PRIMEENERGY CORP, 10KSB, 1998-03-31

PRIMEENERGY CORP
10KSB, 1998-03-31
CRUDE PETROLEUM & NATURAL GAS

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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, 1997

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 NO. 0-7406

PRIMEENERGY CORPORATION
(Exact name of Small Business Issuer in its charter)

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

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

06901
(Zip Code)

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

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

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

Indicate by check mark whether Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES [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
$28,725,000.

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 20, 1998, was $10,119,998.

The number of shares outstanding of each class of the Registrant's
Common Stock as of March 20, 1998, was: Common Stock, $0.10 par value,
4,484,540.

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, 1998, are incorporated by reference in Part III hereof.

Transitional Small Business Disclosure Format (check one)
Yes [ ] No [x]

================================================================================

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PRIMEENERGY CORPORATION

FORM 10-KSB ANNUAL REPORT
FOR THE FISCAL YEAR ENDED
DECEMBER 31, 1997

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,
and West Virginia. The Company's wholly-owned subsidiary, PrimeEnergy Management
Corporation ("PEMC"), acts as the managing general partner in 51 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 interests of PEMC in the oil and gas properties acquired by the
Partnerships and Trusts. As the managing general partner in each of the

<PAGE> 3

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 in the Trusts now administered by PEMC is approximately 9,000.
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 now 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 interest in the joint venture properties.

Since 1987, PEMC has organized approximately $20 million of joint
venture capital. The Company's participation in the joint ventures varies from
none to approximately 68%. The Company's carried interest is generally 10% of
funds contributed by outside investors.

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
about 1,704 oil and gas wells, 500 through the Houston office, 199 through the
Midland office, 489 through the Oklahoma City office and 516 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 the
joint ventures 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 which 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 the development

<PAGE> 4

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 first quarter of 1997, the Company began its field activity on
the Ramrod Prospect, by participating in a 3D Seismic survey over 17,680 acres
in Matagorda County, Texas. As a result of this activity, the Company has
drilled and successfully completed 5 gas wells. Four of these wells are
completed in Miocene sands and initial production from these wells totaled
1,350 gross Mcf of gas per day. The fifth well was drilled to a total depth of
14,010' and completed in the Frio Formation. The well has tested at a rate of
10,000 gross Mcf of gas per day and 240 gross barrels of condensate per day.
The undrilled acreage is under option to lease. The Company owns a 29.5 percent
revenue interest in this property.

Development of the Company's leasehold position in Calhoun County,
Texas, continued in 1997 with two additional wells being drilled on acreage of
the South Powderhorn Project. The first well was drilled in March of 1997 to a
depth of 5,680', completed as a gas well and tested with an initial production
rate of 2,000 gross Mcf of gas per day. The second well was drilled in August of
1997 to a depth of 4,850' and was plugged and abandoned. The Company owns a
27.72 percent revenue interest in this property.

In August of 1997, the Company drilled and completed a well in the West
Carney field of Lincoln County, Oklahoma. This was an increased density location
that was successfully completed as an oil well in the Hunton Formation. The well
produces approximately 135 gross barrels of oil per day, 125 gross Mcf of gas
per day and 1,000 gross barrels of water per day. The Company owns a 14.54
percent working interest and a 12.72 percent net revenue interest in this
property.

Also in August of 1997, the Company operated and participated in the
drilling of a horizontal re-entry well in the Brazos field of Midland County,
Texas. The well was successfully completed as an oil well in the San Andres
Formation with an initial production rate of 92 gross barrels of oil per day.
The Company owns a 6.37 net revenue interest in this property.

During 1997, the Company made several operational improvements to its
Robberson waterflood projects in Garvin County, Oklahoma. These changes included
the conversion of wells to water injection, changes in bottom-hole pump
equipment and changes in water injection rates and pattern. These changes have
resulted in an 18 percent improvement in field production. Oil sales from the
Robberson properties averaged 684 gross barrels of oil per day in 1997, as
compared to 1996 oil sales of 580 gross barrels of oil per day. The Company has
an average 10.4 percent net revenue interest in these properties.

In September of 1997, the Company operated and participated in the
drilling of a well in Calhoun County, Texas, as part of its Flintlock Prospect.
This well was drilled to 6,420' and successfully completed as a dual gas well in
two separate Miocene reservoirs. The lower zone had an initial production rate
of 1,500 gross Mcf of gas per day and the upper zone had an initial production
rate of 1,000 gross Mcf of gas per day. The Company owns a 52.33 percent revenue
interest in this property.

Also in September of 1997, the Company operated and participated in
the drilling of a well in its Rich Ranch Prospect of Liberty County, Texas. This
well was drilled to 12,749' and plugged and abandoned. The Company owned 40
percent of this property.

In October of 1997, the Company operated and participated in the
drilling of a well in its Estherwood Prospect of Acadia Parish, Louisiana. This
well was drilled to 10,686' and plugged and abandoned. The Company owned 19.3
percent of this property.

<PAGE> 5

In November of 1997, the Company operated and participated in the
drilling of a well in the Flintlock Prospect of Calhoun County, Texas. This well
was drilled to 4,964' and plugged and abandoned. The Company owned 50.3 percent
of this property.

Also in November of 1997, the Company operated and participated in the
drilling of a well in the South Kraemer Prospect of Lafourche Parish, Louisiana.
This well was drilled to 10,560' and plugged and abandoned.
The Company owned 10.9 percent of this property.

The Company's development activities in 1997 continued in the Segno
Field of Polk County, Texas. The Company operated and participated in the
drilling and completion of four new wells and the deepening of two existing
wells. All six wells were successfully completed in the Wilcox Formation at
approximately 8,400'. One well was dually completed in the Yegua Formation at a
depth of 5,200'. As a group these six wells had a combined initial production
rate of approximately 391 gross barrels of oil per day, plus 520 gross Mcf of
gas per day. The Company retains 17% of the net revenue from this property.

During 1997, the Company participated in the drilling and completion or
workover operation of 4 gross (.155 net) wells operated by other companies. The
Company spent approximately $357,000 on these projects. At year end, 3 gross
(.08 net) wells were successfully completed as producers and one was
unsuccessful. The successfully completed wells had an aggregate initial
production rate of approximately 73 gross (2 net) barrels of oil per day and
7,750 gross (207 net) Mcf of gas per day.

In April of 1997, the Company sold a group of outside operated wells
located in New Mexico for $680,000, and in a separate transaction, a group of
operated properties also located in New Mexico for $167,000.

In March of 1998, the Company sold the remainder of its operated wells
located in New Mexico for $160,000. Also in March of 1998 the Company sold the
Guerra field, which is located in Webb County, Texas and was acquired in the
Saratoga acquisition, for $105,000.

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 and West Virginia. The Company does not own
any significant properties other than its leasehold, mineral and royalty
interests and related pipeline and gas gathering systems, and does not own any
drilling equipment or refinery or marketing facilities. 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.

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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 1920 ("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.

<PAGE> 7

The Company has been subject to the alternative minimum tax in each of
its taxable years since 1988. The primary factors which have caused it to be
subject to this tax in prior years were the former preference for percentage
depletion in excess of the cost basis of an oil and gas property, the former
adjusted current earnings adjustment for intangible drilling costs, and the
limitation of the Section 29 credits allowable to the excess of regular tax over
tentative alternative minimum tax. The Company is subject to alternative minimum
tax in the current year primarily due to the Company's Section 29 credits. The
Company is allowed a credit carry forward for the amount of alternative minimum
tax paid. This credit, which may be used to offset regular tax liability in
years where it exceeds the tentative alternative minimum tax, can be carried
forward indefinitely.

See Notes 1 and 10 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.

COMPETITION AND MARKETS

The business of acquiring producing properties and nonproducing 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.

The Company 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. While the Company is not
dependent on any one purchaser of its production, oil and gas revenue in 1997
generated from sales to Dow Hydrocarbons and Resources, Inc., a subsidiary of
Dow Chemical, U.S.A., and Scurlock Permian Corp. represented about 23% and 10%,
respectively, of the Company's total revenue from oil and gas sales. Sales to
Dow Hydrocarbons were made under a month-to-month gas purchasing agreement at
prices based upon the Houston Ship Channel index (for large packages only), as
published by Inside F.E.R.C., an industry publication. Although there is no
long-term contract with Dow Hydrocarbons, the Company believes that the
purchaser will continue to purchase its gas products and, if not, could be
replaced by other purchasers. Sales to Scurlock were made under an oil
purchasing agreement at prices that are adjusted semi-annually, based upon
posted crude oil prices.

ENVIRONMENTAL MATTERS

Over the past 20 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

<PAGE> 8

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 natural gas facilities,
including the operation and construction of pipelines, plants and other
facilities for transporting, processing, treating or storing natural 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 natural
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 natural 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 more
strict. Under these new laws, the Company could be required to remove or
remediate previously disposed wastes (including wastes disposed of or released
by prior owners or operators) or property contamination (including groundwater
contamination) or to perform remedial plugging operations to prevent future
contamination.

The Company may generate wastes, including hazardous wastes, that are
subject to the Federal Resource Conservation and Recovery Act and comparable
state statutes. The EPA has limited the disposal options for certain hazardous
wastes and is considering the adoption of stricter disposal standards for
nonhazardous 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.

<PAGE> 9

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 20, 1998, the Company had 163 full-time and 10 part-time
employees, 28 of whom were employed by the Company at its principal offices in
Stamford, Connecticut, 31 in Houston, Texas, at the offices of Prime Operating
Company and Eastern Oil Well Service Company, and 114 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 11,000
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, Yukon, and Marshall, Oklahoma,
and Arnoldsburg, West Virginia.

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

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

OIL AND GAS DRILLING ACTIVITIES

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, 1997.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-----------------------------------------------------------------------------
1997 1996 1995 1994 1993
------------- ------------- ------------- ------------- -------------
GROSS NET GROSS NET GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Exploratory:
Oil ............. -- -- -- -- -- -- -- -- 1 .009
Gas ............. 2 .8 -- -- -- -- -- -- 3 .375
Dry ............. 2 .509 1 1 -- -- -- -- 2 .150
Development:
Oil ............. 5 .796 3 .740 8 1.046 4 .346 3 .600
Gas ............. 5 2.037 17 1.292 3 .235 2 .121 13 .257
Dry ............. 3 1.030 1 .371 2 .350 4 .215 1 .090
Total:
Oil ............. 5 .796 3 .740 8 1.046 4 .346 4 .609
Gas ............. 7 2.837 17 1.292 3 .235 2 .121 16 .632
Dry ............. 5 1.539 2 1.371 2 .350 4 .215 3 .240
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
17 5.172 22 3.403 13 1.631 10 .682 23 1.481
===== ===== ===== ===== ===== ===== ===== ===== ===== =====
</TABLE>

<PAGE> 10
\

OIL AND GAS PRODUCTION

As of December 31, 1997, 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>
GROSS NET
------- -------
<S> <C> <C>
Producing wells (1):
Oil Wells ............................................. 1,472 177.60
Gas Wells ............................................. 1,140 149.08
Producing Acres .......................................... 196,631 37.296
</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 acre 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, 1997. "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>
YEAR ENDED DECEMBER 31,
---------------------------------------------------------
1997 1996 1995 1994 1993
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Oil (barrels) ...... 277,000 249,000 155,000 143,000 149,000
Gas (Mcf) .......... 3,901,000 2,888,000 1,952,000 1,408,000 1,332,000
</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, 1997.

<TABLE>
<CAPTION>
1997 1996 1995 1994 1993
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Average sales price
per barrel ............. $ 19.35 21.11 16.53 15.22 16.30
Average sales price
per Mcf ................ $ 2.57 2.36 1.85 2.36 2.51
Average production
costs per net equivalent
barrel (1) ............. $ 7.59 8.09 8.92 10.14 10.70
</TABLE>

- --------------

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

<PAGE> 11

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, 1997. "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.

