liabilities                                                     30,118,000        29,541,000
                                                                           ------------      ------------

Stockholders' equity:
     Preferred stock, $.10 par value, authorized
       5,000,000 shares; none issued                                                 --                --
     Common stock, $.10 par value, authorized
       10,000,000; issued 7,607,970                                             761,000           761,000
     Paid in capital                                                         10,902,000        10,902,000
     Retained Earnings (accumulated deficit)                                  2,506,000        (2,859,000)
                                                                           ------------      ------------
                                                                             14,169,000         8,804,000
     Treasury stock, at cost, 3,488,942
       common shares in 2000 and 3,266,063
       common shares in 1999                                                 (9,193,000)       (7,870,000)
                                                                           ------------      ------------
       Total stockholders' equity                                             4,976,000           934,000
                                                                           ------------      ------------
         Total liabilities and equity                                      $ 35,094,000      $ 30,475,000
                                                                           ============      ============
</TABLE>


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


                                      F-4
<PAGE>   21

                    PrimeEnergy Corporation and SUBSIDIARIES

                      Consolidated Statements of Operations

                 for the years ended December 31, 2000 and 1999

<TABLE>
<CAPTION>
                                                                           2000             1999
                                                                       ------------     ------------
<S>                                                                    <C>              <C>
Revenue:
     Oil and gas sales                                                 $ 23,223,000     $ 11,763,000
     District operating income                                           13,585,000       11,407,000
     Administrative revenue (Note 10)                                     1,655,000        1,673,000
     Reporting and management fees (Note 10)                                321,000          319,000
     Interest income                                                        169,000          146,000
     Other income                                                           229,000          212,000
                                                                       ------------     ------------
                                                                         39,182,000       25,520,000
                                                                       ------------     ------------

Costs and expenses:
     Lease operating expense                                              9,114,000        6,305,000
     District operating expense                                          11,235,000        8,671,000
     Depreciation and depletion of
       oil and gas properties                                             5,060,000        4,581,000
     Impairment of oil and gas properties (Note 1)                          295,000        2,703,000
     General and administrative expense                                   4,033,000        3,149,000
     Exploration costs                                                    1,797,000          869,000
     Interest expense (Note 4)                                            1,500,000        1,358,000
                                                                       ------------     ------------
                                                                         33,034,000       27,636,000
                                                                       ------------     ------------
     Income (loss) from operations                                        6,148,000       (2,116,000)

Other income:
Gain on sale and exchange of assets                                          28,000            8,000
                                                                       ------------     ------------
     Income (loss) before provision (benefit) for income taxes            6,176,000       (2,108,000)

Provision for income taxes                                                  811,000           30,000
                                                                       ------------     ------------
     Net income (loss)                                                 $  5,365,000     $ (2,138,000)
                                                                       ============     ============


Basic net income (loss) per common share (Notes 1 and 14)              $       1.26     $      (0.48)
                                                                       ============     ============
Diluted net income (loss) per common share (Notes 1 and 14)            $       1.08     $      (0.48)
                                                                       ============     ============
</TABLE>


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


                                      F-5
<PAGE>   22

                    PrimeEnergy Corporation and SUBSIDIARIES

                 Consolidated Statement of Stockholders' Equity

                 for the years ended December 31, 2000 and 1999


<TABLE>
<CAPTION>
                                                                                      Retained
                                                                     Additional       Earnings
                                           Common Stock                Paid In      (Accumulated      Treasury
                                     Shares           Amount           Capital        Deficit)          Stock             Total
                                  ------------     ------------     ------------    ------------     ------------     ------------
<S>                               <C>             <C>              <C>             <C>              <C>              <C>

Balance at December 31, 1998         7,607,970          761,000       10,902,000        (721,000)      (7,323,000)       3,619,000

Purchased 107,687 shares of
 common stock                                                                                            (547,000)        (547,000)

Net loss                                                                              (2,138,000)                       (2,138,000)
                                  ------------     ------------     ------------    ------------     ------------     ------------
Balance at December 31, 1999         7,607,970          761,000       10,902,000      (2,859,000)      (7,870,000)         934,000

Purchased 222,879 shares of
 common stock                                                                                          (1,323,000)      (1,323,000)

