<PAGE> 1
SECURITIES AND EXCHANGE COMMMISSION
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, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ______TO ______
COMMISSION FILE NUMBER 0-7406
PRIMEENERGY CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 84-0637348
(state or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
ONE LANDMARK SQUARE 06901
STAMFORD, CONNECTICUT (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code: (203) 358-5700
Securities registered pursuant to Section 12(b) of the Act:
NONE
Securities registered pursuant to Section 12(g) of the Act:
COMMON STOCK, PAR VALUE $.10 PER SHARE
(Title of Class)
Indicate whether Registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding months (or for such shorter period that the Registrant was required to
file such reports), and (2) has been subject to such filing requirements for the
past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-B is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-KSB or any amendment to
this Form 10-KSB. [ ]
The Registrant's revenues for its most recent fiscal year were $24,795,000.
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 23, 1999, was $5,499,245.
The number of shares outstanding of each class of the Registrant's Common
Stock as of March 23, 1999 was: Common Stock, $0.10 par value, 4,439,124.
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, 1999, are incorporated by reference in Part III hereof.
Transitional Small business Disclosure Format (check one) Yes No X
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<PAGE> 2
PRIMEENERGY CORPORATION
FORM 10-KSB ANNUAL REPORT
FOR THE FISCAL YEAR ENDED
DECEMBER 31, 1998
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 interest of PEMC in the oil and gas properties acquired by the Partnerships
and Trusts. As the managing general partner in each of the Partnerships and
managing trustee of the Trusts, PEMC receives approximately from 5% to 12% of
the net revenues of each Partnership and Trust as a carried interest in the
Partnership's and Trust's properties.
Since 1975, PEMC has sponsored a total of 59 limited partnerships, 22 of
which were offered publicly and 37 of which were offered in private placements
and two Delaware business trusts, both of which were offered publicly. The
aggregate number of limited partners in the Partnerships and beneficial owners
of the Trusts now administered by PEMC is approximately 8,500. 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 interest in the net revenues of each joint venture as a
<PAGE> 3
carried interest in the joint venture properties. 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. Since 1987,
our joint venture partners have invested $26 million with the Company.
WELL OPERATIONS
The Company's operations are conducted through a central office in
Houston, Texas, and district offices in Houston and Midland, Texas, Oklahoma
City, Oklahoma, and Charleston, West Virginia. The Company currently operates
about 1,564 oil and gas wells, 436 through the Houston office, 141 through the
Midland office, 484 through the Oklahoma City office and 503 through the
Charleston, West Virginia office. Substantially all of the wells operated by the
Company are wells in which the Company, the Partnerships, the Trusts or our
joint venture partners have an interest.
The Company operates wells pursuant to operating agreements which govern
the relationship between the Company as operator and the other owners of working
interests in the properties, including the Partnerships, Trusts, and joint
venture participants. For each operated well, the Company receives monthly fees
that are competitive in the areas of operations and also is reimbursed for
expenses incurred in connection with well operations.
EXPLORATION, DEVELOPMENT AND ACQUISITION ACTIVITIES; OTHER MATTERS
The Company's focus is on the acquisition and development of producing
oil and gas properties. The Company will continue to engage in exploratory
operations and will continue to engage in development drilling of properties in
which it has an interest. The Company attempts to assume the position of
operator in all acquisitions of producing properties.
RECENT ACTIVITIES
Effective October 1, 1998, the Company sold 50% of its interest in the
Ramrod field in Matagorda County, Texas for $2,075,000. As part of this sale,
the purchaser agreed to carry the Company in the drilling, and the first
$400,000 spent completing, the St. Andrew No. 1 on this prospect. This well was
spudded in December of 1998, drilled to a depth of 16,000 feet and completed in
a Tex. miss. sand. This well is currently being tested and evaluated. The
Company has a 19.5 % working interest in this well.
In August of 1998, the Company operated and participated in the drilling
of the Francis L. Martin, et al No. 1 well on the West Ridge Prospect in
Lafayette Parish, Louisiana. The well reached total depth at 13,200 feet on
October 1, 1998 and has been completed in a sand at 12,850 feet in depth. The
well went on production January 27, 1999 and is producing at a rate of 14,000
Mcf of gas per day and 200 barrels of condensate per day. The Company owns a
19.20 % working interest and 13.44 % net revenue interest in this property.
In October of 1998, the Company re-entered and sidetracked the Stutes, et
al No. 1 well bore located in the Duson area of Lafayette Parish, Louisiana. The
sidetrack hole reached its total measured depth at 12,717 feet January 29, 1999,
and has been completed in the Upper Stutes sand at 11,800 feet measured depth.
The well is producing at a rate of 180 barrels of oil and 560 Mcf of gas per
day. The Company owns a 46.77 % working interest and a 25.60 % net revenue
interest in this property.
In November of 1998, the Company operated and participated in the
drilling of the Lillie S. Breaux, et al No. 1 well on the Lucky Seven Prospect
in Lafayette Parish, Louisiana. The well was drilled to 13,400' and plugged and
abandoned. The Company owned 34.14 % of this well.
In January 1999, the State Tract 15160 No. 1 well was drilled to a depth
of 12,000 feet. This well was plugged and abandoned. The Company had a 34.5 %
working interest in this well.
In January 1999, the Company participated in the drilling of the Chandler
No. 1 well on the Normanna Prospect in Bee County, Texas. The well was drilled
to a total depth of 9,100 feet and encountered several potentially productive
gas sands in the Wilcox Formation. This well is presently being tested.
On the Ramrod Prospect, the Company is participating in the drilling of
the St. George No. 2. This well was spudded in February of 1999 and is currently
drilling. The Company has a 19.5 % working interest in this well.
The Company is currently participating in the drilling of the Hernandez
No. 1 well on the West Judice Prospect in Lafayette Parish, Louisiana. The well,
which began drilling in February 1999, will be drilled to a total measured depth
of approximately 14,500 feet to test for potential gas reservoirs in various
Oligocene age sands.
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.
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<PAGE> 4
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 interest
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 interest are located in the continental United States.
In the past, the supply of gas has exceeded demand on a cyclical basis,
and the Company is subject to a combination of shut-in and/or reduced takes of
gas production during summer months. Prolonged shut-ins could result in reduced
field operating income from properties in which the Company acts as operator.
Exploration for oil and gas requires substantial expenditures
particularly in exploratory drilling in undeveloped areas, or "wildcat
drilling." As is customary in the oil and gas industry, substantially all of the
Company's exploration and development activities are conducted through joint
drilling and operating agreements with others engaged in the oil and gas
business.
Summaries of the Company's oil and gas drilling activities, oil and gas
production, and undeveloped leasehold, mineral and royalty interests are set
forth under Item 2., "Description of Property," below. Summaries of the
Company's oil and gas reserves, future net revenue and present value of future
net revenue are also set forth under Item 2., "Description of Property -
Reserves" below.
REGULATION
The Company's oil and gas operations are subject to a wide variety of
federal, state and local regulations. Administrative agencies in such
jurisdictions may promulgate and enforce rules and regulations relating to,
among other things, drilling and spacing of oil and gas wells, production rates,
prevention of waste, conservation of natural gas and oil, pollution control, and
various other matters, all of which may affect the Company's future operations
and production of oil and gas. The Company's natural gas production and prices
received for natural gas are regulated by the Federal Energy Regulatory
Commission ("FERC"), the Natural Gas Act of 1938 ("NGA") and the Natural Gas
Policy Act of 1978 ("NGPA") and various state regulations. The Company is also
subject to state drilling and proration regulations affecting its drilling
operations and production rates.
Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. The Company cannot predict when or if any such
proposals might become effective, or their effect, if any, on the Company's
operations. The natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less stringent regulatory
approach recently pursued by the FERC and Congress will continue indefinitely
into the future.
In the event the Company conducts operations on federal, state or Indian
oil and gas leases, such operations must comply with numerous regulatory
restrictions, including various nondiscrimination statutes, and certain of such
operations must be conducted pursuant to certain on-site security regulations
and other appropriate permits issued by the Bureau of Land Management ("BLM") or
Minerals Management Service ("MMS") or other appropriate federal or state
agencies.
The Mineral Leasing Act of 1930 ("Mineral Act") prohibits direct or
indirect ownership of any interest in federal onshore oil and gas leases by a
foreign citizen of a country that denies "similar or like privileges' to
citizens of the United States. Such restrictions on citizens of a
"non-reciprocal" country include ownership or holding or controlling stock in a
corporation that holds a federal onshore oil and gas lease. If this restriction
is violated, the corporation's lease can be canceled in a proceeding instituted
by the United States Attorney General. Although the regulations of the BLM
(which administers the Mineral Act) provide for agency designations of
non-reciprocal countries, there are presently no such designations in effect.
The Company owns interest 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. On certain marginal properties the net income
limitation does not apply, and the gross income limitation varies annually based
on average prices. The amount of the percentage depletion deduction so computed
which may be deducted in any given year is limited to 65% of taxable income. Any
percentage depletion deduction disallowed due to the 65% of taxable income test
may be carried forward indefinitely.
The Company is entitled to credits for producing fuel from a
non-conventional source under Section 29 of the Internal Revenue Code, primarily
from certain of the Company's operations in West Virginia.
See Notes 1 and 9 to the consolidated financial statements included in
this Report for a discussion of accounting for income taxes and availability of
federal tax net operating loss carryforwards and alternative minimum tax credit
carryforwards.
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<PAGE> 5
COMPETITION AND MARKETS
The business of acquiring producing properties and non-producing leases
suitable for exploration and development is highly competitive. Competitors of
the Company in its efforts to acquire both producing and non-producing
properties include oil and gas companies, independent concerns, income programs
and individual producers and operators, many of which have financial resources,
staffs and facilities substantially greater than those available to the Company.
Furthermore, domestic producers of oil and gas must not only compete with each
other in marketing their output, but must also compete with producers of
imported oil and gas and alternative energy sources such as coal, nuclear power
and hydroelectric power. Competition among petroleum companies for favorable oil
and gas properties and leases can be expected to increase.
The availability of a ready market for any oil and gas produced by the
Company at acceptable prices per unit of production will depend upon numerous
factors beyond the control of the Company, including the extent of domestic
production and importation of oil and gas, the proximity of the Company's
producing properties to gas pipelines and the availability and capacity of such
pipelines, the marketing of other competitive fuels, fluctuation in demand,
governmental regulation of production, refining, transportation and sales,
general national and worldwide economic conditions, and use and allocation of
oil and gas and their substitute fuels. There is no assurance that the Company
will be able to market all of the oil or gas produced by it or that favorable
prices can be obtained for the oil and gas production.
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 1998
generated from sales to Dow Hydrocarbons and Resources, Inc., a subsidiary of
Dow Chemical, U.S.A., and El Paso Energy Marketing represented about 18% and
11%, respectively, of the Company's total revenue from oil and gas sales.
Although there are no long-term gas purchasing agreements with these purchasers,
the Company believes that they will continue to purchase its gas products and,
if not, could be replaced by other purchasers.
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 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 measure. 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 not 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 stricter.
Under these new laws, the Company could be required to remove or remediate
previously disposed wastes (including wastes disposed of or released by prior
owners or operators) or property contamination (including groundwater
contamination) or to perform remedial plugging operations to prevent future
contamination.
The Company may generate wastes, including hazardous wastes, that are
subject to the Federal Resource Conservation and Recovery Act and comparable
state statutes. The EPA has limited the disposal options for certain hazardous
wastes and is considering the adoption of stricter disposal standards for
non-hazardous wastes. Furthermore, certain wastes generated by the Company's oil
and gas operations that are currently exempt from treatment as "hazardous
wastes" may in the future by designated as "hazardous wastes," and therefore be
subject to more rigorous and costly operating and disposal requirements.
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<PAGE> 6
In addition, legislation has been proposed in Congress from time to time
that would reclassify certain oil and gas exploration and production wastes as
"hazardous wastes," which would make the reclassified wastes subject to much
more stringent handling, disposal and clean-up requirements. If such legislation
were to be enacted, it could have a significant impact on the operating costs of
the Company, as well as the oil and gas industry in general. Initiatives to
further regulate the disposal of oil and gas wastes are also pending in certain
states, and these various initiatives could have a similar impact on the
Company.
The Federal Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "Superfund" law, imposes joint and
several liability, without regard to fault or the legality of the original
conduct, on certain classes of persons with respect to the release of a
"hazardous substance" into the environment. These persons include the current
owner and operator of a site and persons that disposed of or arranged for the
disposal of the hazardous substances found at a site. CERCLA also authorizes the
EPA and, in some cases, third parties to take actions in response to threats to
the public health or the environment and to seek to recover from the responsible
classes of persons the costs of such action. In the course of its operations,
the Company may have generated and may generate wastes that fall within CERCLA'S
definition of "hazardous substances." The Company may also be an owner of sites
on which "hazardous substances" have been released by previous owners or
operators. The Company may be responsible under CERCLA for all or part of the
costs to clean up sites at which such wastes have been released. Neither the
Company nor, to its knowledge, its predecessors has been named a potentially
responsible person under CERCLA nor does the Company know of any prior owners or
operators of its properties that are named as potentially responsible parties
related to their ownership or operation of such property.
The Company has a proactive environmental policy that management feels
benefits the Company through increased operating profits, improved landowner
relations and an overall enhanced Company image. To this end, the Company has
also adopted a stringent environmental evaluation prior to purchasing a
property. This pre-acquisition assessment, usually referred to as an
Environmental Site Assessment, typically consists of a historical review of the
property combined with a site inspection and limited testing, when necessary.
The objective of this pre-acquisition assessment is to document conditions at
the time of acquisition and to assign liability to the seller for past
operations.
EMPLOYEES
At March 26, 1999, the Company had 166 full-time and 10 part-time
employees, 25 of whom were employed by the Company at its principal offices in
Stamford, Connecticut, 29 in Houston, Texas, at the offices of Prime Operating
Company and Eastern Oil Well Service Company, and 122 employees who were
primarily involved in the district operations of the Company in Houston and
Midland, Texas, Oklahoma City, Oklahoma and Charleston, West Virginia.
ITEM 2. DESCRIPTION OF PROPERTY.
The Company's executive offices and those of PEMC, are located at One
Landmark Square, Stamford, Connecticut, in leased premises of about 8,860
square feet. The executive offices of Prime Operating Company and Eastern Oil
Well Service Company are located in leased premises in Houston, Texas, and the
offices of Southwest Oilfield Construction Company are in Oklahoma City,
Oklahoma.
The Company maintains district offices in Houston and Midland, Texas,
Oklahoma City, Oklahoma and Charleston, West Virginia, and has field offices in
Carrizo Springs and Midland, Texas, Kingfisher, Yukon, and Marshall, Oklahoma,
and Arnoldsburg and Orma, West Virginia.
Substantially all of the Company's oil and gas properties are subject to
a mortgage given to collateralize indebtedness of the Company, or are subject to
being mortgaged upon request by the Company's lender for additional collateral.
The information set forth below concerning the Company's properties,
activities, and oil and gas reserves include the Company's interests in the
Partnerships, Trusts and joint ventures.