<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 ........... 4,185 329 799 23 -- --
Louisiana .......... 1,179 246 -- -- -- --
Montana ............ -- -- 13,984 59 786 5
Nebraska ........... -- -- 2,553 331 -- --
North Dakota ....... -- -- 640 1 -- --
Oklahoma ........... -- -- 320 1 -- --
Texas .............. 20,363 8,551 640 3 -- --
Wyoming ............ 1,000 125 5,043 35 140 35
-------- -------- -------- -------- -------- --------
TOTAL .............. 26,727 9,251 23,979 453 926 40
======== ======== ======== ======== ======== ========
</TABLE>

RESERVES

The Company's interests in proved developed and undeveloped oil and gas
properties have been evaluated by Ryder Scott Company for the years ended
December 31, 1993, 1994, 1995, 1996, and 1997. 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>
1993 ............... 512,000 8,351,000 76,000 922,000 588,000 9,273,000
1994 ............... 799,000 9,675,000 2,000 129,000 801,000 9,804,000
1995 ............... 905,000 13,549,000 -- 52,000 905,000 13,601,000
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
</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

<PAGE> 12

Company's proved developed and proved undeveloped oil and gas reserves at the
end of each of the five years ended December 31, 1997, are summarized as follows
(figures rounded):

<TABLE>
<CAPTION>
PROVED DEVELOPED PROVED UNDEVELOPED TOTAL
------------------------------ ---------------------- ---------------------------
PRESENT PRESENT PRESENT
VALUE OF VALUE OF VALUE OF
FUTURE FUTURE FUTURE FUTURE FUTURE FUTURE
AS OF NET NET NET NET NET NET
12-31 REVENUE REVENUE REVENUE REVENUE REVENUE REVENUE
- ----- ------------ ---------- ------- ------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
1993........... $ 11,307,000 6,576,000 460,000 221,000 11,767,000 6,797,000
1994........... $ 10,396,000 6,839,000 156,000 75,000 10,552,000 6,914,000
1995........... $ 15,727,000 9,530,000 39,000 18,000 15,766,000 9,548,000
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
</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.

Since January 1, 1997, the Company has not filed any estimates of its
oil and gas reserves with, nor were any such estimates included in any reports
to, any federal authority or agency, other than the Securities and Exchange
Commission, except Form EIA-23, Annual Survey of Domestic Oil and Gas Reserves,
filed with The Energy Information Administration of the U.S. Department of
Energy.

ITEM 3. LEGAL PROCEEDINGS.

The Company is not a party to, nor is any of its property the subject
of, any legal proceedings, actual or threatened involving any claim for damages
which exceed 10 percent of the Company's current assets.

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, 1997, to a vote of the Company's security-holders through the
solicitation of proxies or otherwise.

<PAGE> 13

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, 1997, were as follows:

<TABLE>
<CAPTION>
1996 HIGH LOW 1997 HIGH LOW
---- ------- ------- ---- ------ ------
<S> <C> <C> <C> <C> <C>
First Quarter.................. $ 2.44 $ 2.38 First Quarter..................... $ 4.80 $ 4.59
Second Quarter................. 4.00 2.44 Second Quarter.................... 6.54 6.33
Third Quarter.................. 4.00 3.25 Third Quarter..................... 9.15 8.78
Fourth Quarter................. 4.75 3.88 Fourth Quarter.................... 9.23 8.88
</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 20, 1998, was 1,220.

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 feels that it has the ability to generate sufficient
amounts of cash to meet long-term liquidity needs, as well as debt service. The
Company expects to generate increased cash flows by increasing its reserve base
through continued acquisition and development. By increasing its reserve base,
the Company's borrowing ability is increased due to additional properties
available as collateral. Capital expenditures during 1997 were financed by
borrowings and internally generated funds coupled with cash balances available
at the prior year-end.

On April 26, 1995, the Company entered into a revised credit agreement
with Bank One, Texas, NA providing for a $12.5 million revolving line of credit
on a $50 million master promissory note. This new agreement introduced Den
Norske Bank, AS as a 25% syndication partner in the line. The agreement also
provides for a lower floating rate compared to previous agreements as well as
the ability to borrow based upon the London Inter-Bank Offered Rate (LIBOR). The
borrowing base will be revised every six months by the banks.

As of December 31, 1997, the borrowing base under the agreement was
$20,000,000 and the Company had $1,135,000 available under this line of credit.
During most of 1997, the interest rate on this line of credit was the bank's
base rate, as defined, monthly, or 2 1/4 % over the published LIBOR rate,
payable at the end of the applicable interest period. Effective February 2,
1998, this agreement was amended so that the interest rate on the LIBO Rate Loan
will vary from 1 1/2 % to 2% above the published LIBOR rate depending on the
portion

<PAGE> 14

of the Company's credit line being utilized. Based on current and expected
levels of borrowing, it is anticipated that the rate charged to the Company on
these loans will be at 2% above the published LIBOR rate for most or all of
1998.

Most of the Company's oil and gas properties as well as certain
receivables and equipment are pledged as security under the agreement. The
Company is required to maintain, as defined, a minimum tangible net worth, and
certain debt, interest coverage and current ratios, and restrictions are placed
on the Company's ability to pay dividends and purchase treasury stock.

Since late 1995, the Company has been involved in a program to use 3D
seismic to identify prospects for developmental and exploratory drilling in
Southeast Texas (the 3D Seismic Program). The Company spent a total of
$6,909,000 on this program in 1997, including $3,735,000 spent to shoot and
interpret 3D seismic, acquire acreage and drill and equip wells on the Ramrod
acreage, where four successful wells were drilled and completed in the Miocene
formation during 1997. A fifth well, the St. George #1, began drilling during
1997 and was completed in 1998 in the Frio formation. $801,000 was spent on the
drilling of a dry hole on the Rich Ranch prospect in Liberty County, Texas.
$1,569,000 was spent to shoot seismic, acquire acreage and drill two wells on
the Flintlock prospect adjacent to the Company's South Powderhorn field. One of
these wells was successfully completed during 1997 and the other was a dry hole.
$631,000 was spent to acquire seismic covering an area in Matagorda Bay which is
currently being evaluated for potential drilling prospects and $467,000 was
spent to further develop the South Powderhorn field. The remainder of the
spending on the program consisted of costs to acquire leasehold options and 2D
seismic on acreage being considered for additional 3D seismic shoots.

In total, the Company spent approximately $11,066,000 on the
acquisition and development of oil and gas interests in 1997, including the
$6,909,000 spent in connection with the 3D seismic program, $1,242,000 spent to
acquire limited partnerships interests from investors in its oil and gas
partnerships, and $1,004,000 spent to develop properties acquired in the
Saratoga acquisition.

The Company spent $814,000 on trucks, automobiles and equipment used in
field service operations, and an additional $338,000 on computer related
equipment and software.

During 1996, the Company entered into an agreement to purchase 400,000
shares of its common stock for a total consideration of $1,144,000. Of this
amount, $523,000 was paid in 1996, and the remaining $621,000 was paid in 1997.
An additional $872,000 was spent in 1997 to acquire treasury stock in open
market transactions.

In January, 1998, the Company purchased 53,334 shares of its stock for
treasury from Stanford University and 53,334 shares from the University of
California. The total combined cost of these two purchases was $853,000.

Most of the Company's capital spending is discretionary and the
ultimate level of spending will be dependent on the Company's assessment of the
gas and oil business environment, the number of oil and gas prospects, and oil
and gas business opportunities in general. The St. George #1 well discussed
above had first gas sales on March 12, 1998. After reviewing the first three
months of production from this well, the Company and its partners will consider
the possibilities for further development of this field. The results from this
will also be considered by the Company in deciding whether to perform additional
3D seismic shoots in an attempt to identify potential exploratory drilling
prospects in the Frio formation. The Company's primary objective continues to be
to increase reserves and cash flow through its acquisition, development and
exploration activities.

<PAGE> 15

RESULTS OF OPERATIONS

1997 Compared to 1996

1997 net income of $1,024,000 represents an increase of $85,000 over
the 1996 figure of $939,000. This increase is primarily attributable to sharply
higher income from oil and gas properties due to higher prices, a full year of
revenue from the properties acquires in the Saratoga acquisition in May of 1996,
and revenue from the South Powderhorn wells. This increased income was largely
offset by $2,411,000 in exploration costs incurred in 1997 as compared to
$482,000 in 1996.

Oil and gas sales of $15,485,000 in 1997 represent a 38% increase over
the 1996 sales. The South Powderhorn field, developed as part of the company's
3D seismic program, contributed $3,383,000 in revenue in 1997 as compared to
$918,000 in 1996. The Saratoga properties purchased in May of 1996 contributed
$3,224,000 in revenue in 1997 as compared to $2,676,000 in 1996.

The average price received per barrel of oil for directly owned
production was $19.33 in 1997 as compared to $21.24 in 1996, and the average gas
price was $2.56 in 1997 as compared to $2.34 in 1996.

Oil and gas sales related to the Company's interests in the
Partnerships increased 38% in 1997 compared to 1996. This increase is
attributable to additional interests purchase by the company during the year,
and such increases may continue in the short-term as the Company continues to
repurchase additional interests in the partnerships.

The purchase of the South Powderhorn property was subject to a
provision wherein the seller obtains a 25% working interest in the property at
such time as the Company and its joint venture partners have received net cash
from the property equal to 200% of their costs (Payout). This Payout occurred in
January of 1998.

On March 12, 1998, first sales occurred from the St. George #1 well,
which was drilled as part of the 3D Drilling and Exploration program. Initial
production rates are approximately 10 Mmcf and 240 barrels of condensate per
day. The Company owns a 29% revenue interest in this well.

In terms of barrel of oil equivalents, with 6 mcf's being equivalent to
one barrel, slightly over two-thirds of the Company's total production in 1997
was gas. This percentage can be expected to increase in 1998 as the St. George
#1 well came on line in March 1998.

Lease operating expenses increased by 19% to $7,035,000 in 1997.
Average lifting costs on directly owned properties declined to $7.17 per barrel
of oil equivalent in 1997 as compared to in 1996. The primary reasons for the
decline in per unit lifting costs are higher levels of production from the South
Powderhorn field, where average lifting costs were only $2.26 per BOE and a drop
from $7.90 per BOE to $7.10 on the properties acquired in the Saratoga
acquisition, where substantial cleanup and repair work was done after acquiring
the properties in 1996.

Lease operating expenses attributable to the Company's interests in
Partnerships increased 57%, primarily due to additional interests in the
Partnerships purchased during the year.

District operating income and district operating expense both increased
by 13% in 1997 as compared to 1996. In both cases the primary reason for the
increase is a full year of operating the properties acquired in the Saratoga
acquisition in May of 1996. Oil prices declined significantly in the first
quarter of 1998. A prolonged period of low prices could cause significant
decline in district operating income as certain wells become uneconomical to
operate and customers for field services attempt to reduce spending.

<PAGE> 16

Administrative revenue, which represents the reimbursement of general
and administrative overhead expended on behalf of the Partnerships and the
Company's joint venture partners, increased 4% in 1997 as compared to 1996. In
both years, amounts received from partnerships are 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 its related 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 the total general and administrative expenses. During 1997 and 1996
the Company's total reimbursements for property acquisition costs were
approximately $1,751,000 and $1,783,000 respectively.

General and administrative expense decreased 9% or $300,000 between
1997 and 1996. This decrease is primarily due to $340,000 in non-capitalized
costs incurred in connection with Saratoga acquisition in 1996.

Exploration costs of $2,411,000 were incurred in 1997. The primary
components of this amount were $801,000 related to the drilling of a dry hole on
the Rich Ranch prospect, $631,000 spent to purchase 3D seismic covering an area
of Matagorda Bay currently being evaluated for possible exploratory drilling
prospects, and $721,000 in seismic and other costs relating to the Ramrod
prospect, where four successful wells were drilled and completed in 1997, and an
additional well came on line in March of 1998.

Gain on sales of assets in 1997 consists of net gains of $105,000 from
the sale of producing oil and gas properties, and $189,000 in gains from excess
of the proceeds of sales of equipment on wells which were plugged and abandoned
during 1997 over the plugging and reclamation costs of the wells.

Many existing computer applications use two digits rather than four to
define the applicable year, raising the possibility that software may
erroneously assume that a date using "00" as the year refers to the year 1900
rather than the year 2000.