Net income                                                                             5,365,000                         5,365,000
                                  ------------     ------------     ------------    ------------     ------------     ------------
Balance at December 31, 2000         7,607,970     $    761,000     $ 10,902,000    $  2,506,000     ($ 9,193,000)    $  4,976,000
                                  ============     ============     ============    ============     ============     ============
</TABLE>


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


                                      F-6
<PAGE>   23

                    PrimeEnergy Corporation and SUBSIDIARIES

                      Consolidated StatementS of CASH FLOWS

                 for the years ended December 31, 2000 and 1999

                                   ----------

<TABLE>
<CAPTION>
                                                                                   2000              1999
                                                                               ------------      ------------
<S>                                                                            <C>               <C>

Cash flows from operating activities:
     Net income (loss)                                                         $  5,365,000      $ (2,138,000)
     Adjustments to reconcile net loss to net cash provided
       by operating activities:
            Depreciation, depletion and amortization                              6,000,000         5,529,000
              Impairment of oil and gas properties                                  295,000         2,703,000
           Dry hole and abandonment costs                                         1,787,000           818,000
            Gain on sale of properties                                              (28,000)           (8,000)
            Provision (benefit) of deferred income taxes                            356,000           (39,000)
     Changes in assets and liabilities:
          (Increase) decrease in accounts receivable                             (2,028,000)         (745,000)
          (Increase) decrease in due from related parties                        (1,177,000)          108,000
          (Increase) decrease in other assets                                        36,000           120,000
          (Increase) decrease in prepaid expenses                                   (28,000)           (5,000)
          Increase (decrease) in accounts payable                                  (346,000)          811,000
          Increase in accrued liabilities                                           944,000           311,000
          Increase (decrease) in due to related parties                             322,000           212,000
                                                                               ------------      ------------
                 Net cash provided by operating activities                       11,498,000         7,677,000
                                                                               ------------      ------------

Cash flows from investing activities:
     Proceeds from sale of properties and equipment                                  71,000            59,000
     Additions to property and equipment                                        (11,632,000)       (9,308,000)
     Proceeds from payment on notes receivable                                      453,000            28,000
                                                                               ------------      ------------
           Net cash used in investing activities                                (11,108,000)       (9,221,000)
                                                                               ------------      ------------

Cash flows from financing activities:
     Purchase of stock for treasury                                              (1,323,000)         (547,000)
     Repayment of long-term bank debt and other long-term obligations           (27,844,000)      (25,770,000)
     Increase in long-term bank debt and other long-term obligations             27,690,000        28,465,000
                                                                               ------------      ------------
           Net cash provided by (used in) financing activities                   (1,477,000)        2,148,000
                                                                               ------------      ------------
           Net increase (decrease) in cash                                       (1,087,000)          604,000

Cash and cash equivalents, beginning of year                                      1,771,000         1,167,000
                                                                               ------------      ------------
Cash and cash equivalents, end of year                                         $    684,000      $  1,771,000
                                                                               ============      ============

Supplemental disclosures:
     Income taxes paid during the year                                         $     53,000      $         --
     Net income tax refunds received during the year                           $         --      $     84,000
     Interest paid during the year                                             $  1,462,000      $  1,367,000

Supplemental information of noncash investing and financing activities:
     In 1999, the Company recorded capital lease obligations in the
     amount of $22,000
</TABLE>


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


                                      F-7
<PAGE>   24

                    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
         47 private and publicly-held limited partnerships and 2 trusts
         (collectively, the "Partnerships"). PEC owns Eastern Oil Well Service
         Company ("EOWSC") and Southwest Oilfield Construction Company ("SOCC"),
         both 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. 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 1,603 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.

         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 acquisition of producing oil and gas properties on
         behalf of the Partnerships



                                      F-8
<PAGE>   25

         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.

         The net basis of assets are periodically compared to the expected
         future net revenue to be generated from the assets, and if the basis
         exceeds future net revenue, an impairment is recorded. In 2000 and
         1999, the Company recorded noncash impairment charges of $295,000 and
         $2,703,000, respectively. The 1999 impairment was recorded on the
         Company's Ramrod property, located in Matagorda County, Texas. The most
         significant well on this property, the Saint George #1, experienced
         significant mechanical difficulties in 1999 leading to a substantial
         reduction of estimated reserves. Additionally, significant sums were
         spent on drilling to develop this property in 1999, and although
         reserves were found, the drilling costs incurred greatly exceeded the
         value of those reserves. The carrying value of the property was written
         down to its fair market value, based on projected discounted future net
         cash flows, using the Company's estimates of future commodity prices.