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The following table sets for the exploratory and development drilling
experience with respect to wells in which the Company participated during the
five years ended December 31,1998.
<TABLE>
<CAPTION>
1998 1997 1996 1995 1994
------------- ------------- ------------- ------------- -------------
Gross Net Gross Net Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Exploratory:
Oil 1 0.468 -- -- -- -- -- -- -- --
Gas 2 0.387 2 .8 -- -- -- -- -- --
Dry 2 0.686 2 .509 1 1 -- -- -- --
Development:
Oil 1 0.145 5 .796 3 .740 8 1.046 4 .346
Gas 5 0.316 5 2.037 17 1.292 3 .235 2 .121
Dry -- -- 3 1.030 1 2 .350 4 .215
.371
Total:
Oil 2 0.613 5 3 8 1.046 4 .346
.796 .740
Gas 7 0.703 7 2.837 17 1.292 3 .235 2 .121
Dry 2 0.686 5 1.539 2 1.371 2 .350 4 .215
===== ===== ===== ===== ===== ===== ===== ===== ===== =====
11 2.002 17 5.172 22 3.403 13 1.631 10 .682
===== ===== ===== ===== ===== ===== ===== ===== ===== =====
</TABLE>
OIL AND GAS PRODUCTION
As of December 31, 1998, 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>
Producing wells (1): Gross Net
----- ---
<S> <C> <C>
Oil Wells . . . . . . . . . . . . . . . . . . . 744 122.15
Gas Wells . . . . . . . . . . . . . . . . . . 1,314 282.96
Producing Acres. . . . . . . . . . . . . . . . . 291,216 50,429
</TABLE>
(1) A gross well or gross acre is a well or an acre in which a working
interest is owned. A net well or net is the sum of the fractional revenue
interests owned in gross wells or gross acres. Wells are classified by
their primary product. Some wells produce both oil and gas.
The following table shows the Company's net production of crude oil and
natural gas for each of the five years ended December 31, 1998. "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>
1998 1997 1996 1995 1994
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Oil (barrels)..................... 277,000 277,000 249,000 155,000 143,000
Gas (Mcf)......................... 3,621,000 3,901,000 2,888,000 1,952,000 1,408,000
</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, 1998.
<TABLE>
<CAPTION>
1998 1997 1996 1995 1994
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Average sales price
per barrel ........................ $ 12.39 19.35 21.11 16.53 15.22
Average sales price
Per Mcf ........................... $ 2.19 2.57 2.36 1.85 2.36
Average production
costs per net equivalent
barrel (1) ........................ $ 7.60 7.59 8.09 8.92 10.14
</TABLE>
- ---------------
(1) Net equivalent barrels are computed at a rate of 6 Mcf per barrel.
UNDEVELOPED ACREAGE
The following table sets forth the approximate gross and net
undeveloped acreage in which the Company has leasehold, mineral and royalty
interests as of December 31, 1998. "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.
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<PAGE> 8
<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 3,385 266 799 23 -- --
Louisiana 1,985 404 -- -- -- --
Montana -- -- 13,984 59 786 5
Nebraska -- -- 2,553 331 -- --
North Dakota -- -- 640 1 -- --
Oklahoma -- -- 320 1 -- --
Texas 3,999 1,585 680 16 -- --
Wyoming 1,000 125 5043 35 140 40
========= ========= ========= ========= ========= =========
TOTAL 10,369 2,380 24,019 466 926 45
========= ========= ========= ========= ========= =========
</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, 1994, 1995, 1996, 1997 and 1998. 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>
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
1998 1,122,000 17,341,000 78,000 -- 1,200,000 17,341,000
</TABLE>
The estimated future net revenue (using current prices and costs as of
those dates, exclusive of income taxes) and the present value of future net
revenue (at a 10% discount for estimated timing of cash flow) for the Company's
proved developed and proved undeveloped oil and gas reserves at the end of each
of the five years ended December 31, 1998, are summarized as follows (figures
rounded):
<TABLE>
<CAPTION>
Proved Developed Proved Undeveloped Total
---------------- ------------------ -----
Present Value Present Value Present Value
As of Future Net Of Future Future Net Of Future Future Net Of Future
12-31 Revenue Net Revenue Revenue Net Revenue Revenue Net Revenue
---- ----------- ---------- ------- ------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
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
1998 $20,839,000 13,444,000 359,000 212,000 21,198,000 13,656,000
</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, 1998, 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.
- 7 -
<PAGE> 9
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, 1998, to a vote of the Company's security-holders through the
solicitation of proxies or otherwise.
PART II
ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
The Company's Common Stock is traded in the NASDAQ Stock Market,
trading symbol "PNRG". The high and low bid quotations for each quarterly period
during the two years ended December 31, 1998, were as follows:
<TABLE>
<CAPTION>
1997 High Low 1998 High Low
---- ---- --- ---- ---- ---
<S> <C> <C> <C> <C>
First Quarter ................ $ 4.80 $ 4.59 First Quarter ............ $ 8.06 $ 7.79
Second Quarter ............... 6.54 6.33 Second Quarter ........... 7.46 7.08
Third Quarter ................ 9.15 8.78 Third Quarter ............ 7.00 6.72
Fourth Quarter ............... 9.23 8.88 Fourth Quarter ........... 6.66 6.60
</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 1,180.
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
During 1997 and 1998, the Company was party to a line of credit
agreement with a bank with a non-reducing borrowing base of $20 million.
Twenty-five percent of the borrowing is syndicated to a second bank. During
1997, the agreement provided for interest at the bank's base rate as defined, or
2-1/4% over the London Inter-Bank Offered Rate (LIBO rate) for the interest
period in question, payable at the end of the interest period. 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 LIBO rate depending upon the Company's utilization of the available
line of credit.
The average interest rates paid on outstanding borrowings subject to
interest at the bank's base rate during 1998 and 1997 were 8.46% and 8.58%,
respectively. During the same periods, the average rates paid on outstanding
borrowings bearing interest based upon the LIBO rate were 7.69% and 8.04%. As of
December 31, 1998 and 1997, the total outstanding borrowings were $16.5 million
and $18.9 million, respectively, of which $14.3 million and $13.7 million
accrued interest at the LIBO rate option.
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. In February 1999, the credit agreement was
revised to require that the $20 million borrowing base, reestablished on October
14, 1998, would begin reducing each month by $300,000 beginning February 1,
1999.
Effective October 1, 1998, the Company sold 50% of its interest in the
Ramrod field for $2,075,000. The Company recorded a gain of $150,000 on this
sale. As part of this sale, the purchaser agreed to carry the Company in the
drilling, and the first $400,000 spent completing, the St. Andrew No. 1 on this
prospect. It is expected that the Company's share of completion costs in excess
of this amount will be approximately $200,000.
The Company spent $1,014,000 on its Ramrod prospect in 1998, primarily
to finish drilling and completing the Saint George # 1 well, which began
drilling in the fourth quarter of 1997. The Company is participating in a Saint
George # 2 well which is currently being drilled to the Frio formation. The
Company's total share of drilling and equipping this well is estimated to be
$785,000.
- 8 -
<PAGE> 10
During 1998, the Company organized a drilling program in which the
Company, along with several joint venture partners, will participate in the
drilling of six wells. As of December 31, 1998, the Company had incurred costs
of $3,297,000 in connection with this program, including $1,355,000 in dry hole
costs. It is expected that the Company will incur approximately $1,777,000 in
additional costs in the first half of 1999 in connection with this program,
including at least $325,000 in dry hole costs. As of the date of this report,
two wells were successfully completed, one well was waiting on completion, two
wells were dry holes, and one well was in the process of being drilled. Of the
two wells which have been successfully completed, the first, the Francis Martin
# 1, is currently producing at a rate of 14,000 Mcf of gas per day and 200
barrels of condensate per day. The Company owns a 19.20 % working interest and
13.44 % net revenue interest in this property. The second, the Stutes, is
producing at a rate of 180 barrels of oil and 560 Mcf of gas per day. The
Company owns a 46.77% working interest and a 25.60% net revenue interest in this
property.