The Company's existing software will properly handle all dates
including dates beyond December 31, 1999 and the Company does not expect any
significant operational difficulties or unusual costs to result from the year
2000 issue. While it is not possible at this time to determine what effect the
year 2000 issue might have on the Company's customers, suppliers, or joint
venture partners, the Company does not believe the potential problems associated
with the year 2000 issue will have a material effect on it financial position.

1996 Compared to 1995

Net income increased to $939,000 in 1996 as compared to $527,000 in 1995. This
large increase was primarily caused by sharply higher oil and gas revenue caused
by production from the properties acquired in the Saratoga acquisition and wells
drilled in the 3D seismic development and exploration project, as well as higher
oil and gas prices received in the fourth quarter of 1996.

Oil and gas sales increased 87% in 1996, going from $6,024,000 in 1995
to $11,238,000 in 1996. This large increase is due primarily to the
contributions of the Saratoga properties acquired in May of 1996 and wells
drilled in the third quarter as part of the Company's 3D seismic development
program combined with sharply higher oil and gas prices. The Saratoga properties
contributed a total of $2,676,000 in oil and gas revenue in 1996. The wells from
the 3D seismic development program have contributed $823,000.

<PAGE> 17

The average oil price per barrel received for directly owned production
in 1996 was $21.24 as compared to $16.53 per barrel in 1995 and the average gas
price was $2.34 in 1996 as compared to $1.85 per Mcf in 1995.

Oil and gas sales related to PEMC's carried interest in the
Partnerships and other ventures increased approximately 56% or $1,476,000 in
1996 as compared to 1995. Factors leading to this increase include substantially
higher oil and gas prices received by those entities, the acquisition of new
properties and the development of existing properties by those entities, and the
purchase by PEMC of substantial additional interests in these Partnerships over
the last year.

Lease operating expenses increased 44%, or $1,809,000 in 1996 as
compared to 1995. This increase is primarily attributable to the $1,142,000 in
lease operating expenses incurred on the Saratoga properties purchased during
1996. Average lifting costs on directly owned properties declined to $8.87 per
barrel of oil equivalent, primarily because the wells drilled as part of the
Company's 3D seismic program produced 54,000 barrel of oil equivalents, while
adding only $98,000 to lease operating expense.

Depreciation and depletion of oil and gas properties increased 76% or
$1,853,000 in 1996 as compared to 1995. Depletion on the newly acquired Saratoga
properties contributed $1,153,000 to depletion expense in 1996.

District operating revenue and expense totals for 1996 were relatively
flat when compared to 1995. Revenues increased $171,000 (1.75%) to $9.8 million
while expenses increased $40,000 (less than 1%) to $7.4 million. These results
are the net effect of several changes in the Company's activities. The primary
increase in both revenue and expense results from the addition of the Saratoga
properties to the Gulf Coast district. Activity related to servicing these
properties and the expansion of activity related to the 3D seismic program,
which is also concentrated in the Gulf Coast district, offset by a decrease in
equipment utilization on existing Gulf Coast properties, resulted in net
additions of $500,000 and $300,000 in revenues and expense, respectively,
generated by that district. The offsetting declines in district operating
revenue and expense resulted primarily from organizational changes made in both
the Appalachian and Mid-continent districts. The Company has reduced the costs
incurred in servicing the operated properties by restructuring the field
organization and reducing personnel. The reduction in these costs is reflected
in reduced billings and related revenues in both districts.

Administrative revenue which represents the Company's reimbursement of
general and administrative overhead expended on behalf of the Partnerships (see
Note 12 to the consolidated financial statements), declined 13% in 1996 as
compared to 1995. Administrative revenues received in both years from certain
Partnerships are substantially less than the amounts allocable to those
Partnerships under the Partnership agreements. The lower amounts reflect PEMC's
continuing efforts to reduce costs, both incurred and those 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 its related 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 the total general and administrative expenses. During 1996 and
1995, the Company's total reimbursements for property acquisition costs were
approximately $1,783,000 and $1,616,000 respectively.

General and administrative expense increased by 13%, or $387,000
between 1996 and 1995. This increase is primarily due to $340,000 in
non-capitalized costs incurred in connection with Saratoga acquisition, as well
as a general increase in costs reflecting an increase in the scope of the
Company's operations.

<PAGE> 18

Exploration costs of $483,000 consist of $211,000 of dry hole costs and
$272,000 of seismic and other costs related to properties on which exploratory
wells will be drilled in 1997.

Interest expense increased 48% or $327,000 in 1996 as compared to 1995.
This increase is primarily due to higher debt levels related to the purchase of
the Saratoga properties in May of 1996.

The Company recorded $175,000 in gains on the sale of assets during
1996. This amount is primarily attributable to the sale of a large number of
fully depleted wells and equipment sold for salvage during 1996.

ITEM 7. FINANCIAL STATEMENTS.

Included on pages F-1 through F-25 of this Report. The Index to
Financial Statements is at page 22 of this Report.

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

The Company engaged Pustorino, Puglisi & Co. as the principal
accountants for the Company with respect to the audit of the Company's financial
statements for the years ended December 31, 1996 and 1997. There was no
disagreement between the Company and its certified public accountants on any
matter of accounting principles or practices or financial statement disclosure.
The appointment of Pustorino, Puglisi & Co. was effective October 29, 1996,
replacing Coopers & Lybrand, upon approval of the Executive Committee of the
Board of Directors. Coopers & Lybrand acted as the principal accountants for the
Company with respect to the audit of the Company's financial statements for the
years ended December 31, 1995, and 1994. There were no disagreements with
Coopers & Lybrand on any matters of accounting principles or practices,
financial statement disclosure or auditing scope or procedure in connection with
the audit of the Company's two most recent audited fiscal years, being the years
ended December 31, 1995 and 1994, or any subsequent interim period. The audit
reports of Coopers & Lybrand contained no adverse opinion or any disclaimer of
opinion, nor were their reports qualified or modified as to uncertainty, audit
scope or accounting principles.

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, 1998, which will be filed with the Securities and Exchange Commission
within 120 days of December 31, 1997, 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, 1998, which will be filed with the Securities
and Exchange Commission within 120 days of December 31, 1997, and which is
incorporated herein by reference.

<PAGE> 19

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,
1998, which will be filed with the Securities and Exchange Commission within 120
days of December 31, 1997, 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, 1998, which will be filed with the Securities and Exchange Commission
within 120 days of December 31, 1997, and which is incorporated herein by
reference.

PART IV

ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K.

(a) Exhibits:

NO.

3.1 -- Certificate of Incorporation as amended, of PrimeEnergy
Corporation. (Incorporated herein by reference to Exhibit 3.1
of PrimeEnergy Corporation Form 10-KSB for the year ended
December 31, 1994)

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, 1994)

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

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

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

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

<PAGE> 20

(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 (filed herewith)

10.8 -- Mortgage, Deed of 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
herein by reference to Exhibit 10.8 to 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. (filed
herewith)(1)

10.19 -- Purchase and Sale Agreement dated as of May 7, 1996, by and
between Internationale Nederlanden (U.S.) Capital Corporation
and PrimeEnergy Corporation (Incorporated herein by reference
to Exhibit 10.19 to PrimeEnergy Corporation Form 8-K dated May
29, 1996)

10.20 -- Assignment, Conveyance and Bill of Sale dated as of May 7,
1996, by Saratoga Resources, Inc., a Texas corporation, et
al., to PrimeEnergy Corporation (Incorporated herein by
reference to Exhibit 10.20 to PrimeEnergy Corporation Form 8-K
dated May 29, 1996)

21 -- Subsidiaries. (filed herewith)

23 -- Consent of Ryder Scott Company. (filed herewith)

27 -- Financial Data Schedule. (filed herewith)

- --------------

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

(b) Reports on Form 8-K:

No reports on Form 8-K have been filed during the last quarter
of the year covered by this Report.

<PAGE> 21

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, on the 30th day of
March, 1998.

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, 1998.

<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/ BENNIE H. WALLACE, JR. Director, and Vice President
- ---------------------------
Bennie H. Wallace, Jr.

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

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

/s/ CHARLES E. DRIMAL, SR. Director
- ---------------------------
Charles E. Drimal, Sr.

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

/s/ H. GIFFORD FONG Director
- ---------------------------
H. Gifford Fong
</TABLE>

<PAGE> 22

<TABLE>
<S> <C>
/s/ THOMAS S.T. GIMBEL Director
- ---------------------------
Thomas S.T. Gimbel

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

/s/ ROBERT DE ROTHSCHILD 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>

<PAGE> 23

INDEX TO FINANCIAL STATEMENTS

Financial Statements (Included herein at pages F-1 through F-25):

Report of Independent Public Accountants, F-1

Financial Statements:

Consolidated Balance Sheets -- December 31, 1997 and 1996, F-2

Consolidated Statements of Operations -- for the years ended
December 31, 1997 and 1996, F-4

Consolidated Statements of Stockholders' Equity --
for the years ended December 31, 1997 and 1996, F-5

Consolidated Statements of Cash Flows -- for the
years ended December 31, 1997 and 1996, F-6

Notes to Consolidated Financial Statements, F-7

Supplementary Information: F-19

Capitalized Costs Relating to Oil and Gas Producing
Operations, December 31, 1997 and 1996, F-20

Costs Incurred in Oil and Gas Property
Acquisition, Exploration and Development
Activities, years ended December 31, 1997
and 1996, F-20

Standardized Measure of Discounted Future Net Cash
Flows Relating to Proved Oil and Gas reserves, years
ended December 31, 1997 and 1996, F-21

Standardized Measure of Discounted Future Net Cash
Flows and Changes Therein Relating to Proved Oil and
Gas Reserves, years ended December 31, 1997 and 1996,
F-22

Reserve Quantity Information, years ended December 31,
1997 and 1996, F-23

Results of Operations from Oil and Gas
Producing Activities, years ended December
31, 1997 and 1996, F-24

Notes to Supplementary Information, F-25

<PAGE> 24

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, 1997 and 1996, 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, 1997 and 1996, 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, 1998

F-1

<PAGE> 25

PRIMEENERGY CORPORATION and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, December 31, 1997 and 1996

<TABLE>
<CAPTION>
1997 1996
------------ ------------
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 2,987,000 $ 3,316,000
Restricted cash and cash
equivalents (Note 13) 885,000 663,000
Accounts receivable, net (Note 3) 4,480,000 5,052,000
Due from related parties (less allowance for
doubtful accounts of $800,000 in 1997
and 1996) (Note 12) 2,454,000 2,184,000
Prepaid expenses 107,000 150,000
Other current assets 175,000 266,000
Deferred income taxes (Notes 1 and 10) 121,000 119,000
------------ ------------
Total current assets 11,209,000 11,750,000
------------ ------------

Property and equipment, at cost (Notes 1 and 2):
Oil and gas properties (successful
efforts method):
Developed 41,427,000 36,645,000
Undeveloped 231,000 179,000
Furniture, fixtures and equipment
including leasehold improvements 5,757,000 5,269,000
------------ ------------
47,415,000 42,093,000
Accumulated depreciation and depletion (24,885,000) (21,860,000)
------------ ------------
Net property and equipment 22,530,000 20,233,000
------------ ------------

Other assets (Note 12) 604,000 607,000
Due from affiliates (Note 12) 325,000 325,000
------------ ------------
Total assets $ 34,668,000 $ 32,915,000
============ ============
</TABLE>

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

F-2
<PAGE> 26

PRIMEENERGY CORPORATION and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, December 31, 1997 and 1996

<TABLE>
<CAPTION>
1997 1996
------------ ------------
<S> <C> <C>
LIABILITIES and STOCKHOLDERS' EQUITY:
Current liabilities:
Current portion of other long-term
obligations (Note 5) $ -- $ 73,000
Accounts payable (Note 15) 6,333,000 5,297,000
Accrued liabilities:
Payroll, Benefits and Related Items 530,000 494,000
Taxes (Notes 1 and 10) 27,000 11,000
Interest and other 646,000 774,000
Due to related parties (Note 12) 1,389,000 1,298,000
------------ ------------
Total current liabilities 8,925,000 7,947,000
------------ ------------

Long-term bank debt (Note 4) 18,865,000 17,400,000
Other long-term obligations (Note 5) -- 243,000
Deferred income taxes (Notes 1 and 10) 262,000 240,000
Payable for encumbered treasury
stock (Note 6) -- 621,000
------------ ------------
Total liabilities 28,052,000 26,451,000
------------ ------------