         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.

         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.
         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.



                                      F-9
<PAGE>   26

         Recently Issued Accounting Standards:

         In June 1998, the Financial Accounting Standards Board issued Statement
         of Financial Accounting Standards No. 133 ("SFAS No. 133"), "Accounting
         for Derivative Instruments and Hedging Activities". The statement
         requires the recognition of all derivatives as either assets or
         liabilities in the balance sheet and the measurement of those
         instruments at fair value. The accounting for changes in the fair value
         of a derivative depends on the planned use of the derivative and the
         resulting designation. The adoption of SFAS No. 133 in 2000 did not
         have a significant impact on the Company's financial position, results
         of operations or cash flows.

         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.

2.       SIGNIFICANT  ACQUISITIONS AND DISPOSITIONS

         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 6, 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. The purchase price was $1,813,000, and the
         Company will pay an estimated $1,850,000 of additional contingent
         consideration based on the performance of the properties. Such amount
         has been accrued on the December 31, 2000 financial statements.

         As more fully described in Note 6, 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.



                                      F-10
<PAGE>   27

3        ACCOUNTS RECEIVABLE

         Accounts receivable at December 31, 2000 and 1999 consisted of the
         following:

<TABLE>
<CAPTION>
                                                                   December 31,
                                                          ------------------------------
                                                              2000              1999
                                                          ------------      ------------

<S>                                                       <C>               <C>
         Joint interest billing                           $  1,352,000      $  1,738,000
         Trade receivables                                     967,000           550,000
         Oil and gas sales                                   3,310,000         1,423,000
         Other                                                 180,000            61,000
                                                          ------------      ------------
                                                             5,809,000         3,772,000
            Less, allowance for doubtful accounts             (146,000)         (137,000)
                                                          ------------      ------------
                                                          $  5,663,000      $  3,635,000
                                                          ============      ============
</TABLE>

4        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 2000 and 1999 were 9.46% and
         7.48%, respectively. During the same periods, the average rates paid on
         outstanding borrowings bearing interest based upon the LIBO rate were
         8.46% and 7.34%. As of December 31, 2000 and 1999, the total
         outstanding borrowings were $17.2 million and $19.2 million,
         respectively, with an additional $1.75 million and $3.45 million
         available, and $13.5 million and $15.5 million 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.

5.       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-11
<PAGE>   28

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

<TABLE>
<CAPTION>
                                                   Operating Leases    Capital Leases
                                                   ----------------    --------------

<S>                                                <C>                  <C>
                  2001                                    486,000              5,000
                  2002                                    432,000              6,000
                  2003                                    373,000              6,000
                  2004                                     22,000              3,000
                  Thereafter                                   --                 --
                                                     ------------       ------------
                  Total minimum payments             $  1,313,000       $     20,000
                                                     ============
                  Less Imputed interest                                       (3,000)
                                                                        ------------
                  Present value of minimum
                     lease payments                                     $     17,000
                                                                        ============
</TABLE>

6.       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. The total estimated contingent
         consideration to be paid under this agreement is $1,850,000, of which
         $1,000,000 is included in `Other long-term obligations', and $850,000
         is included in `Current portion of other long-term obligations'.

7.       STOCK OPTIONS AND OTHER COMPENSATION

         In May 1989, non-statutory stock options were granted by the Company to
         key executive officers for the purchase of shares of common stock. At
         December 31, 2000 and 1999, options on 767,500 and 802,500 shares,
         respectively, were outstanding and exercisable at prices ranging from
         $1.00 to $1.25 per share.

         On January 27, 1983, the Company adopted the 1983 Incentive Stock
         Option Plan. At December 31, 2000 and 1999, options on 87,000 and
         103,000 shares were exercisable at $1.50 per share, respectively, and
         no additional shares were available for granting.

         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



                                      F-12
<PAGE>   29

         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.