In total, the Company spent $7,462,000 on the acquisition and
development of oil and gas interests in 1998, including $831,000 spent to
repurchase limited partnership interests from investors in its oil and gas
partnerships.
In 1998, the Company spent $905,000 on trucks, automobiles and
equipment used in field service operations, and an additional $150,000 on
computer related equipment and software.
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. The
Company spent an additional $467,000 on the repurchase of treasury stock through
open market transactions in 1998; $60,535 was spent to repurchase treasury stock
between January 1, 1999, and the date of this report.
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.
RESULTS OF OPERATIONS:
1998 AS COMPARED TO 1997
The Company incurred a loss of $1,692,000 in 1998 as compared to income
of $1,024,000 in 1997. The primary reason for this change was sharply lower
prices received for oil and gas production.
Oil and gas sales of $11,354,000 in 1998 represent a decrease of 26%,
or $4,049,000 over the 1997 sales. The average price received per barrel of oil
for all production was $12.39 as compared to $19.35 in 1997 and the average gas
price was $2.19 in 1998 as compared to $2.58 in 1997. Based on total production
of 3,621,000 MCF of gas, and 277,000 barrels of oil, the Company would have
received an additional $3,334,000 in gross oil and gas revenue if it had
received the same average prices for oil and gas production in 1998 as it did in
1997.
Oil production in 1998 was roughly equivalent to 1997 production, as
the natural decline curve on existing properties was roughly offset by increased
production related to partnership interests of about 12,000 barrels, due to
additional interests in the partnerships being purchased during the year.
Gas production declined from 3,895,000 Mcf in 1997 to 3,621,000 Mcf in
1998. 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. Due to this provision, and a high natural decline curve on the
property, the Company's share of production from this property declined from
1,326,000 Mcf in 1997 to 570,000 Mcf in 1998. This was in large part offset by
an increase in production from the Ramrod property due to the Saint George # 1
well coming online in March of 1998. The Ramrod property in total contributed
680,000 Mcf of production in 1998 as compared to 54,000 Mcf in 1997.
Lease operating expenses decreased by 5% in 1998 as compared to 1997.
Per unit costs were approximately $7.60 per barrel of oil equivalent in both
years.
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 2% in 1998 as compared to 1997. In
both years, amounts received from certain 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
- 9 -
<PAGE> 11
general and administrative expenses. During 1998 and 1997 the Company's total
reimbursements for property acquisition costs were approximately $1,690,000 and
$1,751,000 respectively.
Exploration costs of $1,706,000 were incurred in 1998. The primary
components of this amount were $845,000 spent on the drilling of a dry hole in
Lafayette Parish, Louisiana, and $510,000 incurred up to December 31, 1998 in
connection with a dry hole in Terrebonne Parish Louisiana. This well completed
drilling in 1999, and approximately $325,000 in costs incurred during 1999 will
be written of as an expense in the first quarter of the year. The Company is
currently participating in the drilling of a well to the Frio formation on its
Ramrod prospect, and a well in Lafayette Parish, Louisiana, which is part of its
1998 drilling program. The estimated dry hole cost of these wells of $300,000
and $496,000 respectively, will be expensed in 1999 if the wells are not
productive.
A tax benefit of $183,000 was recognized in 1998. This includes $72,000
of federal income tax refunds expected to be received due to the filing of net
operating loss carry back claims, with the balance being primarily attributable
to the reversal of deferred tax liabilities previously recognized. Future losses
would not create a similar tax benefit as no further carryback claims could be
filed, the greater part of the Company's deferred tax liability has already been
eliminated, and tax assets created would be fully reserved against.
The Year 2000 (Y2K) issue is the definition and resolution of potential
problems resulting from computer application programs or imbedded chip
instruction sets utilizing two-digits, as opposed to four digits, to define a
specific year. Such date sensitive systems may be unable to properly interpret
dates, which could cause a system failure or other computer errors, leading to
disruptions in operations. In 1997, the Company developed a three-phase program
for the Y2K information systems compliance. Phase I is to identify those systems
with which the Company has exposure to Y2K issues. Phase II is to remediate
systems and replace equipment where required. Phase III, to be completed by
mid-1999, is the final testing of each major area of exposure to ensure
compliance. The Company has identified four major areas determined to be
critical for successful Y2K compliance: (1) financial and informational system
applications, (2) communications applications, (3) oil and gas producing
operations, and (4) third-party relationships.
The Company, in accordance with Phase I of the program, is in the
process of conducting an internal review of all systems and contacting all
software suppliers to determine major areas of exposure to Y2K issues. The
Company has completed the modifications to its core financial and reporting
systems and is continuing to test compliance in this area. These modifications
were made in conjunction with an upgrade of the financial reporting applications
provided by the Company's software vendor. Conversion to the new system was
completed during 1998. Due to the technology advances in the communications area
the Company has upgraded such equipment regularly over the past three years. Y2K
compliance was a specification requirement of each installation. Consequently,
the Company expects exposure in this area to be limited to third party
readiness. The Company is in the process of identifying areas of exposure
resulting from equipment used in its oil and gas producing operations. The
Company expects to complete identification of critical systems by June 1999 and
to continue remediation and testing throughout 1999. In the third-party area,
the Company has received assurance from its significant service suppliers that
they intend to be Y2K complaint by 2000. The Company has implemented a program
to request Year 2000 certification or other assurance from other third parties
during 1999.
The Company recognizes that, notwithstanding the efforts described
above, the Company could experience disruptions to its operations or
administrative functions, including those resulting from non-compliant systems
utilized by unrelated third party governmental and business entities. The
Company is in the process of developing a contingency plan in order to mitigate
potential disruption to business operations. The Company expects to complete
this contingency plan by the second quarter of 1999, but also expects to refine
this plan throughout 1999.
Through 1998, the Company has handled identifying, remediating and
testing systems for Year 2000 compliance within the scope of routine upgrades
and systems evaluations. The Company expects to complete the review of oil and
gas operations exposure in the same manner, without incurring substantial
additional costs. However, information resulting from the oil and gas operations
review may indicate required expenditures not currently contemplated by the
Company.
1997 AS 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
$483,000 in 1996.
Oil and gas sales of $15,403,000 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.
- 10 -
<PAGE> 12
Oil and gas sales related to the Company's interests in the
Partnerships increased $4,247,000 or 38% in 1997 as 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.
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 certain 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
in 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.
ITEM 7. FINANCIAL STATEMENTS.
Included on pages F-1 through F-25 of this Report. The Index to
Financial Statements is at page F-1 of this Report.
- 11 -
<PAGE> 13
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS;
COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT.
Information relating to the Company's Directors, nominees for Directors
and executive officers is included in the Company's definitive proxy statement
relating to the Company's Annual Meeting of Stockholders to be held in June,
1999, which will be filed with the Securities and Exchange Commission within 120
days of December 31, 1998, 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, 1999, which will be filed with the Securities
and Exchange Commission within 120 days of December 31, 1998, and which is
incorporated herein by reference.
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Information relating to security ownership of certain beneficial owners
and management is included in the Company's definitive proxy statement relating
to the Company's Annual Meeting of Stockholders to be held in June, 1999, which
will be filed with the Securities and Exchange Commission within 120 days of
December 31, 1998, 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,
1999, which will be filed with the Securities and Exchange Commission within 120
days of December 31, 1998, and which is incorporated herein by reference.