Stockholders' equity:
Preferred stock, $.10 par, authorized
10,000 shares; none issued -- --
Common stock, $.10 par value, authorized
15,000,000 shares; issued 7,597,970
in 1997 and 1996 760,000 760,000
Paid in capital 10,888,000 10,888,000
Retained earnings (accumulated deficit) 971,000 (53,000)
Encumbered treasury stock (Note 6) -- (621,000)
------------ ------------
12,619,000 10,974,000
Treasury stock, at cost, 2,989,161
common shares in 1997 and 2,650,398
common shares in 1996 (6,003,000) (4,510,000)
------------ ------------
Total stockholders' equity 6,616,000 6,464,000
------------ ------------
Total liabilities and equity $ 34,668,000 $ 32,915,000
============ ============
</TABLE>

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

F-3
<PAGE> 27

PRIMEENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS of OPERATIONS

for the years ended December 31, 1997 and 1996

<TABLE>
<CAPTION>
1997 1996
----------- -----------
<S> <C> <C>
Revenue:
Oil and gas sales $15,485,000 $11,238,000
District operating income 11,083,000 9,846,000
Administrative revenue (Note 12) 1,684,000 1,621,000
Reporting and management fees (Note 12) 322,000 350,000
Interest income 138,000 129,000
Other income 13,000 42,000
----------- -----------
28,725,000 23,226,000
----------- -----------

Costs and expenses:
Lease operating expense 7,035,000 5,909,000
District operating expense 8,365,000 7,407,000
Depreciation and depletion of
oil and gas properties 5,895,000 4,283,000
General and administrative expense 3,028,000 3,328,000
Exploration costs 2,411,000 483,000
Interest expense (Notes 4 and 5) 1,149,000 1,002,000
----------- -----------
27,883,000 22,412,000
----------- -----------
Income from operations 842,000 814,000

Other income:
Gain on sale and exchange of assets 294,000 175,000
----------- -----------
Income before provision for income taxes 1,136,000 989,000

Provision for income taxes (Note 10) 112,000 50,000
----------- -----------
Net income $ 1,024,000 $ 939,000
=========== ===========

Basic net income per common share (Notes 1 and 16) $ 0.22 $ 0.19
=========== ===========
Diluted net income per common share (Notes 1 and 16) $ 0.19 $ 0.17
=========== ===========
</TABLE>

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

F-4
<PAGE> 28

PRIMEENERGY CORPORATION and SUBSIDIARIES

CONSOLIDATED STATEMENT of STOCKHOLDERS' EQUITY

for the years ended December 31, 1997 and 1996

<TABLE>
<CAPTION>
Retained
Additional Earnings Encumbered
Common Stock Paid In (Accumulated Treasury Treasury
Shares Amount Capital Deficit) Stock Stock Total
------------ ------------ ------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at December
31, 1995 7,597,970 $ 760,000 $ 10,888,000 ($ 992,000) ($ 3,589,000) -- $ 7,067,000

Purchased 105,388 shares
of Common stock (398,000) (398,000)

Purchased 400,000 shares
of Encumbered treasury
stock (Note 6) (523,000) (621,000) (1,144,000)

Net income 939,000 939,000
------------ ------------ ------------ ------------ ------------ ------------ ------------
Balance at December 31,
1996 7,597,970 760,000 10,888,000 (53,000) (4,510,000) (621,000) 6,464,000

Purchased 121,807 shares
of Common stock (872,000) (872,000)

Amortization of
encumbered Treasury
stock (Note 6) (621,000) 621,000 --

Net income 1,024,000 1,024,000
------------ ------------ ------------ ------------ ------------ ------------ ------------
Balance at
December 31, 1997 7,597,970 $ 760,000 $ 10,888,000 $ 971,000 ($ 6,003,000) -- $ 6,616,000
============ ============ ============ ============ ============ ============ ============
</TABLE>

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

F-5
<PAGE> 29

PRIMEENERGY CORPORATION and SUBSIDIARIES

CONSOLIDATED STATEMENTS of CASH FLOWS

for the years ended December 31, 1997 and 1996

--------

<TABLE>
<CAPTION>
1997 1996
------------ ------------
<S> <C> <C>
Cash flows from operating activities:
Net income $ 1,024,000 $ 939,000
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization 6,795,000 5,039,000
Gain on sale of properties (294,000) (175,000)
Provision of deferred income taxes 20,000 (14,000)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable 572,000 (2,741,000)
(Increase) decrease in due from related parties (270,000) 755,000
(Increase) decrease in other assets 54,000 252,000
(Increase) decrease in prepaid expenses 43,000 1,000
Increase in accounts payable 814,000 2,656,000
Increase (decrease) in accrued liabilities (76,000) 114,000
Increase (decrease) in due to related parties 91,000 (21,000)
------------ ------------
Net cash provided by operating activities 8,773,000 6,805,000
------------ ------------

Cash flows from investing activities:
Proceeds from sale of properties and equipment 1,019,000 291,000
Additions to property and equipment (9,817,000) (13,434,000)
(Increase) decrease in notes receivable 40,000 (40,000)
------------ ------------
Net cash used in investing activities (8,758,000) (13,183,000)
------------ ------------

Cash flows from financing activities:
Purchase of stock for treasury (1,493,000) (921,000)
Repayment of long-term bank debt and other long-term obligations (36,252,000) (20,677,000)
Increase in long-term bank debt and other long-term obligations 37,401,000 30,283,000
------------ ------------
Net cash provided by (used in) financing activities (344,000) 8,685,000
------------ ------------
Net increase (decrease) in cash (329,000) 2,307,000

Cash and cash equivalents, beginning of year 3,316,000 1,009,000
------------ ------------
Cash and cash equivalents, end of year $ 2,987,000 $ 3,316,000
============ ============

Supplemental disclosures:
Income taxes paid during the year $ 76,000 $ 79,000
Interest paid during the year $ 1,164,000 $ 905,000
</TABLE>

Supplemental information of non-cash investing and financial activities:

During 1996, the Company purchased treasury stock in return for a note in
the amount of $1,144,000. (Note 6)

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

F-6
<PAGE> 30

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
53 private and publicly-held limited partnerships and trusts (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, Nevada, New Mexico,
North Dakota, Oklahoma, Texas, Utah, West Virginia and Wyoming. The
Company operates approximately 1,704 wells and owns non-operating
interests in approximately 908 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.

The Company has significant deferred tax assets which have been fully
reserved against based upon the assumption that at current and expected
future levels of taxable income, and considering the Section 29 credits
the Company expects to generate, the availability of these
carryforwards will not lead to significant reductions in the Company's
tax liability as compared to what it would pay if such carryforwards
did not exist. Increases in estimates of future taxable income could
lead to significant reductions in the amount of this reserve, which
could have a material effect on the net income of the Company.

F-7
<PAGE> 31

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued

---------

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 related partnerships, trusts or joint ventures are deferred
and charged to the related entity upon the completion of the
acquisition. To the extent that the Company acquires an interest in the
property, an appropriate allocation of internal costs are capitalized
as part of the depletable base of the property.

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

Income Taxes:

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

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

General and Administrative Expenses:

General and administrative expenses represent costs and expenses
associated with the operation of the Company. Certain partnerships and
trusts 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," described below in Recently Issued Accounting Standards.

Statements of cash flows:

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

Concentration of Credit Risk:

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

F-8
<PAGE> 32

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued

---------

Hedging:

From time to time the Company may enter into futures contracts in order
to reduce its exposure related to changes in oil and gas prices. In
accordance with Statement of Financial Accounting Standards No. 80, any
gain or loss on such contracts is treated as an adjustment to oil and
gas revenue.

Recently Issued Accounting Standards:

In June 1997, the Financial Accounting Standards Board released
Statement No. 130, "Reporting Comprehensive Income" and Statement No.
131, "Disclosures about Segments of an Enterprise and Related
Information." Both statements become effective for fiscal years
beginning after December 15, 1997 with early adoption permitted. These
statements require disclosure of certain components of changes in
equity and certain information about operating segments and geographic
areas of operation. The Company will adopt these statements effective
January 1, 1998. These statements will not have any effect on the
results of operations or financial position.

In February 1997, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards ("SFAS") No. 128, "Earnings
per Share" (EPS). SFAS No. 128 replaces the standards for computing
earnings per share previously established by APB No. 15, "Earnings per
Share," by replacing the primary EPS with a presentation of "basic EPS"
and requiring dual presentation of basic and diluted EPS on the face of
the income statement. SFAS No. 128 requires companies to adopt its
provisions for fiscal years ending after December 15, 1997 and requires
restatement of all prior period EPS data, if necessary. Earnings per
share information has been presented on the financial statements and
its computations disclosed in footnote 16 in accordance with SFAS No.
128.

2. SIGNIFICANT ACQUISITIONS AND DISPOSITIONS

1997

San Juan Basin Property Divestment
In April of 1997, the Company sold all of its interests in certain oil
and gas producing properties located in the San Juan Basin to Chateau
Oil and Gas, Inc. for the amount of $680,000. These properties are
operated by others and consist of 151 gross (10.53 net) wells located
in San Juan and Rio Arriba Counties, New Mexico. The Company owned an
average of 9.18 percent working interest and 6.97 net revenue interest
in these properties.

3D Seismic Development and Exploration Program:
During 1997, the Company acquired or took options on certain leasehold
mineral rights as part of its on-going oil and gas exploration and
development activities. The Company acquired leasehold mineral rights
covering 16,600 gross (7,300 net) acres and took options covering
49,129 gross (20,582 net) acres. In addition to the 1997 exploration
activities, the Company plans future exploration and development of
these mineral rights. The Company continues to expand this program with
additional 3D seismic surveys, leasehold acquisitions and drilling.
Outside investors have continued to participate in the subsequent
activities.

Other:
As more fully described in Note 8, the Company is committed to offer to
repurchase the interests of the limited partners and trust unitholders
in certain managed limited partnerships and trusts. During 1997, the
Company purchased such interests in an amount totaling $1,242,000.

F-9
<PAGE> 33

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued

---------

1996

Saratoga Property Acquisition:
In May 1996, the Company completed the acquisition of various interests
in 145 active wells previously owned by Saratoga Resources, Inc. from
Internationale Nederlanden (U.S.) Capital Corporation (herein referred
to as "ING") for $7,180,000. The Company serves as operator for 132 of
these wells. These properties are located primarily in eight counties
along the Gulf Coast of Texas. These properties also include additional
development potential. Pursuant to the purchase and sale agreement, ING
has retained a net profits interest in the development of these
properties, subject to performance hurdles.

During 1996, wells were drilled on properties acquired in the Saratoga
Property Acquisition. In October 1996, the S.F. Wing No. 82 well was
drilled in the Segno field of Polk County, Texas. The well was
completed in the Yegua Formation at an initial production rate of
approximately 90 Barrels of oil per day and 500 MCF of gas per day. The
Company owns 20% of this property. Also in October 1996, the Fling
Point No. 1H was drilled as a horizontal well in the Brookeland field,
of Sabine County, Texas. This well was completed in the Austin Chalk
Formation at an initial production rate of approximately 2,500 MCF of
gas per day. The Company owns eight percent of this property.

The purchase of Saratoga, described above, constitutes a significant
acquisition. The following unaudited proforma data presents financial
information as if the Saratoga acquisition was made at the beginning of
the periods indicated:

<TABLE>
<CAPTION>
December 31,
---------------------------
1996 1995
------------- -----------
<S> <C> <C>
Revenue $ 24,318,000 $21,114,000
============= ===========
Net income $ 1,169,000 $ 635,000
============= ===========
Net income per common share $ .20 $ .11
============= ===========
</TABLE>

These proforma results have been prepared for comparative purposes only
and do not purport to be indicative of what would have occurred had the
acquisition been made at the beginning of 1996 and 1995 or of results
which may occur in the future.

3D Seismic Development and Exploration Program:
Capital committed under the 1995 Development Program was expended
during 1996 on the initial phase of this development and exploration
program. The Company continued to expand this program with additional
3D seismic surveys, leasehold acquisitions and drilling. Outside
investors continued to participate in the subsequent phases. The
Company's interest in these activities ranges from 37% to 52%.