8.       INCOME TAXES

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

<TABLE>
<CAPTION>
                                                                       2000             1999
                  Federal:                                         ------------     ------------
<S>                                                                <C>              <C>
                      Current                                      $    201,000     $     32,000
                      Deferred                                          141,000               --
                  State:
                      Current                                           254,000           37,000
                      Deferred                                          215,000          (39,000)
                                                                   ------------     ------------
                  Total                                            $    811,000     $     30,000
                                                                   ============     ============
</TABLE>

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

<TABLE>
<CAPTION>
                                                                     December 31,      December 31,
                                                                         2000              1999
                                                                     ------------      ------------
<S>                                                                  <C>               <C>
         Current assets:
              Compensation and benefits                              $    147,000      $    103,000
              Allowance for doubtful accounts                               8,000             8,000
              Less, valuation allowance                                        --          (111,000)
                                                                     ------------      ------------
                                                                          155,000                --
                                                                     ------------      ------------
         Noncurrent assets:
              Depreciation                                                346,000           215,000
              Due from related parties reserve                            312,000           312,000
              Federal net operating loss carryforwards                    249,000           758,000
              State net operating loss                                         --            51,000
              Percentage depletion carryforwards                          597,000         1,016,000
              Alternative minimum tax credits                             918,000           716,000
              Less, valuation allowance                                        --        (1,676,000)
                                                                     ------------      ------------
                                                                        2,422,000         1,392,000
                                                                     ------------      ------------
         Noncurrent liabilities:
              Basis differences relating to limited partnerships       (1,751,000)         (749,000)
              Depletion                                                (1,182,000)         (643,000)
                                                                     ------------      ------------
                                                                       (2,933,000)       (1,392,000)
                                                                     ------------      ------------
         Net deferred tax liabilities:                               $    356,000      $         --
                                                                     ============      ============
</TABLE>



                                      F-13
<PAGE>   30

                    PrimeEnergy Corporation and SUBSIDIARIES

              Notes to Consolidated Financial Statements, Continued

                                   ----------

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

<TABLE>
<CAPTION>
                                                                          December 31,      December 31,
                                                                              2000              1999
                                                                          ------------      ------------
<S>                                                                       <C>               <C>
         Expected tax expense (benefit)                                      2,100,000          (717,000)
         State income tax, net of federal benefit                              469,000            (2,000)
         Overaccrual of prior year refunds receivable                               --            32,000
         Effect of valuation reserve against tax assets                             --           717,000
         Benefit from net operating losses and other carryforwards
               previously reserved against                                  (1,670,000)               --
         Credit for producing fuel from a non-conventional source              (88,000)               --
                                                                          ------------      ------------
         Tax expense                                                           811,000            30,000
                                                                          ============      ============
</TABLE>

         In both 1998 and 1999 the Company had large federal net operating
         losses. The value of these loss carryforwards was fully reserved
         against due to the uncertainty as to whether the Company would have
         future net income against which these losses could be offset. The use
         of these previously reserved against carryforwards are the primary
         reason for the low federal rate in the current year. The Company's
         effective rate in future years may increase significantly as no
         reserves against tax assets exist as of December 31, 2000.

         The Company has $732,000 of net operating loss carryforwards for both
         regular and alternate minimum tax purposes. $366,000 of these
         carryforwards expire in each of the years 2001 and 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, which is scheduled to expire at the end of the 2002 tax year,
         may significantly reduce the Company's tax liability in future years.

         The Company has percentage depletion carryforwards of approximately
         $1,531,000 for regular tax purposes and $995,000 for alternative
         minimum tax purposes. The Company has approximately $918,000 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.

9.       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 2000.

<TABLE>
<S>                                         <C>
         Unimark LLC                        23.85%
         Texon Distributing L.P.            18.55%
         El Paso Energy Marketing           11.76%
         Plains All American Inc.           10.82%
</TABLE>

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



                                      F-14
<PAGE>   31

                    PrimeEnergy Corporation and SUBSIDIARIES

              Notes to Consolidated Financial Statements, Continued

                                   ----------

10.      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 12% 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.