PART IV
ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits:
<TABLE>
<CAPTION>
No.
<S> <C>
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 3.2 of
PrimeEnergy Corporation Form 10-KSB for the year ended December 31, 1994)
10.3 Massachusetts Mutual Flexinvest 401(k) Plan as amended and restated. (Incorporated herein by reference to Exhibit
10.3 of PrimeEnergy Corporation Form 10-KSB for the year ended December 31, 1994) (1)
10.7 Credit Agreement dated April 26, 1995, between PrimeEnergy Corporation, PrimeEnergy Management Corporation and
Bank One, Texas, National Association. (Incorporated herein by reference to Exhibit 10.7 to PrimeEnergy
Corporation Form 8-K dated April 26, 1995)
10.7.1 First Amendment to Credit Agreement Among PrimeEnergy Corporation and PrimeEnergy Management Corporation, as
Borrowers, Bank One, Texas, National Association, as Agent, and the Lenders Signatory Hereto, effective as of
October 6, 1995. (Incorporated herein by reference to Exhibit 10.7.1 to PrimeEnergy Corporation Form 10-KSB for
the year ended December 31, 1995)
</TABLE>
- 12 -
<PAGE> 14
<TABLE>
<S> <C>
10.7.2 Second Amendment to Credit Agreement Among PrimeEnergy Corporation and PrimeEnergy Management Corporation, as
Borrowers, Bank One, Texas, National Association, as Agent, and the Lenders Signatory Hereto, effective as of
February 6, 1997. (Incorporated by reference to Exhibit 10.7.2 of PrimeEnergy Corporation Form 10-KSB for the year
ended December 31, 1996)
10.7.3 Third Amendment to Credit Agreement Among PrimeEnergy Corporation and PrimeEnergy Management Corporation, as
Borrowers, Bank One, Texas, National Association, as Agent, and the Lenders Signatory Hereto, effective as of
January 2, 1998 (Incorporated by reference to Exhibit 10.7.3 of PrimeEnergy Corporation Form 10-KSB for the year
ended December 31, 1997)
10.8 Mortgage, Deed or Trust, Indenture, Security Agreement, Financing Statement and Assignment of Production dated May
27, 1994, as ratified and amended April 26, 1995, between PrimeEnergy Corporation, PrimeEnergy Management
Corporation and Bank One, Texas, National Association. (Incorporated by reference to Exhibit 10.8 of PrimeEnergy
Corporation Form 8-K dated April 26, 1995)
10.17 Amended Marketing Agreement between PrimeEnergy Management Corporation and Charles E. Drimal, Jr. (Incorporated
herein by reference to Exhibit 10.17 of PrimeEnergy Corporation Form 10-KSB for the year ended December 31, 1994)
(1)
10.18 Composite copy of Non-Statutory Option Agreements. (Incorporated by reference to Exhibit 10.18 of PrimeEnergy
Corporation Form 10-KSB for the year ended December 31, 1997) (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)
22 Consent of Ryder Scott Company. (filed herewith)
27 Financial Data Schedule. (filed herewith)
</TABLE>
- -----------
(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.
- 13 -
<PAGE> 15
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, 1999.
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, 1999.
<TABLE>
<S> <C> <C> <C>
/s/CHARLES E. DRIMAL, JR. Director and President; /s/ JARVIS K. SLADE Director
- ----------------------------- The Principal Executive Officer -----------------------------
Charles E. Drimal, Jr. Jarvis J. Slade
/s/ BEVERLY A. CUMMINGS Director, Vice President and Treasurer; /s/ JAN K. SMEETS Director
- ----------------------------- The Principal Financial and Accounting Officer -----------------------------
Beverly A. Cummings Jan K. Smeets
/s/ GAINES WEHRLE Director
Director, and Vice President -----------------------------
- ----------------------------- Gaines Wehrle
Bennie H. Wallace, Jr.
/s/ MICHAEL WEHRLE Director
/s/ SAMUEL R. CAMPBELL Director -----------------------------
- ----------------------------- Michael Wehrle
Samuel R. Campbell
/s/ JAMES E. CLARK Director
- -----------------------------
James E. Clark
/s/ MATTHIAS ECKENSTEIN Director
- -----------------------------
Matthias Eckenstein
Director
- -----------------------------
H. Gifford Fong
/s/ THOMAS S.T. GIMBEL Director
- -----------------------------
Thomas S.T. Gimbel
/s/ CLINT HURT Director
- -----------------------------
Clint Hurt
Director
- -----------------------------
Robert de Rothschild
</TABLE>
- 14 -
<PAGE> 16
INDEX TO FINANCIAL STATEMENTS
Financial Statements (Included herein at pages F-1 through F-25):
Report of Independent Public Accountants, F-2
Financial Statements:
Consolidated Balance Sheets -- December 31, 1998 and 1997, F-3
Consolidated Statements of Operations -- for the years ended December
31, 1998 and 1997, F-5
Consolidated Statements of Stockholders' Equity -- for the years ended
December 31, 1998 and 1997, F-6
Consolidated Statements of Cash Flows -- for the years ended December
31, 1998 and 1997, F-7
Notes to Consolidated Financial Statements, F-8
Supplementary Information: F-19
Capitalized Costs Relating to Oil and Gas Producing
Operations, December 31, 1998 and 1997, F-20
Costs Incurred in Oil and Gas Property Acquisition,
Exploration and Development Activities, years ended December
31, 1998 and 1997, F-20
Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas reserves, years ended December
31, 1998 and 1997, F-21
Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil an Gas Reserves, years
ended December 31, 1998 and 1997, F-22
Reserve Quantity Information, years ended December 31, 1998
and 1997, F-23
Results of Operations from Oil and Gas Producing Activities,
years ended December 31, 1998 and 1997, F-24
Notes to Supplementary Information, F-25
F - 1
<PAGE> 17
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, 1998 and 1997, 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, 1998 and 1997, 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, 1999
F - 2
<PAGE> 18
PrimeEnergy Corporation and Subsidiaries
Consolidated Balance Sheets, December 31, 1998 and 1997
<TABLE>
<CAPTION>
1998 1997
------------ ------------
<S> <C> <C>
ASSETS:
Current assets:
Cash and cash equivalents $ 1,167,000 $ 2,987,000
Restricted cash and cash
equivalents (Note 12) 1,080,000 885,000
Accounts receivable, net (Note 3) 2,890,000 4,480,000
Due from related parties (less allowance for
doubtful accounts of $800,000 in 1998
and 1997) (Note 11) 2,952,000 2,454,000
Prepaid expenses 79,000 107,000
Other current assets 351,000 175,000
Deferred income taxes (Notes 1 and 9) 18,000 121,000
------------ ------------
Total current assets 8,537,000 11,209,000
------------ ------------
Property and equipment, at cost (Notes 1 and 2):
Oil and gas properties (successful
efforts method):
Developed 40,582,000 41,427,000
Undeveloped 1,284,000 231,000
Furniture, fixtures and equipment
including leasehold improvements 6,571,000 5,757,000
------------ ------------
48,437,000 47,415,000
Accumulated depreciation and depletion (29,310,000) (24,885,000)
------------ ------------
Net property and equipment 19,127,000 22,530,000
------------ ------------
Other assets (Note 11) 622,000 604,000
Due from affiliates (Note 11) 325,000 325,000
------------ ------------
Total assets $ 28,611,000 $ 34,668,000
============ ============
</TABLE>
The accompanying notes are an integral part of the
consolidated financial statements.