Other:
As more fully described in Note 8, the Company is committed to offer to
repurchase the interests of the limited partners and trust unitholders
in certain managed limited partnerships and trusts. During 1996, the
Company purchased such interests in an amount totaling $538,000.

F-10
<PAGE> 34

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued

---------

3. ACCOUNTS RECEIVABLE

Accounts receivable at December 31, 1997 and 1996 consisted of the
following:

<TABLE>
<CAPTION>
December 31,
--------------------------
1997 1996
----------- -----------
<S> <C> <C>
Joint interest billing $ 1,601,000 $ 1,533,000
Trade receivables 213,000 126,000
Oil and gas sales 2,630,000 3,337,000
Other 62,000 99,000
----------- -----------
4,506,000 5,095,000
Less, allowance for doubtful accounts (26,000) (43,000)
----------- -----------
$ 4,480,000 $ 5,052,000
=========== ===========
</TABLE>

4. LONG-TERM BANK DEBT

At December 31, 1996, the Company was party to a line of credit
agreement with a bank with a non-reducing borrowing base of $19 million.
Twenty-five percent of the borrowing is syndicated to a second bank.
During 1996, the agreement provided for interest at 1/2% over the bank's
base rate as defined, or 2-3/4% over the London Inter-Bank Offered Rate
(LIBOR rate) for the interest period in question, payable at the end of
the interest period.

On February 6, 1997, the bank extended the borrowing base to $21
million. The credit agreement was also amended to provide for interest
on outstanding borrowings at the bank's base rate, as defined, or 2 1/4%
over the LIBOR rate. Effective in May, 1997, the bank revised the
borrowing base to $20.5 million due to the sale of properties by the
Company. In September, 1997, the borrowing base was again revised to $20
million. The average interest rates paid on outstanding borrowings
subject to interest at the bank's base rate during 1997 and at 1/2% over
the bank's base rate during 1996 were 8.58% and 8.79%, respectively.
During the same periods, the average rates paid on outstanding
borrowings bearing interest based upon the LIBO rate were 8.04% and
8.33%. As of December 31, 1997 and 1996, the total outstanding
borrowings were $18.9 million and $17.4 million, respectively, of which
$13.7 million and $12.6 million accrued interest at the LIBOR rate
option.

Effective January 2, 1998, the credit agreement was amended to implement
an interest rate schedule that is based upon the aggregate principal
amount of loans outstanding as a percentage of the borrowing base. The
amendment provides for interest on outstanding borrowings at the bank's
base rate, as defined, or from 1 1/2% to 2% over the LIBOR rate
depending upon the Company's utilization of the available line of
credit.

Advances pursuant to the agreement are limited to the borrowing base as
defined in the agreement. Most of the Company's oil and gas properties
as well as certain receivables and equipment are pledged as security
under this agreement. Under the Company's credit agreement, the Company
is required to maintain, as defined, a minimum current ratio, tangible
net worth, debt coverage ratio and interest coverage ratio.

F-11
<PAGE> 35

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued

---------

5. OTHER LONG-TERM OBLIGATIONS

Other long-term obligations at December 31, 1996 consisted of the
following:

<TABLE>
<CAPTION>
1996
---------
<S> <C>
Subordinated debentures $ 225,000
Capital lease obligations 91,000
---------
316,000
Less, current portion (73,000)
---------
$ 243,000
=========
</TABLE>

The secured subordinated debentures were held by affiliated
Partnerships in which PEMC is a general partner. Interest was payable
at 6.5% through 1996. All of the above long-term obligations were paid
in full during 1997.

6. ENCUMBERED TREASURY STOCK

In June of 1996, the Company entered into an agreement to purchase
400,000 shares of the Company's common stock from McJunkin Corporation.
The Company agreed to make 15 monthly payments of $80,000 beginning on
June 1, 1996, with the shares held in escrow until such payments were
made. The shares were classified as encumbered treasury stock on the
balance sheet, and were unencumbered in proportion to the payments made
under the agreement. The liability for future payments under the note,
less imputed interest, was shown as "Payable For Encumbered Treasury
Stock" on the balance sheet. As of December 31, 1997, all shares
purchased under this agreement were fully unencumbered and are included
in treasury stock on the balance sheet.

7. 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. Future
minimum lease payments under operating leases are as follows:

F-12
<PAGE> 36

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued

---------

8. 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.

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 (150) 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 recent years, the
Company has chosen to purchase limited partner interests in excess of
its commitment.

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.

9. STOCK OPTIONS AND OTHER COMPENSATION

In May 1989, non-statutory stock options were granted by the Company to
four key executive officers for the purchase of shares of common stock.
Such options are exercisable, on a cumulative basis, as to twenty
percent of the shares subject to option in each year, beginning one
year after the granting of the option. At December 31, 1997, options on
802,500 shares were outstanding and exercisable at prices ranging from
$1.00 to $1.25.

On January 27, 1983, the Company adopted the 1983 Incentive Stock
Option Plan. At December 31, 1997 and 1996, options on 124,000 shares
were exercisable at $1.50 per share 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 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.

F-13
<PAGE> 37

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued

---------

10. INCOME TAXES

The components of the provision for income taxes for the year ended
December 31, 1997 and 1996 are as follows:

<TABLE>
<CAPTION>
Federal: 1997 1996
-------- --------
<S> <C> <C>
Current $ 28,000 $ 23,000
Deferred 11,000 --
State:
Current 65,000 40,000
Deferred 8,000 (13,000)
-------- --------
$112,000 $ 50,000
======== ========
</TABLE>

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

<TABLE>
<CAPTION>
December 31, December 31,
----------- -----------
1997 1996
----------- -----------
<S> <C> <C>
Current assets:
Compensation and benefits $ 112,000 $ 102,000
Allowance for doubtful accounts 9,000 17,000
----------- -----------
121,000 119,000
----------- -----------
Noncurrent assets:
Depreciation 329,000 74,000
Due from related parties reserve 316,000 316,000
Net operating loss carryforwards 621,000 747,000
Percentage depletion carryforwards 1,067,000 1,116,000
Alternative minimum tax credits 757,000 729,000
Less, Valuation allowance (1,194,000) (1,607,000)
----------- -----------
1,896,000 1,375,000
----------- -----------
Noncurrent liabilities:
Basis differences relating to limited partnerships (837,000) (813,000)
Depletion (1,321,000) (802,000)
----------- -----------
(2,158,000) (1,615,000)
----------- -----------
Net deferred tax liabilities: $ (141,000) $ (121,000)
=========== ===========
</TABLE>

F-14
<PAGE> 38

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued

---------

The total provision for income taxes for the years ended December 31,
1997 and 1996 varies from the federal statutory tax rate as a result of
the following:

<TABLE>
<CAPTION>
December 31, December 31,
1997 1996
------------ ------------
<S> <C> <C>
Expected statutory tax rate 34.0% 34.0%
State income tax, net of federal benefit 6.4% 2.7%
Effect of utilizing net operating loss carryforwards (11.0%) (12.6%)
Percentage depletion (4.9%) (9.9%)
Intangible drilling costs (14.6%) (9.1%)
------ ------
9.9% 5.1%
====== ======
</TABLE>

At December 31, 1997, the Company had federal tax net operating loss
carryforwards for both regular income tax purposes and alternative
minimum tax ("AMT") purposes of $825,000. Due to the change in control
of the Company on October 7, 1987, the Company is limited in utilizing
its annual net operating loss carryforwards. Based on the current
ownership and IRS statutes, the annual amount available to the Company
is approximately $366,000. Net loss carryforwards expire beginning in
1998 through 2002. This applies to the alternative minimum tax net
operating loss carryforwards, which can be used to offset 90% of AMT
income in future years. The Company has percentage depletion
carryforwards of approximately $2,648,000 for regular tax purposes and
$2,322,000 for alternative minimum tax purposes. The Company has
approximately $757,000 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.

11. SEGMENT INFORMATION AND MAJOR CUSTOMERS

The Company operates in one industry - oil and gas exploration,
development and operation. 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.
While the Company is not dependent on any one purchaser of its
production, oil and gas revenue in 1997 included sales to one purchaser
for $3,627,000 which represented approximately 23% of the Company's
total revenue from oil and gas sales. In 1997 and 1996, $1,592,000 and
$1,401,000, respectively, of revenue was generated from sales to
another purchaser, representing an additional 10% of the Company's
total oil and gas revenue in 1997 and 12% in 1996. In 1996, $1,378,000
of revenue from sales to a third purchaser represented 12% of the
Company's total oil and gas revenue. The above sales were made under
various contractual arrangements, some of which are month-to-month;
however, the Company believes that these purchasers will continue to
purchase oil and gas products and, if not, could be replaced by other
purchasers.

12. RELATED PARTY TRANSACTIONS

PEMC is a general partner in several oil and gas Partnerships in which
certain directors have limited and general partnership interests.
Substantially all of the assets and revenues of PEMC are derived from
its sponsorship of the Partnerships and the interests of PEMC in the
oil and gas properties acquired by the Partnerships. 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.

F-15
<PAGE> 39

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued

---------

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 of which a Company Officer and Director
is a general partner. During 1996, the principal of the loan was
increased by $40,000, representing additional funds disbursed to the
limited partnership in May and August of 1996. During 1997, the Company
received several loan payments from the borrower, reducing the
principal by approximately $40,000. This loan is 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 provides 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 are not
sufficient, then the accrued interest is added to the principal.
Amounts due, included in other non-current assets on the balance sheet,
were $480,000 and $520,000 at December 31, 1997 and 1996, respectively.

Due to related parties at December 31, 1997 and December 31, 1996
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 $1,389,000 and $1,298,000 at December 31,
1997 and 1996, respectively. Receivables from affiliates consist of
reimbursable general and administrative costs, lease operating expenses
and reimbursements for property acquisitions, development, and related
costs.

13. RESTRICTED CASH AND CASH EQUIVALENTS

Restricted cash and cash equivalents includes $885,000 and $663,000 at
December 31, 1997 and December 31, 1996, respectively, of cash
primarily pertaining to unclaimed royalty payments. There were
corresponding accounts payable recorded at December 31, 1997 and 1996
for these liabilities.

14. 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 $221,000 and $207,000 in 1997 and 1996, respectively.

15. ACCOUNTS PAYABLE

A summary of accounts payable at December 31, 1997 and 1996 is as
follows:

<TABLE>
<CAPTION>
1997 1996
---------- ----------
<S> <C> <C>
Payables to unaffiliated interests $6,285,000 $5,221,000
Other 48,000 76,000
---------- ----------
$6,333,000 $5,297,000
========== ==========
</TABLE>

F-16
<PAGE> 40

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued

---------

16. 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, 1997 December 31, 1996
------------------------------------ ------------------------------------
Net Number of Per Share Net Number of Per Share
Income Shares Amount Income Shares Amount
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Net income per common
share $1,024,000 4,664,957 $ 0.22 $ 939,000 4,966,615 $ 0.19

Effect of dilutive securities:
Options -- 784,696 (0.03) -- 617,927 (0.02)
---------- ---------- ---------- ---------- ---------- ----------

Diluted net income per
common share $1,024,000 5,449,653 $ 0.19 $ 939,000 5,584,542 $ 0.17
========== ========== ========== ========== ========== ==========
</TABLE>

17. SUBSEQUENT EVENTS

In January of 1998, the Company purchased 53,334 shares of its stock
for treasury from Stanford University and 53,334 shares from the
University of California. The total combined cost of these two
purchases was $853,000.

18. SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

<TABLE>
<CAPTION>
Year Ended
December 31, Fourth Third Second First
1997 Quarter Quarter Quarter Quarter
<S> <C> <C> <C> <C> <C>
Revenue $ 28,725,000 $ 7,554,000 $6,926,000 $6,837,000 $7,408,000

Operating income 842,000 232,000 (37,000) 20,000 627,000

Net income 1,024,000 260,000 50,000 130,000 584,000

Net income per common
share $.22 $.06 $.01 $.03 $.12

Diluted net income per
common share $.19 $.05 $.01 $.02 $.11
</TABLE>

F-17
<PAGE> 41

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued

---------

<TABLE>
<CAPTION>
Year Ended
December 31, Fourth Third Second First
1996 Quarter Quarter Quarter Quarter
<S> <C> <C> <C> <C> <C>
Revenue $ 23,226,000 $ 7,341,000 $ 6,044,000 $5,395,000 $ 4,446,000

Operating income 814,000 533,000 267,000 4,000 10,000

Net income 939,000 546,000 284,000 73,000 36,000

Net income per common
share $.19 $.11 $.06 $.01 $.01

Diluted net income per common
share $.17 $.10 $.05 $.01 $.01
</TABLE>

F-18
<PAGE> 42

PRIMEENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION

-----

(UNAUDITED)

F-19
<PAGE> 43

PRIMEENERGY CORPORATION and SUBSIDIARIES

CAPITALIZED COSTS RELATING to OIL and GAS PRODUCING ACTIVITIES

December 31, 1997 and 1996

---------

(Unaudited)

<TABLE>
<CAPTION>
1997 1996
----------- -----------
<S> <C> <C>
Developed oil and gas properties $41,427,000 $35,952,000
Undeveloped oil and gas properties-- 231,000 872,000
----------- -----------

41,658,000 36,824,000

Accumulated depreciation, depletion and valuation allowance 21,397,000 18,661,000
----------- -----------

Net capitalized costs (1) $20,261,000 $18,163,000
=========== ===========
</TABLE>

(1) Includes $140,000 in 1997 and $160,000 in 1996 related to the net cost
of gas gathering facilities.

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

Years ended December 31, 1997 and 1996

---------

(Unaudited)

<TABLE>
<CAPTION>
1997 1996
---------- ----------
<S> <C> <C>
Acquisition of properties:
Developed $1,345,000 $7,281,000
Undeveloped 231,000 872,000

Exploration costs, excluding valuation allowance 2,411,000 483,000

Development costs 7,079,000 4,274,000
</TABLE>

See accompanying notes to supplementary information.

F-20
<PAGE> 44

PRIMEENERGY CORPORATION and SUBSIDIARIES

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

years ended December 31, 1997 AND 1996

---------

(Unaudited)

<TABLE>
<CAPTION>
1997 1996
------------ ------------
<S> <C> <C>
Future cash inflows $ 62,024,000 $ 95,679,000

Future production and development costs (31,135,000) (44,329,000)

Future income tax expenses (1,321,000) (6,488,000)
------------ ------------

Future net cash flows 29,568,000 44,862,000

10% annual discount for estimated timing of cash flow (8,875,000) (14,220,000)
------------ ------------
Standardized measure of discounted
future net cash flow $ 20,693,000 $ 30,642,000
============ ============
</TABLE>

See accompanying notes to supplementary information.

F-21
<PAGE> 45

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, 1997 and 1996

---------

(Unaudited)

The following are the principal sources of change in the standardized measure of
discounted future net cash flows during 1997 and 1996

<TABLE>
<CAPTION>
1997 1996
------------ ------------
<S> <C> <C>
Sales of oil and gas produced, net of production costs $ (8,450,000) $ (5,329,000)
Net changes in prices and production costs (4,735,000) 7,803,000
Extensions, discoveries and improved recovery,
less recovery costs 6,782,000 7,897,000
Revisions of previous quantity estimates (3,082,000) 4,827,000
Reserves purchases, net of development costs 2,923,000 9,783,000
Net change in development costs (116,000) (26,000)

Reserves sold (2,007,000) --

Accretion of discount 3,064,000 913,000

Net change in income taxes (3,405,000) (4,200,000)
Other (923,000) (160,000)
------------ ------------
Net change (9,949,000) 21,508,000

Standardized measure of discounted future net cash flow:

Beginning of year 30,642,000 9,134,000
------------ ------------
End of year $ 20,693,000 $ 30,642,000
============ ============
</TABLE>

See accompanying notes to supplementary information

F-22
<PAGE> 46

PRIMEENERGY CORPORATION and SUBSIDIARIES

RESERVE QUANTITY INFORMATION

years ended December 31, 1997 and 1996

---------

(Unaudited)

<TABLE>
<CAPTION>
1997 1996
-------------------------- --------------------------
Gas Oil Gas Oil
(Mcf) (bbls.) (Mcf) (bbls.)
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Proved developed and undeveloped reserves:
Beginning of year 19,065,000 1,466,000 13,600,000 905,000
Extensions, discoveries
and improved recovery 3,764,000 282,000 3,746,000 90,000
Revisions of previous
estimates (1) (1,731,000) (121,000) 1,012,000 (14,000)
Sales (2,086,000) (42,000) -- --
Purchases 1,550,000 133,000 3,595,000 734,000
Production (3,901,000) (277,000) (2,888,000) (249,000)
----------- ----------- ----------- -----------

End of year 16,661,000 1,441,000 19,065,000 1,466,000
=========== =========== =========== ===========

Proved developed reserves 16,661,000 1,364,000 19,036,000 1,453,000
=========== =========== =========== ===========
</TABLE>

(1) Revisions during 1996 and 1997 relate primarily to changes in prices.

See accompanying notes to supplementary information

F-23
<PAGE> 47

PRIMEENERGY CORPORATION and SUBSIDIARIES

RESULTS of OPERATIONS from OIL and GAS PRODUCTING ACTIVITIES

years ended December 31, 1997 and 1996

---------

(Unaudited)

<TABLE>
<CAPTION>
1997 1996
----------- -----------
<S> <C> <C>
Revenue:
Oil and gas sales $15,485,000 $11,238,000
----------- -----------

Costs and expenses:
Lease operating expense 7,035,000 5,909,000
Exploration costs 2,411,000 483,000
Depreciation and depletion 5,895,000 4,283,000
Income tax (benefit) expense 10,000 --
----------- -----------
15,351,000 10,675,000
----------- -----------

Results of operations from producing activities
(excluding corporate overhead and interest costs) $ 134,000 $ 563,000
=========== ===========
</TABLE>

See accompanying notes to supplementary information

F-24
<PAGE> 48

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-25
<PAGE> 49
INDEX TO EXHIBITS

Exhibit
Number Description
------ -----------
3.1 -- Certificate of Incorporation as amended, of PrimeEnergy
Corporation. (Incorporated herein by reference to Exhibit 3.1
of PrimeEnergy Corporation Form 10-KSB for the year ended
December 31, 1994)

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, 1994)

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

10.7.2 -- 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)

10.18 -- Composite copy of Non-Statutory Option Agreements. (filed
herewith)(1)

21 -- Subsidiaries. (filed herewith)

23 -- Consent of Ryder Scott Company. (filed herewith)

27 -- Financial Data Schedule. (filed herewith)

- --------------

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

<PAGE> 1

================================================================================

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

================================================================================
<PAGE> 2

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C> <C>
ARTICLE I DEFINITIONS . . . . . . . . . . . . . . . . . . . . . . 1
1.01 Terms Defined Above . . . . . . . . . . . . . . . 1
1.02 Terms Defined in Agreement . . . . . . . . . . . . 1
1.03 References . . . . . . . . . . . . . . . . . . . . 1
1.04 Articles and Sections . . . . . . . . . . . . . . 2
1.05 Number and Gender . . . . . . . . . . . . . . . . 2

ARTICLE II AMENDMENTS . . . . . . . . . . . . . . . . . . . . . . . 2
2.01 Amendment of Section 1.2 . . . . . . . . . . . . . 2
2.02 Amendment of Section 2.14 . . . . . . . . . . . . 2
2.03 Amendment of Section 2.16 . . . . . . . . . . . . 3

ARTICLE III CONDITIONS . . . . . . . . . . . . . . . . . . . . . . . 3
3.01 Receipt of Loan Documents . . . . . . . . . . . . . 3
3.02 Accuracy of Representations and Warranties;
No Default or Event of Default . . . . . . . . . . 3
3.03 Payment of Fees and Expenses . . . . . . . . . . . 3
3.04 Matters Satisfactory to Lenders . . . . . . . . . . 3
3.05 No Material Adverse Effect . . . . . . . . . . . . 3

ARTICLE IV REPRESENTATIONS AND WARRANTIES . . . . . . . . . . . . . 4
4.01 Due Authorization . . . . . . . . . . . . . . . . . 4
4.02 Valid and Binding Obligations of Borrowers . . . . 4
4.03 Representations and Warranties in Credit
Agreement . . . . . . . . . . . . . . . . . . . . . 4
4.04 No Default or Event of Default . . . . . . . . . . 4
4.05 Ratification and Confirmation of Liens . . . . . . 4

ARTICLE V MISCELLANEOUS . . . . . . . . . . . . . . . . . . . . . 5
5.01 Survival Upon Unenforceability . . . . . . . . . . 5
5.02 Rights of Third Parties . . . . . . . . . . . . . . 5
5.03 Amendments or Modifications . . . . . . . . . . . . 5
5.04 Ratification . . . . . . . . . . . . . . . . . . . 5
5.05 Expenses . . . . . . . . . . . . . . . . . . . . . 5
5.06 ENTIRE AGREEMENT; NO ORAL AGREEMENTS . . . . . . . 5
5.07 GOVERNING LAW . . . . . . . . . . . . . . . . . . . 5
5.08 JURISDICTION AND VENUE . . . . . . . . . . . . . . 6
5.09 Counterparts . . . . . . . . . . . . . . . . . . . 6
</TABLE>

i
<PAGE> 3
THIRD AMENDMENT TO CREDIT AGREEMENT

This THIRD AMENDMENT TO CREDIT AGREEMENT (this "Amendment") is
made and entered into effective as of January 2, 1998, by and among PRIMEENERGY
CORPORATION, a Delaware corporation ("PEC"), PRIMEENERGY MANAGEMENT
CORPORATION, a New York corporation ("PEMC," with PEC and PEMC being
individually referred to as a "Borrower" and collectively as the "Borrowers"),
BANK ONE, TEXAS, NATIONAL ASSOCIATION, a national banking association ("Bank
One"), and DEN NORSKE BANK ASA, a Norwegian bank ("DNB," with Bank One, DNB,
and each other lender that becomes signatory, individually, together with its
successors and assigns, a "Lender and, collectively, together with their
respective successors and assigns, the "Lenders"), and Bank One, as agent for
the Lenders (in such capacity, together with its successors in such capacity,
the "Agent").

W I T N E S S E T H:

WHEREAS, the above named parties did execute and exchange
counterparts of that certain Credit Agreement dated April 26, 1995, as amended
by First Amendment to Credit Agreement dated effective as of October 6, 1995,
as further amended by Second Amendment to Credit Agreement dated effective as
of February 6, 1997 (the "Agreement"), to which reference is here made for all
purposes;

WHEREAS, the parties subject to and bound by the Agreement are
desirous of amending the Agreement in the particulars hereinafter set forth;

NOW, THEREFORE, in consideration of the mutual covenants and
agreements of the parties to the Agreement, as set forth therein, and the
mutual covenants and agreements of the parties hereto, as set forth in this
Amendment, the parties hereto agree as follows:

ARTICLE I

DEFINITIONS

1.01 Terms Defined Above. As used herein, each of the terms
"Agent," "Amendment," "Bank One," "Borrower," "Borrowers," "Credit Agreement,"
"DNB," "Lender," "Lenders," "PEC," and "PEMC" shall have the meaning assigned
to such term hereinabove.

1.02 Terms Defined in Agreement. As used herein, each term
defined in the Agreement shall have the meaning assigned thereto in the
Agreement, unless expressly provided herein to the contrary.

1.03 References. References in this Amendment to Article or
Section numbers shall be to Articles and Sections of this Amendment, unless
expressly stated herein to the contrary. References in this Amendment to
"hereby," "herein," "hereinafter," "hereinabove,"

<PAGE> 4
"hereinbelow," "hereof," and "hereunder" shall be to this Amendment in its
entirety and not only to the particular Article or Section in which such
reference appears.

1.04 Articles and Sections. This Amendment, for convenience
only, has been divided into Articles and Sections and it is understood that the
rights, powers, privileges, duties, and other legal relations of the parties
hereto shall be determined from this Amendment as an entirety and without
regard to such division into Articles and Sections and without regard to
headings prefixed to such Articles and Sections.