         In 1991, the Company loaned approximately $325,000 at 12% interest to a
         real estate limited partnership in which a company director is a
         general partner. This loan was secured by a second mortgage on the
         underlying real estate in the partnership and the Company received a
         23% equity participation in the partnership. The loan agreement
         provided for interest payments on a quarterly basis provided the cash
         flow from operations of the limited partnership is sufficient to pay
         interest for the quarter. If cash flows were not sufficient, then the
         accrued interest was added to the principal. As of December 31, 1999,
         amounts due, included in other non-current assets on the balance sheet,
         were $442,000. In July of 2000, the loan balance, including all accrued
         interest, was paid in full.

         Due to related parties at December 31, 2000 and December 31, 1999
         primarily represent receipts collected by the Company, as agent, from
         oil and gas sales net of expenses. The amount of such receipts due the
         affiliated Partnerships was $1,265,000 and $943,000 at December 31,
         2000 and 1999, 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 1999, 2000 and 2001 included shares
         acquired from related parties. Purchases from related parties include a
         total of 41,800 shares purchased for total consideration of $209,000 in
         1999, 40,700 shares purchased for total consideration of $276,900 in
         2000, and 159,600 shares purchased for a total consideration of
         $1,117,000 in the first quarter of 2001.

11.      RESTRICTED CASH AND CASH EQUIVALENTS

         Restricted cash and cash equivalents includes $1,128,000 and $1,854,000
         at December 31, 2000 and 1999, respectively, of cash primarily
         pertaining to unclaimed royalty payments. There were corresponding
         accounts payable recorded at December 31, 2000 and 1999 for these
         liabilities.

12.      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 $226,000 and $217,000 in 2000 and 1999, respectively.



                                      F-15
<PAGE>   32

                    PRIME ENERGY Corporation and SUBSIDIARIES

              Notes to Consolidated Financial Statements, Continued

                                   ----------


13.      ACCOUNTS PAYABLE

         A summary of accounts payable at December 31, 2000 and 1999 is as
follows:

<TABLE>
<CAPTION>
                                                              2000             1999
                                                          ------------     ------------

<S>                                                       <C>              <C>
         Payables to unaffiliated interests               $  6,783,000     $  7,851,000
         Other                                                  45,000           49,000
                                                          ------------     ------------
                                                          $  6,828,000     $  7,900,000
                                                          ============     ============
</TABLE>

14.      EARNINGS PER SHARE

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

<TABLE>
<CAPTION>
                                                     Year Ended                                       Year Ended
                                                  December 31, 2000                                December 31, 1999
                                     --------------------------------------------    ---------------------------------------------
                                         Net          Number of       Per Share          Net           Number of       Per Share
                                        Income          Shares          Amount           Loss            Shares          Amount
                                     ------------    ------------    ------------    ------------     ------------    ------------
<S>                                  <C>             <C>             <C>             <C>              <C>             <C>
Net income (loss) per
   common share                      $  5,365,000       4,266,186    $       1.26    $ (2,138,000)       4,423,838    $      (0.48)
Effect of dilutive securities:
   Options (1)                                 --         686,057              --              --               --              --
                                     ------------    ------------    ------------    ------------     ------------    ------------

Diluted net income (loss)
  per common share                   $  5,365,000       4,952,243    $       1.08    $ (2,138,000)       4,423,838    $      (0.48)
                                     ============    ============    ============    ============     ============    ============
</TABLE>

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

15.      SUBSEQUENT EVENTS

         In the first quarter of 2001, the Company purchased, in a number of
         separate transactions, 232,500 shares of treasury stock for a total
         consideration of $1,624,000.

         The Company drilled two dry holes in the first quarter of 2001, on
         which it expects to recognize expense of approximately $285,000.