F - 3
<PAGE> 19
PrimeEnergy Corporation and Subsidiaries
Consolidated Balance Sheets, December 31, 1998 and 1997
<TABLE>
<CAPTION>
1998 1997
------------ ------------
<S> <C> <C>
LIABILITIES and STOCKHOLDERS' EQUITY:
Current liabilities:
Accounts payable (Note 14) $ 6,315,000 $ 6,333,000
Accrued liabilities:
Payroll, Benefits and Related Items 552,000 530,000
Taxes (Notes 1 and 9) -- 27,000
Interest and other 832,000 646,000
Due to related parties (Note 11) 731,000 1,389,000
------------ ------------
Total current liabilities 8,430,000 8,925,000
------------ ------------
Long-term bank debt (Note 4) 16,505,000 18,865,000
Deferred income taxes (Notes 1 and 9) 57,000 262,000
------------ ------------
Total liabilities 24,992,000 28,052,000
------------ ------------
Stockholders' equity:
Preferred stock, $.10 par, authorized
10,000,000 shares; none issued -- --
Common stock, $.10 par value, authorized
15,000,000 shares; issued 7,607,970 in 1998 and
7,597,970 in 1997 761,000 760,000
Paid in capital 10,902,000 10,888,000
Retained earnings (accumulated deficit) (721,000) 971,000
------------ ------------
10,942,000 12,619,000
Treasury stock, at cost, 3,158,376
common shares in 1998 and 2,989,161
common shares in 1997 (7,323,000) (6,003,000)
------------ ------------
Total stockholders' equity 3,619,000 6,616,000
------------ ------------
Total liabilities and equity $ 28,611,000 $ 34,668,000
============ ============
</TABLE>
The accompanying notes are an integral part of the
consolidated financial statements.
F - 4
<PAGE> 20
PrimeEnergy Corporation and SUBSIDIARIES
Consolidated Statements of Operations
for the years ended December 31, 1998 and 1997
<TABLE>
<CAPTION>
1998 1997
------------ ------------
<S> <C> <C>
Revenue:
Oil and gas sales $ 11,354,000 $ 15,403,000
District operating income 10,945,000 11,083,000
Administrative revenue (Note 11) 1,723,000 1,684,000
Reporting and management fees (Note 11) 301,000 322,000
Interest income 139,000 138,000
Other income 333,000 95,000
------------ ------------
24,795,000 28,725,000
------------ ------------
Costs and expenses:
Lease operating expense 6,695,000 7,035,000
District operating expense 8,265,000 8,365,000
Depreciation and depletion of
oil and gas properties 6,038,000 5,895,000
General and administrative expense 2,899,000 3,028,000
Exploration costs 1,706,000 2,411,000
Interest expense (Note 4) 1,337,000 1,149,000
------------ ------------
26,940,000 27,883,000
------------ ------------
Income (loss) from operations (2,145,000) 842,000
Other income:
Gain on sale and exchange of assets 270,000 294,000
------------ ------------
Income (loss) before provision (benefit) for income taxes (1,875,000) 1,136,000
(Benefit) provision for income taxes (183,000) 112,000
------------ ------------
Net income (loss) $ (1,692,000) $ 1,024,000
============ ============
Basic net income (loss) per common share (Notes 1 and 15) $ (0.38) $ 0.22
============ ============
Diluted net income (loss) per common share (Notes 1 and 15) $ (0.38) $ 0.19
============ ============
</TABLE>
The accompanying notes are an integral part of the
consolidated financial statements.
F - 5
<PAGE> 21
PrimeEnergy Corporation and SUBSIDIARIES
Consolidated Statement of Stockholders' Equity
for the years ended December 31, 1998 and 1997
<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, 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 5) (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
Purchased 169,215 shares of
common stock (1,320,000) (1,320,000)
Stock options exercised 10,000 1,000 14,000 15,000
Net income (loss) (1,692,000) (1,692,000)
-----------
Balance at December 31, 1998 7,607,970 $ 761,000 $10,902,000 ($ 721,000) ($7,323,000) -- $ 3,619,000
=========== =========== =========== =========== =========== =========== ===========
</TABLE>
The accompanying notes are an integral part of the
consolidated financial statements.
F - 6
<PAGE> 22
PrimeEnergy Corporation and SUBSIDIARIES
Consolidated Statements of CASH FLOWS
for the years ended December 31, 1998 and 1997
<TABLE>
<CAPTION>
1998 1997
------------ ------------
<S> <C> <C>
Cash flows from operating activities:
Net income (loss) $ (1,692,000) $ 1,024,000
Adjustments to reconcile net income (loss) to net cash provided by operating
activities:
Depreciation, depletion and amortization 6,994,000 6,795,000
Gain on sale of properties (270,000) (294,000)
Provision of deferred income taxes (102,000) 20,000
Changes in assets and liabilities:
Decrease in accounts receivable 1,590,000 572,000
(Increase) in due from related parties (498,000) (270,000)
(Increase) decrease in other assets (204,000) 54,000
Decrease in prepaid expenses 28,000 43,000
Increase (decrease) in accounts payable (213,000) 814,000
Increase (decrease) in accrued liabilities 181,000 (76,000)
Increase (decrease) in due to related parties (658,000) 91,000
------------ ------------
Net cash provided by operating activities 5,156,000 8,773,000
------------ ------------
Cash flows from investing activities:
Proceeds from sale of properties and equipment 2,433,000 1,019,000
Additions to property and equipment (5,754,000) (9,817,000)
Decrease in notes receivable 10,000 40,000
------------ ------------
Net cash used in investing activities (3,311,000) (8,758,000)
------------ ------------
Cash flows from financing activities:
Purchase of stock for treasury (1,320,000) (1,493,000)
Repayment of long-term bank debt and other long-term obligations (33,221,000) (36,252,000)
Increase in long-term bank debt and other long-term obligations 30,861,000 37,401,000
Proceeds from exercised stock options 15,000 --
------------ ------------
Net cash used in financing activities (3,665,000) (344,000)
------------ ------------
Net decrease in cash (1,820,000) (329,000)
Cash and cash equivalents, beginning of year 2,987,000 3,316,000
------------ ------------
Cash and cash equivalents, end of year $ 1,167,000 $ 2,987,000
============ ============
Supplemental disclosures:
Income taxes paid during the year $ 46,000 $ 76,000
Interest paid during the year $ 1,346,000 $ 1,164,000
</TABLE>
There were no non-cash investing or financing activities during 1997 and 1998.
The accompanying notes are an integral part of the
consolidated financial statements.
F - 7
<PAGE> 23
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 1,564 wells and owns non-operating
interests in approximately 753 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.
Certain items on the prior year income statement have been reclassified
to conform with current year classification.
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 - 8
<PAGE> 24
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, primarily at a field level.
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 - 9
<PAGE> 25
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. Cash activity related to hedging transactions is
treated as operating activity on the Statements of Cash Flows.
Recently Issued Accounting Standards:
In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 133 ("SFAS No. 133"), "Accounting
for Derivative Instruments and Hedging Activities". SFAS No. 133
establishes accounting and reporting standards requiring that every
derivative instrument (including certain derivative instruments
embedded in other contracts) be recorded in the balance sheet as either
an asset or liability measured at its fair value. It also requires that
changes in the derivative's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses
to offset related results on the hedged item in the income statement,
and requires that a company must formally document, designate, and
assess the effectiveness of transactions that receive hedge accounting.
SFAS No. 133 is effective for fiscal years beginning after June 15,
1999 and cannot be applied retroactively. The Company has not yet
quantified the impacts of adopting SFAS No. 133 on its financial
statements and has not determined the timing of or method of adoption
of SFAS No. 133. However, SFAS No. 133 could increase volatility in
earnings and other comprehensive income.