1.05 Number and Gender. Whenever the context requires,
reference herein made to the single number shall be understood to include the
plural and likewise the plural shall be understood to include the singular.
Words denoting sex shall be construed to include the masculine, feminine, and
neuter, when such construction is appropriate, and specific enumeration shall
not exclude the general, but shall be construed as cumulative. Definitions of
terms defined in the singular and plural shall be equally applicable to the
plural or singular, as the case may be.

ARTICLE II

AMENDMENTS

The Borrower and the Lender hereby amend the Agreement in the
following particulars:

2.01 Amendment of Section 1.2. Section 1.2 of the
Agreement is hereby amended as follows:

The following definitions are added and/or amended to read as
follows:

"Applicable Margin" shall mean as to each Floating Rate Loan,
zero percent (0%) and as to each LIBO Rate Loan, the following:

<TABLE>
<CAPTION>
Borrowing Base LIBO Rate Loan
Utilization Applicable Margin
---------------- -----------------
<S> <C>
1) greater than 75% two percent (2%)
of Borrowing Base

2) less than or equal to one and three-fourths
75% and greater than percent (1-3/4%)
50% of Borrowing Base

3) less than or equal to one and one-half
50% of Borrowing Base percent (1-1/2%)
</TABLE>

2
<PAGE> 5
The LIBO Rate Loan Applicable Margin shall change and be
calculated on the day the Borrowing Base Utilization changes.

"Borrowing Base Utilization" shall mean the aggregate
principal amount of Loans outstanding hereunder as a percentage of the
Borrowing Base."

2.02 Amendment of Section 2.14. Section 2.14 shall be
amended as follows:

"The Commitment Fee set forth herein shall be reduced to
three-eighths percent (3/8%)."

2.03 Amendment of Section 2.16. Section 2.16 is amended
to add the following:

"Notwithstanding the above, the Facility Fee will be one-half
percent (1/2%) on all increases in the Borrowing Base."

ARTICLE III

CONDITIONS

The obligation of the Agent and the Lenders to amend the
Credit Agreement as provided herein is subject to the fulfillment of the
following conditions precedent:

3.01 Receipt of Loan Documents. The Agent shall have
received multiple counterparts, as requested by the Agent, of this Amendment,
executed by the Borrowers, which shall be in form and substance satisfactory to
the Agent.

3.02 Accuracy of Representations and Warranties; No
Default or Event of Default. The representations and warranties contained in
Article IV of this Amendment shall be true and correct in all material
respects; and no Default or Event of Default shall have occurred and be
continuing.

3.03 Payment of Fees and Expenses. The Agent shall have
received reimbursement from the Borrowers, or special legal counsel for the
Agent shall have received payment from the Borrowers, for all reasonable fees
and expenses of counsel to the Lenders for which the Borrowers are responsible
pursuant to applicable provisions of this Amendment and the Credit Agreement
for which invoices have been presented as of or prior to the date hereof.

3.04 Matters Satisfactory to Lenders. All matters
incident to the consummation of the transactions hereby contemplated shall be
reasonably satisfactory to the Lenders.

3.05 No Material Adverse Effect. No event or circumstance
shall have occurred since June 30, 1995, that could reasonably be expected to
have a Material Adverse Effect.

3
<PAGE> 6
ARTICLE IV

REPRESENTATIONS AND WARRANTIES

To induce the Agent and the Lenders to enter into this
Amendment and amend the Credit Agreement as provided herein, the Borrowers
represent and warrant to the Agent and each Lender that:

4.01 Due Authorization. The execution and delivery by the
Borrowers of this Amendment and the performance of its obligations hereunder
are within the power of the Borrowers, are duly authorized by all necessary
action on behalf of the Borrowers, and do not and will not (a) require the
consent of any Governmental Authority, (b) contravene or conflict with any
Requirement of Law or the articles or certificate of incorporation, bylaws, or
other organizational or governing documents of the Borrowers, (c) contravene or
conflict with any indenture, instrument or other agreement to which either
Borrower is a party or by which its Property may be presently bound or
encumbered, or (d) result in or require the creation or imposition of any Lien
upon any of the properties or assets of either Borrower under any such
indenture, instrument or other agreement other than the Loan Documents.

4.02 Valid and Binding Obligations of Borrowers. This
Amendment, when duly executed and delivered, will be the legal, valid and
binding obligation of the Borrowers, enforceable in accordance with its terms
(subject to any applicable bankruptcy, insolvency or other laws of general
application affecting creditors' rights and judicial decisions interpreting any
of the foregoing).

4.03 Representations and Warranties in Credit Agreement.
As of the date hereof, all representations and warranties set forth in the
Credit Agreement are true and correct in all material respects, except to the
extent such representations and warranties relate solely to an earlier date.

4.04 No Default or Event of Default. No Default or Event
of Default exists.

4.05 Ratification and Confirmation of Liens. The
Borrowers hereby ratify and confirm all Liens created under the Security
Instruments and acknowledge and agree that all such Liens secure all
Obligations.

4
<PAGE> 7
ARTICLE V

MISCELLANEOUS

5.01 Survival Upon Unenforceability. In the event any one
or more of the provisions contained in this Amendment shall, for any reason, be
held to be invalid, illegal or unenforceable in any respect, such invalidity,
illegality, or unenforceability shall not affect any other provision hereof.

5.02 Rights of Third Parties. All provisions herein are
imposed solely and exclusively for the benefit of the Agent, the Lenders and
the Borrowers, and their successors and permitted assigns. No other Person
shall have any right, benefit, priority, or interest hereunder or as a result
hereof or have standing to require satisfaction of provisions hereof in
accordance with their terms.

5.03 Amendments or Modifications. Neither this Amendment
nor any provision hereof may be changed, waived, discharged or terminated
orally, but only by an instrument in writing signed by the party against whom
enforcement of the change, waiver, discharge or termination is sought.

5.04 Ratification. Except as expressly amended by this
Amendment and the documents executed in connection herewith, the Credit
Agreement and all other Loan Documents shall remain in full force and effect.
The Credit Agreement, as hereby amended, and all rights and powers created
thereby or thereunder and under such other Loan Documents are in all respects
ratified and confirmed.

5.05 Expenses. The Borrowers shall pay to the Agent for
the benefit of the Lenders promptly upon request all expenses incurred in
connection with this Amendment and the documents executed in connection
herewith.

5.06 ENTIRE AGREEMENT; NO ORAL AGREEMENTS. THIS AMENDMENT
CONSTITUTES THE ENTIRE AGREEMENT OF THE PARTIES HERETO WITH RESPECT TO THE
SUBJECT HEREOF AND SUPERSEDES ANY PRIOR AGREEMENT BETWEEN THE PARTIES HERETO,
WHETHER WRITTEN OR ORAL, RELATING TO THE SUBJECT HEREOF. THIS WRITTEN
AGREEMENT AND THE OTHER WRITTEN LOAN DOCUMENTS REPRESENT, COLLECTIVELY, THE
FINAL AGREEMENT AMONG THE PARTIES HERETO AND THERETO AND MAY NOT BE
CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL
AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE
PARTIES.

5.07 GOVERNING LAW. THIS AMENDMENT SHALL BE GOVERNED BY
AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS (WITHOUT GIVING
EFFECT TO PRINCIPLES THEREOF RELATING TO CONFLICTS OF LAW); PROVIDED, HOWEVER,
THAT VERNON'S TEXAS CIVIL

5
<PAGE> 8
STATUTES, ARTICLE 5069, CHAPTER 15 (WHICH REGULATES CERTAIN REVOLVING CREDIT
LOAN ACCOUNTS AND REVOLVING TRIPARTY ACCOUNTS) SHALL NOT APPLY.

5.08 JURISDICTION AND VENUE. ALL ACTIONS OR PROCEEDINGS
WITH RESPECT TO, ARISING DIRECTLY OR INDIRECTLY IN CONNECTION WITH, OUT OF,
RELATED TO OR FROM THIS AMENDMENT MAY BE LITIGATED, AT THE SOLE DISCRETION AND
ELECTION OF THE AGENT, IN COURTS HAVING SITUS IN HOUSTON, HARRIS COUNTY, TEXAS.
EACH BORROWER HEREBY SUBMITS TO THE JURISDICTION OF ANY LOCAL, STATE OR FEDERAL
COURT LOCATED IN HOUSTON, HARRIS COUNTY, TEXAS, AND HEREBY WAIVES ANY RIGHTS IT
MAY HAVE TO TRANSFER OR CHANGE THE JURISDICTION OR VENUE OF ANY LITIGATION
BROUGHT AGAINST IT BY THE AGENT IN ACCORDANCE WITH THIS SECTION.

5.09 Counterparts. This Amendment may be signed in any
number of counterparts and by different parties in separate counterparts, each
of which shall be deemed an original but all of which together shall constitute
one and the same instrument.

IN WITNESS WHEREOF, the parties have caused this Amendment to
be executed by their respective duly authorized officers on the date first
hereinabove written.

BORROWER:

PRIMEENERGY CORPORATION

By: /s/ BEVERLY A. CUMMINGS
------------------------------------
Beverly A. Cummings
Executive Vice President,
Treasurer and
Chief Financial Officer

BORROWER:

PRIMEENERGY MANAGEMENT
CORPORATION

By: /s/ BEVERLY A. CUMMINGS
------------------------------------
Beverly A. Cummings
Executive Vice President,
Treasurer and
Chief Financial Officer

6
<PAGE> 9

AGENT AND LENDER:

BANK ONE, TEXAS, NATIONAL
ASSOCIATION

By:
------------------------------------
Richard Sylvan
Senior Vice President

LENDER:
------

DEN NORSKE BANK ASA

By:
------------------------------------
William V. Moyer
First Vice President

By:
-----------------------------------
Name:
---------------------------------
Title:
--------------------------------

<PAGE> 1

EXHIBIT 10.18

K.R.M. PETROLEUM CORPORATION

NONSTATUTORY STOCK OPTION AGREEMENT

OPTION NO.: 3

OPTIONEE: Charles E. Drimal, Jr.

DATE OF GRANT: May 16, 1989

OPTION PRICE: $1.00

COVERED SHARES: 523,125

1. Definitions. All terms used in this Agreement shall have the
meanings set forth below:

(a) "Agreement" means this Nonstatutory Stock Option
Agreement.

(b) "Change in Control" means the acquisition of 51% or
more of the outstanding voting capital stock of the Corporation by any company
or other person or group of companies or other persons acting in concert, or
the merger or consolidation of the Corporation with, or the acquisition of a
majority of the assets of the Corporation by, any of such persons.

(d) "Common Stock" means the common stock, par value
$0.10 per share, of the Corporation.

(e) "Corporation" means K.R.M. Petroleum Corporation, a
Delaware corporation, and any successor thereto.

(f) "Covered Shares" means the number of Shares set forth
on page 1 of this Agreement.

(g) "Date of Exercise" means the date on which the
Corporation receives notice of the exercise of the Option in accordance with
the terms of Article 4.

<PAGE> 2
K.R.M. PETROLEUM CORPORATION

NONSTATUTORY STOCK OPTION AGREEMENT

OPTION NO.: 4

OPTIONEE: Charles E. Drimal, Jr.

DATE OF GRANT: May 16, 1989

OPTION PRICE: $1.25

COVERED SHARES: 174,375

1. Definitions. All terms used in this Agreement shall have the
meanings set forth below:

(a) "Agreement" means this Nonstatutory Stock Option
Agreement.

(d) "Common Stock" means the common stock, par value
$0.10 per share, of the Corporation.

(e) "Corporation" means K.R.M. Petroleum Corporation, a
Delaware corporation, and any successor thereto.

(f) "Covered Shares" means the number of Shares set forth
on page 1 of this Agreement.

(g) "Date of Exercise" means the date on which the
Corporation receives notice of the exercise of the Option in accordance with
the terms of Article 4.
<PAGE> 3
K.R.M. PETROLEUM CORPORATION

NONSTATUTORY STOCK OPTION AGREEMENT

OPTION NO.: 5

OPTIONEE: Beverly A. Cummings

DATE OF GRANT: May 16, 1989

OPTION PRICE: $1.00

COVERED SHARES: 52,500

1. Definitions. All terms used in this Agreement shall have the
meanings set forth below:

(a) "Agreement" means this Nonstatutory Stock Option
Agreement.