                                      F-16
<PAGE>   33

                    PRIME ENERGY Corporation and SUBSIDIARIES

              Notes to Consolidated Financial Statements, Continued

                                   ----------


16.      SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

<TABLE>
<CAPTION>
                                       Year Ended
                                      December 31,         Fourth            Third           Second             First
                                          2000            Quarter           Quarter          Quarter           Quarter
                                      ------------      ------------      ------------     ------------      ------------
<S>                                   <C>               <C>               <C>              <C>               <C>

Revenue                               $ 39,182,000      $ 11,548,000      $ 11,113,000     $  8,809,000      $  7,712,000

Operating income                         6,148,000         1,451,000         2,605,000        1,501,000           591,000

Net income                               5,365,000         1,221,000         2,294,000        1,332,000           518,000

Net income per common
share                                 $       1.26      $        .29      $        .54     $        .31      $        .12

Diluted net income per
common share                          $       1.08      $        .24      $        .47     $        .27      $        .10
</TABLE>

<TABLE>
<CAPTION>
                                       Year Ended
                                      December 31,         Fourth            Third           Second             First
                                          1999            Quarter           Quarter          Quarter           Quarter
                                      ------------      ------------      ------------     ------------      ------------
<S>                                   <C>               <C>               <C>              <C>               <C>

Revenue                               $ 25,520,000      $  7,574,000      $  6,512,000     $  6,120,000      $  5,314,000

Operating income (loss)                 (2,116,000)       (1,623,000)               --           (3,000)         (490,000)

Net income (loss)                       (2,138,000)       (1,691,000)            2,000            1,000          (450,000)

Net income (loss) per common
share                                 $      (0.48)     $      (0.38)     $        .00     $        .00      $       (.10)

Diluted net income (loss) per
common share                          $      (0.48)     $      (0.38)     $        .00     $        .00      $       (.10)
</TABLE>


                                      F-17
<PAGE>   34


                    PRIMEENERGY CORPORATION AND SUBSIDIARIES

                            SUPPLEMENTARY INFORMATION

                                   ----------

                                   (UNAUDITED)



                                      F-18
<PAGE>   35

                    PRIMEENERGY CORPORATION and SUBSIDIARIES

         CAPITALIZED COSTS RELATING to OIL and GAS PRODUCING ACTIVITIES

                           December 31, 2000 and 1999

                                   ----------

                                   (Unaudited)


<TABLE>
<CAPTION>
                                                                           2000             1999
                                                                       ------------     ------------
<S>                                                                    <C>              <C>

Developed oil and gas properties                                       $ 57,439,000     $ 49,249,000
Undeveloped oil and gas properties                                          159,000          235,000
                                                                       ------------     ------------

                                                                         57,598,000       49,484,000

Accumulated depreciation, depletion and valuation allowance              37,686,000       32,342,000
                                                                       ------------     ------------

         Net capitalized costs                                         $ 19,912,000     $ 17,142,000
                                                                       ============     ============
</TABLE>

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

                     Years ended December 31, 2000 and 1999

                                   ----------

                                   (Unaudited)


<TABLE>
<CAPTION>
                                                                           2000             1999
                                                                       ------------     ------------
<S>                                                                    <C>              <C>

Acquisition of properties:
         Developed                                                     $  4,679,000     $  3,042,000
         Undeveloped                                                        106,000          189,000

Exploration costs, excluding valuation allowance                          1,797,000          806,000

Development costs                                                         3,351,000        4,473,000
</TABLE>


              See accompanying notes to supplementary information.



                                      F-19
<PAGE>   36

                    PRIMEENERGY CORPORATION and SUBSIDIARIES

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

                     years ended December 31, 2000 AND 1999

                                   ----------

                                   (Unaudited)


<TABLE>
<CAPTION>
                                                                      2000                1999
                                                                 --------------      --------------
<S>                                                              <C>                 <C>

Future cash inflows                                              $  315,680,000      $  100,177,000

Future production and development costs                            (116,417,000)        (58,807,000)

Future income tax expenses                                          (59,339,000)         (4,229,000)
                                                                 --------------      --------------

         Future net cash flows                                      139,349,000          37,141,000

10% annual discount for estimated timing of cash flow               (59,339,000)        (13,281,000)
                                                                 --------------      --------------
         Standardized measure of discounted
           future net cash flow                                  $   80,010,000      $   23,860,000
                                                                 ==============      ==============
</TABLE>


              See accompanying notes to supplementary information.