In June 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 130 ("SFAS No. 130"), "Reporting
Comprehensive Income". SFAS No. 130 requires the reporting of
comprehensive income (non-owner changes in equity) and its components
in the financial statements. In 1998, the Company did not have any
equity changes from non-owner sources that would be classified as
comprehensive income.
2. SIGNIFICANT ACQUISITIONS AND DISPOSITIONS
1998
Effective October 1, 1998, the Company sold 50% of its interest in the
Ramrod field for $2,075,000. The Company recorded a gain of $150,000 on
this sale. As part of this sale, the purchaser agreed to carry the
Company in the drilling, and the first $400,000 spent completing, the
St. Andrew No. 1 on this prospect. This well was drilled in the first
quarter of 1999 and is currently being evaluated.
During 1998, the Company organized a drilling program in which the
Company, along with several joint venture partners, will participate in
the drilling of six wells. As of December 31, 1998, the Company had
incurred costs of $3,297,000 in connection with this program, including
$1,355,000 in dry hole costs. It is expected that the Company will
incur approximately $1,777,000 in additional costs in the first half of
1999 in connection with this program, including at least $325,000 in
dry hole costs. As of the date of this report, two wells were
successfully completed, one well was waiting on completion, two wells
were dry holes, and one well was in the process of being drilled. Of
the two wells which have been successfully completed, the first, the
Francis Martin # 1, is currently producing at a rate of 14,000 Mcf of
gas per day and 200 barrels of condensate per day. The Company owns a
19.20 % working interest and 13.44 % net revenue interest in this
property. The second, the Stutes, is producing at a rate of 180 barrels
of oil and 560 Mcf of gas per day. The Company owns a 46.77% working
interest and a 25.60% net revenue interest in this property.
As more fully described in Note 7, the Company is committed to offer to
repurchase the interests of the limited partners and trust unitholders
in certain managed limited partnerships and trusts. During 1998, the
Company purchased such interests in an amount totaling $831,000.
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
F - 10
<PAGE> 26
to expand this program with additional 3D seismic surveys, leasehold
acquisitions and drilling. Outside investors have continued to
participate in the subsequent activities.
During 1997, the Company repurchased $1,242,000 of interests in the
trusts and partnerships of which it is manager.
F-11
<PAGE> 27
3. ACCOUNTS RECEIVABLE
Accounts receivable at December 31, 1998 and 1997 consisted of the
following:
<TABLE>
<CAPTION>
December 31,
---------------------------------
1998 1997
----------- -----------
<S> <C> <C>
Joint interest billing $ 1,395,000 $ 1,601,000
Trade receivables 264,000 213,000
Oil and gas sales 1,287,000 2,630,000
Other 71,000 62,000
----------- -----------
3,017,000 4,506,000
Less, allowance for doubtful accounts (127,000) (26,000)
----------- -----------
$ 2,890,000 $ 4,480,000
=========== ===========
</TABLE>
4. LONG-TERM BANK DEBT
During 1997 and 1998, the Company was party to a line of credit
agreement with a bank with a non-reducing borrowing base of $20 million.
Twenty-five percent of the borrowing is syndicated to a second bank.
During 1997, the agreement provided for interest at the bank's base rate
as defined, or 2-1/4% over the London Inter-Bank Offered Rate (LIBO
rate) for the interest period in question, payable at the end of the
interest period. 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 LIBO rate depending upon the Company's utilization of the
available line of credit.
The average interest rates paid on outstanding borrowings subject to
interest at the bank's base rate during 1998 and 1997 were 8.46% and
8.58%, respectively. During the same periods, the average rates paid on
outstanding borrowings bearing interest based upon the LIBO rate were
7.69% and 8.04%. As of December 31, 1998 and 1997, the total outstanding
borrowings were $16.5 million and $18.9 million, respectively, of which
$14.3 million and $13.7 million accrued interest at the LIBO rate
option.
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.
In February 1999, the credit agreement was revised to require that the
$20 million borrowing base, reestablished on October 14, 1998, would
begin reducing monthly by $300,000 beginning February 1, 1999.
5. 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.
F-12
<PAGE> 28
6. COMMITMENTS
Operating Leases:
The Company has several noncancelable operating leases, primarily for
rental of office space, that have a term of more than one year. Future
minimum lease payments under operating leases are as follows:
<TABLE>
<S> <C>
1999 $ 476,000
2000 466,000
2001 483,000
2002 430,000
2003 373,000
Thereafter 22,000
-----------
$ 2,250,000
===========
</TABLE>
7. CONTINGENT LIABILITIES
The Company, as managing general partner of the affiliated
Partnerships, is responsible for all Partnership activities, including
the review and analysis of oil and gas properties for acquisition, the
drilling of development wells and the production and sale of oil and
gas from productive wells. The Company also provides the
administration, accounting and tax preparation work for the
Partnerships, and is liable for all debts and liabilities of the
affiliated Partnerships, to the extent that the assets of a given
limited Partnership are not sufficient to satisfy its obligations.
The Company is subject to environmental laws and regulations.
Management believes that future expenses, before recoveries from third
parties, if any, will not have a material effect on the Company's
financial condition. This opinion is based on expenses incurred to date
for remediation and compliance with laws and regulations which have not
been material to the Company's results of operations.
As a general partner, the Company is committed to offer to purchase the
limited partners' interest in certain of its managed Partnerships at
various annual intervals. Under the terms of a partnership agreement,
the Company is not obligated to purchase an amount greater than 10% of
the total partnership interest outstanding. In addition, the Company
will be obligated to purchase interests tendered by the limited
partners only to the extent of one hundred fifty (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.
8. STOCK OPTIONS AND OTHER COMPENSATION
In May 1989, non-statutory stock options were granted by the Company to
four key executive officers for the purchase of shares of common stock.
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, 1998 and 1997,
options on 802,500 shares were outstanding and exercisable at prices
ranging from $1.00 to $1.25 per share.
On January 27, 1983, the Company adopted the 1983 Incentive Stock
Option Plan. At December 31, 1998 and 1997, options on 111,000 and
124,000 shares were exercisable at $1.50 per share, respectively, and
no additional shares were available for granting.
PEMC has a marketing agreement with its current President to provide
assistance and advice to PEMC in connection with the organization and
marketing of oil and gas partnerships and joint ventures and other
investment vehicles of which PEMC is to serve as general or managing
partner. The Company had a similar agreement with its former Chairman.