(d) "Common Stock" means the common stock, par value $0.10
per share, of the Corporation.

(e) "Corporation" means K.R.M. Petroleum Corporation, a
Delaware corporation, and any successor thereto.

(f) "Covered Shares" means the number of Shares set forth
on page 1 of this Agreement.

(g) "Date of Exercise" means the date on which the
Corporation receives notice of the exercise of the Option in accordance with
the terms of Article 4.
<PAGE> 4
K.R.M. PETROLEUM CORPORATION

NONSTATUTORY STOCK OPTION AGREEMENT

OPTION NO.: 6

OPTIONEE: Beverly A. Cummings

DATE OF GRANT: May 16, 1989

OPTION PRICE: $1.25

COVERED SHARES: 17,500

1. Definitions. All terms used in this Agreement shall have the
meanings set forth below:

(a) "Agreement" means this Nonstatutory Stock Option
Agreement.

(d) "Common Stock" means the common stock, par value
$0.10 per share, of the Corporation.

(e) "Corporation" means K.R.M. Petroleum Corporation, a
Delaware corporation, and any successor thereto.

(f) "Covered Shares" means the number of Shares set forth
on page 1 of this Agreement.

(g) "Date of Exercise" means the date on which the
Corporation receives notice of the exercise of the Option in accordance with
the terms of Article 4.
<PAGE> 5
K.R.M. PETROLEUM CORPORATION

NONSTATUTORY STOCK OPTION AGREEMENT

OPTION NO.: 7

OPTIONEE: Bennie H. Wallace, Jr.

DATE OF GRANT: May 16, 1989

OPTION PRICE: $1.00

COVERED SHARES: 26,250

1. Definitions. All terms used in this Agreement shall have the
meanings set forth below:

(a) "Agreement" means this Nonstatutory Stock Option
Agreement.

(d) "Common Stock" means the common stock, par value
$0.10 per share, of the Corporation.

(e) "Corporation" means K.R.M. Petroleum Corporation, a
Delaware corporation, and any successor thereto.

(f) "Covered Shares" means the number of Shares set forth
on page 1 of this Agreement.

(g) "Date of Exercise" means the date on which the
Corporation receives notice of the exercise of the Option in accordance with
the terms of Article 4.
<PAGE> 6
K.R.M. PETROLEUM CORPORATION

NONSTATUTORY STOCK OPTION AGREEMENT

OPTION NO.: 8

OPTIONEE: Bennie H. Wallace, Jr.

DATE OF GRANT: May 16, 1989

OPTION PRICE: $1.25

COVERED SHARES: 8,750

1. Definitions. All terms used in this Agreement shall have the
meanings set forth below:

(a) "Agreement" means this Nonstatutory Stock Option
Agreement.

(d) "Common Stock" means the common stock, par value
$0.10 per share, of the Corporation.

(e) "Corporation" means K.R.M. Petroleum Corporation, a
Delaware corporation, and any successor thereto.

(f) "Covered Shares" means the number of Shares set forth
on page 1 of this Agreement.

(g) "Date of Exercise" means the date on which the
Corporation receives notice of the exercise of the Option in accordance with
the terms of Article 4.

<PAGE> 7
2

(h) "Date of Grant" means the date on which the option is
granted.

(i) "Fair Market Value" of a Share means the amount equal
to the fair market value of a Share as determined by the Board pursuant to a
reasonable method adopted in good faith for such purpose.

(j) "Option" means the option to purchase the Covered
Shares granted pursuant to this Agreement.

(k) "Option Period" means the period during which the
option may be exercised.

(l) "Option Price" means the price per Share at which the
Option may be exercised, as set forth on page 1 of this Agreement.

(m) "Optionee" means the individual to whom the Option is
granted.

(n) "Securities Act" means the Securities Act of 1933, as
amended.

(o) "Share" means a share of authorized but unissued or
reacquired Common Stock.

(p) "Subsidiary" means a corporation at least 50% of the
total combined voting power of all classes of stock of which is owned by the
Corporation, either directly or through one or more other Subsidiaries.

2. Grant of Option. Subject to the terms and conditions of this
Agreement, the Corporation hereby grants to the Optionee an Option to purchase
the Covered Shares from the Corporation at the Option Price, as the same may be
adjusted from time to time pursuant to the terms of Article 6.

3. Terms of the Option.

(a) Type of Option. The Option is intended to be a
nonstatutory stock option, and is not an incentive stock option within the
meaning of section 422A of the Code.

(b) Option Period. The Option may be exercised with respect to
full Shares (and no fractional Shares shall be issued) as follows:
<PAGE> 8
3

(i) the Option shall not be exercisable until one
year after the Date of Grant;

(ii) the Option shall be exercisable with respect
to 20% of the Covered Shares beginning one year after the Date of Grant;

(iii) the Option shall be exercisable with respect
to a cumulative maximum of 40% of the Covered Shares beginning two years after
the Date of Grant;

(iv) the Option shall be exercisable with respect
to a cumulative maximum of 60% of the Covered Shares beginning three years after
the Date of Grant;

(v) the Option shall be exercisable with respect
to a cumulative maximum of 80% of the Covered Shares beginning four years after
the Date of Grant; and

(vi) the Option shall be fully exercisable
beginning five years after the Date of Grant.

(c) Notwithstanding anything to the contrary contained
herein, the Option shall expire at the earlier of (i) three months after
termination of the Optionee's employment with the Corporation or its Subsidiary
for any reason except death or disability or (ii) one year after termination of
the Optionee's employment with the Corporation or its Subsidiary by reason of
death or disability.

(d) Nontransferability. The Optionee may not assign or
transfer the option other than by will or by the laws of descent and
distribution. The Option may be exercised, during the Optionee's lifetime, only
by the Optionee. To the extent the Option is exercisable at the time of the
Optionee's death, it is exercisable by the person designated by will or
entitled by the laws of descent and distribution, upon such death, to any
remaining rights arising out of the Option. The Option is not subject, in whole
or in part, to attachment, execution or levy of any kind.

(e) Payment upon Change in Control. Upon a Change in
Control, the Corporation shall pay the Optionee in complete cancellation of the
Option an amount of cash equal to the product of (i) the excess of (A) the Fair
Market Value of a Share on the date of such Change in Control over (B) the
Option Price times (ii) the number of Shares with respect to which the Option
is then outstanding and has not terminated, whether or not the Option is then
exercisable with respect to such Shares.
<PAGE> 9
4

4. Exercise.

(a) Notice. The Option shall be exercised, in whole or in
part, by the delivery to the Corporation of written notice of such exercise, in
such form as the Corporation may from time to time prescribe, accompanied by:
(i) full payment of the Option Price with respect to that portion of the Option
being exercised and (ii) full payment of any amounts required to be withheld
pursuant to applicable income tax laws in connection with such exercise. The
date of delivery of such notice shall be the Date of Exercise of such Option.
Until the Corporation notifies the Optionee to the contrary, the form attached
to this Agreement as Exhibit A shall be used to exercise the Option.

(b) Payment of the Option Price and Withholding. Upon
exercise of the Option, in whole or in part, the Optionee shall pay the Option
Price and satisfy any applicable income tax withholding requirements in cash.

(c) Effect. The exercise, in whole or in part, of the
Option shall cause a reduction in the number of unexercised Covered Shares
equal to the number of Shares with respect to which the Option is exercised.

5. Restrictions on Exercise and upon Shares Issued upon Exercise.
Notwithstanding any other provision of this Agreement, the Optionee agrees, for
himself and his successors, that the Option may not be exercised at any time
that the Corporation does not have in effect a registration statement under the
Securities Act relating to the offer of Common Stock to the Optionee, unless
the Optionee furnishes to the Corporation an opinion of counsel reasonably
satisfactory to the Corporation to the effect that such registration is not
required, or unless the Corporation agrees to permit such exercise. The
Optionee further agrees, for himself and his successors, that (i) upon the
issuance of any Shares upon the exercise of the Option, he will, upon the
request of the Corporation, agree in writing that he is acquiring such Shares
for investment only and not with a view to resale, and (ii) that he will not
sell, pledge or otherwise dispose of such Shares so issued unless and until:

(a) the Corporation is furnished with an opinion of
counsel to the effect that registration of such Shares is not required by the
Securities Act or by the rules and regulations thereunder;
<PAGE> 10
5

(b) the staff of the Securities and Exchange Commission
has issued a "no-action" letter with respect to such disposition; or

(C) such registration or notification as is, in the
opinion of counsel for the Corporation, required for the lawful disposition of
such Shares has been filed by the Corporation and has become effective;
provided, however, that the Corporation is not obligated hereby to file any
such registration or notification.

The Optionee further agrees that the Corporation may place a legend embodying
such restriction on the certificates evidencing such Shares.

6. Capital Adjustments. The number of Shares subject to the
Option and the Option Price shall be subject to such adjustment, if any, as the
Corporation in its sole discretion deems appropriate to reflect such events as
stock dividends, stock splits, recapitalizations, mergers, consolidations or
reorganizations of or by the Corporation.

7. Rights as Shareholder. The Optionee shall have no rights as a
shareholder with respect to any Shares subject to the Option until and unless a
certificate or certificates representing such Shares are issued to the Optionee
pursuant to this Agreement. Except as the Corporation may determine, no
adjustment shall be made for dividends or other rights for which the record
date is prior to the issuance of such certificate or certificates.

8. Employment. Neither the granting of the Option evidenced by
this Agreement nor any term or provision of this Agreement shall constitute or
be evidence of any understanding, express or implied, on the part of the
Corporation to employ the Optionee for any period.

9. Governing Law. This Agreement shall be governed, construed and
administered in accordance with the laws of the State of Delaware.
<PAGE> 11
6

IN WITNESS WHEREOF, the Corporation has caused this Agreement
to be signed on its behalf effective as of the Date of Grant.

ATTEST:

K.R.M. PETROLEUM CORPORATION

[ILLEGIBLE] By: /s/ BEVERLY A. CUMMINGS
- ------------------------------------- --------------------------------
Accepted and agreed to as of the Date of Grant.

[ILLEGIBLE]
-----------------------------------
Optionee
<PAGE> 12
EXHIBIT A

EXERCISE OF OPTION

Secretary
K.R.M. Petroleum Corporation

The undersigned optionee under the Nonstatutory Stock Option Agreement
identified as Option No._____ (the "Agreement"), hereby irrevocably elects to
exercise the Option granted in the Agreement to purchase _____ shares of common
voting stock of K.R.M. Petroleum Corporation, $0.10 par value, and herewith
makes payment of $ ________ in cash in payment of the option price in respect
of such exercise.

---------------------------------
(Signature of Optionee)

Date Received by K.R.M. Petroleum Corporation:
---------------------------------

Received by:
---------------------------------

<PAGE> 1
EXHIBIT 21

Subsidiaries:

PrimeEnergy Management Corporation, a New York corporation 100% owned by
PrimeEnergy Corporation

Prime Operating Company, a Texas corporation 100% owned by PrimeEnergy
Corporation

Eastern Oil Well Service Company, a West Virginia corporation 100% owned by
PrimeEnergy Corporation

Southwest Oilfield Construction Company, an Oklahoma corporation, 100%
owned by PrimeEnergy Corporation

<PAGE> 1
EXHIBIT 24

[RYDER SCOTT COMPANY/PETROLEUM ENGINEERS LETTERHEAD]

CONSENT OF RYDER SCOTT COMPANY

We consent to the use on the form 10-KSB of PrimeEnergy Corporation of our
reserve report and all schedules, exhibits, and attachments thereto incorporated
by reference of Form 10-KSB and to any reference made to us on Form 10-KSB as a
result of such incorporation.

Very Truly Yours,

/s/ RYDER SCOTT COMPANY
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS

Denver, Colorado
March 10, 1998

<ARTICLE> 5
<MULTIPLIER> 1,000

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<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
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0
0
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<F1>CURRENT PORTION LT DEBT 0
<F2>RETAINED EARNINGS 971
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</TABLE>