                                      F-20
<PAGE>   37

                    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, 2000 and 1999

                                   ----------

                                   (Unaudited)


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


<TABLE>
<CAPTION>
                                                                     2000              1999
                                                                 ------------      ------------
<S>                                                              <C>               <C>

Sales of oil and gas produced, net of production costs           $(14,109,000)     $ (5,458,000)
Net changes in prices and production costs                         69,822,000         3,192,000
Extensions, discoveries and improved recovery,
         less recovery costs                                       13,705,000         6,188,000
Revisions of previous quantity estimates                            3,577,000         2,178,000
Reserves purchased, net of development costs                       11,698,000         4,818,000
Net change in development costs                                       (99,000)          150,000

Accretion of discount                                               2,386,000         1,328,000

Net change in income taxes                                        (30,779,000)       (1,973,000)
Other                                                                 (51,000)          156,000
                                                                 ------------      ------------

         Net change                                                56,150,000        10,579,000

Standardized measure of discounted future net cash flow:

         Beginning of year                                         23,860,000        13,281,000
                                                                 ------------      ------------
         End of year                                             $ 80,010,000      $ 23,860,000
                                                                 ============      ============
</TABLE>


               See accompanying notes to supplementary information



                                      F-21
<PAGE>   38

                    PRIMEENERGY CORPORATION and SUBSIDIARIES

                          RESERVE QUANTITY INFORMATION

                     years ended December 31, 2000 and 1999

                                   ----------

                                   (Unaudited)


<TABLE>
<CAPTION>
                                                      2000                               1999
                                         ------------------------------      ------------------------------
                                              Gas               Oil              Gas               Oil
                                             (Mcf)            (bbls.)           (Mcf)             (bbls.)
                                         ------------      ------------      ------------      ------------
<S>                                      <C>               <C>               <C>               <C>

Proved developed and undeveloped
     reserves:
         Beginning of year                 22,202,000         2,110,000        17,341,000         1,200,000
         Extensions, discoveries
            and improved recovery           1,961,000            13,000         1,732,000           554,000
         Revisions of previous
            estimates                       3,763,000           162,000         1,853,000           346,000
         Purchases                          3,034,000           375,000         4,565,000           274,000
         Production                        (3,931,000)         (298,000)       (3,289,000)         (264,000)
                                         ------------      ------------      ------------      ------------

         End of year                       27,029,000         2,362,000        22,202,000         2,110,000
                                         ============      ============      ============      ============

Proved developed reserves                  27,029,000         2,362,000        22,046,000         2,110,000
                                         ============      ============      ============      ============
</TABLE>


               See accompanying notes to supplementary information




                                      F-22
<PAGE>   39

                    PRIMEENERGY CORPORATION and SUBSIDIARIES

           RESULTS of OPERATIONS from OIL and GAS PRODUCING ACTIVITIES

                     years ended December 31, 2000 and 1999

                                   ----------

                                   (Unaudited)


<TABLE>
<CAPTION>
                                                                     2000             1999
                                                                 ------------     ------------
<S>                                                              <C>              <C>

Revenue:
         Oil and gas sales                                       $ 23,223,000     $ 11,763,000
                                                                 ------------     ------------

Costs and expenses:
         Lease operating expense                                    9,114,000        6,305,000
         Exploration costs                                          1,717,000          869,000
         Depreciation and depletion                                 5,060,000        4,581,000
         Write down of oil and gas properties                         295,000        2,703,000
         Income tax expense                                           811,000           30,000
                                                                 ------------     ------------
                                                                   16,997,000       14,488,000
                                                                 ------------     ------------

Results of operations from producing activities
    (excluding corporate overhead and interest costs)            $  6,226,000     $ (2,725,000)
                                                                 ============     ============
</TABLE>


               See accompanying notes to supplementary information



                                      F-23
<PAGE>   40

                    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-24

<PAGE>   41
                               INDEX TO EXHIBITS

<TABLE>
<CAPTION>
EXHIBIT
NUMBER       DESCRIPTION
-------      -----------
<S>          <C>
  3.1        Restated Certificate of Incorporation of PrimeEnergy
             Corporation. (Incorporated herein by reference to Exhibit 3.1
             of PrimeEnergy Corporation Form 10-KSB for the year ended
             December 31, 1999)

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

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

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

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

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

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

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

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

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

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

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

  21         Subsidiaries. (filed herewith)

  23         Consent of Ryder Scott & Company L.P. Company. (filed
                  herewith)
</TABLE>

-----------

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