Although that agreement has expired, the former Chairman is still
entitled to receive certain 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> 29
PRIMEENERGY CORPORATION and SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued
9. INCOME TAXES
The components of the provision for income taxes for the year ended
December 31, 1998 and 1997 are as follows:
<TABLE>
<CAPTION>
1998 1997
---------- ---------
<S> <C> <C>
Federal:
Current $ (89,000) $ 28,000
Deferred (11,000) 11,000
State:
Current 7,000 65,000
Deferred (90,000) 8,000
---------- ---------
Total $ (183,000) $ 112,000
========== ========
</TABLE>
The components of net deferred tax assets (liabilities) are as follows:
<TABLE>
<CAPTION>
December 31, December 31,
1998 1997
------------ ------------
<S> <C> <C>
Current assets:
Compensation and benefits $ 120,000 $ 112,000
Allowance for doubtful accounts 9,000 9,000
Less, valuation allowance (111,000)
------------ ------------
18,000 121,000
------------ ------------
Noncurrent assets:
Depreciation 836,000 329,000
Due from related parties reserve 316,000 316,000
Net operating loss carryforwards 862,000 621,000
Percentage depletion carryforwards 1,033,000 1,067,000
Alternative minimum tax credits 685,000 757,000
Less, valuation allowance (1,670,000) (1,194,000)
------------ ------------
2,062,000 1,896,000
------------ ------------
Noncurrent liabilities:
Basis differences relating to limited partnerships (812,000) (837,000)
Depletion (1,307,000) (1,321,000)
------------ ------------
(2,119,000) (2,158,000)
------------ ------------
Net deferred tax liabilities: $ (39,000) $ (141,000)
============ ============
</TABLE>
F-14
<PAGE> 30
PRIMEENERGY CORPORATION and SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued
The total provision for income taxes for the years ended December 31,
1998 and 1997 varies from the federal statutory tax rate as a result of
the following:
<TABLE>
<CAPTION>
December 31, December 31,
1998 1997
------------ ------------
<S> <C> <C>
Expected statutory tax rate 34.00% 34.0%
State income tax, net of federal benefit 4.67% 6.4%
Effect of utilizing net operating loss carryforwards (11.0%)
Percentage depletion (4.9%)
Intangible drilling costs (14.6%)
Effect of valuation reserve against loss carryforwards (28.36)%
------ ----
10.31% 9.9%
====== ====
</TABLE>
The Company incurred a federal net operating loss for both regular and
alternative minimum tax purposes in 1998. Based on the carryback of
this loss, the Company expects to receive refunds of approximately
$72,000 in federal income taxes paid during the last three years. The
amount of the 1998 net operating loss which will not be absorbed by the
prior three years income will be approximately $1,070,000 and $565,000
for regular tax and alternative minimum tax respectively. This loss may
be carried forward for 15 years. Additionally, the Company has net
operating loss carryforwards from earlier years. Based upon a change in
ownership, the amount of such losses which may be deducted for both
regular and alternative minimum tax purposes limited to $365,000 in
each of the years 1999 through 2002, at which time such loss
carryforwards will expire.
The Company has percentage depletion carryforwards of approximately
$2,811,000 for regular tax purposes and $2,507,000 for alternative
minimum tax purposes. The Company has approximately $685,000 in
alternative minimum tax credit carryforwards.
Both the percentage depletion deductions and the alternative minimum
tax credits may be carried forward indefinitely for tax purposes.
10. SEGMENT INFORMATION AND MAJOR CUSTOMERS
The Company operates in one industry - oil and gas exploration,
development 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 1998 and 1997 included sales to one
purchaser for $2,061,000 and $3,627,000, respectively, which
represented approximately 18% of the Company's total revenue from oil
and gas sales in 1998, and 23% in 1997. In 1998, $1,192,000 of revenue
was generated from sales to another purchaser, representing an
additional 11% of the Company's total oil and gas revenue. In 1997,
$1,592,000 of revenue from sales to a third purchaser represented 10%
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.
F-15
<PAGE> 31
PRIMEENERGY CORPORATION and SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued
11. RELATED PARTY TRANSACTIONS
PEMC is a general partner in several oil and gas Partnerships in which
certain directors have limited and general partnership interests.
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.
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. During 1998 and 1997, the Company
received several loan payments from the borrower, reducing the
principal by approximately $10,000 in 1998 and $40,000 in 1997. 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 $470,000 and $480,000 at December 31, 1998 and
1997, respectively.
Due to related parties at December 31, 1998 and December 31, 1997
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 $731,000 and $1,389,000 at December 31,
1998 and 1997, respectively. Receivables from affiliates consist of
reimbursable general and administrative costs, lease operating expenses
and reimbursements for property acquisitions, development, and related
costs.
12. RESTRICTED CASH AND CASH EQUIVALENTS
Restricted cash and cash equivalents includes $1,080,000 and $885,000
at December 31, 1998 and December 31, 1997, respectively, of cash
primarily pertaining to unclaimed royalty payments. There were
corresponding accounts payable recorded at December 31, 1998 and 1997
for these liabilities.
13. SALARY DEFERRAL PLAN
The Company maintains a salary deferral plan (the "Plan") in accordance
with Internal Revenue Code Section 401(k), as amended. The Plan
provides for discretionary and matching contributions which
approximated $218,000 and $221,000 in 1998 and 1997, respectively.
F-16
<PAGE> 32
PRIMEENERGY CORPORATION and SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued
14. ACCOUNTS PAYABLE
A summary of accounts payable at December 31, 1998 and 1997 is as
follows:
<TABLE>
<CAPTION>
1998 1997
---- ----
<S> <C> <C>
Payables to unaffiliated interests $ 6,266,000 $ 6,285,000
Other 49,000 48,000
----------- ------------
$ 6,315,000 $ 6,333,000
=========== ============
</TABLE>
15. EARNINGS PER SHARE
Basic earnings per share are computed by dividing earnings available to
common stockholders by the weighted average number of common shares
outstanding during the period. Diluted earnings per share reflect per
share amounts that would have resulted if dilutive potential common
stock had been converted to common stock. The following reconciles
amounts reported in the financial statements:
<TABLE>
<CAPTION>
Year Ended Year Ended
December 31, 1998 December 31, 1997
----------------- -----------------
Net Number of Per Share Net Number of Per Share
Loss Shares Amount Income Shares Amount
---- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
Net income (loss) per
common share ................... $ (1,692,000) 4,471,201 $ (0.38) $ 1,024,000 4,664,957 $ 0.22
Effect of dilutive
securities:
Options (1) .................... -- -- -- -- 784,696 (0.03)
------------ --------- -------- ----------- --------- --------
Diluted net income
(loss) per common
share ........................... $ (1,692,000) 4,471,201 $ (0.38) $ 1,024,000 5,449,653 $ 0.19
============ ========= ======== =========== ========= ========
</TABLE>
(1) For the year ended December 31, 1998, the number of options
excluded from diluted loss per common share calculations were 771,186,
as the conversion of these would have had an anti-dilutive effect on
net loss per share.
F-17
<PAGE> 33
PRIMEENERGY CORPORATION and SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued
16. SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
<TABLE>
<CAPTION>
Year Ended
December 31, Fourth Third Second First
1998 Quarter Quarter Quarter Quarter
<S> <C> <C> <C> <C> <C>
Revenue $ 24,795,000 $ 5,837,000 $ 6,208,000 $ 6,573,000 $ 6,177,000
Operating income (loss) (2,145,000) (2,396,000) (53,000) 219,000 85,000
Net income (loss) (1,692,000) (2,037,000) 11,000 207,000 127,000
Net income (loss) per common
share $(0.38) $(0.46) $.00 $.05 $.03
Diluted net income (loss) per
common share $(0.38) $(0.46) $.00 $.04 $.02
</TABLE>
<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-18
<PAGE> 34
PRIMEENERGY CORPORATION AND SUBSIDIARIES
SUPPLEMENTARY INFORMATION
-----
(UNAUDITED)
F-19
<PAGE> 35
PRIMEENERGY CORPORATION and SUBSIDIARIES
CAPITALIZED COSTS RELATING to OIL and GAS PRODUCING ACTIVITIES
December 31, 1998 and 1997
(Unaudited)
<TABLE>
<CAPTION>
1998 1997
---- ----
<S> <C> <C>
Developed oil and gas properties $ 40,582,000 $ 41,427,000
Undeveloped oil and gas properties 1,284,000 231,000
------------ ------------
41,866,000 41,658,000
Accumulated depreciation, depletion and valuation allowance 25,077,000 21,397,000
------------ ------------
Net capitalized costs $ 16,789,000 $ 20,261,000
============ ============
</TABLE>
COSTS INCURRED in OIL and GAS PROPERTY ACQUISTION,
EXPLORATION and DEVELOPMENT ACTIVITIES
Years ended December 31, 1998 and 1997
(Unaudited)
<TABLE>
<CAPTION>
1998 1997
---- ----
<S> <C> <C>
Acquisition of properties:
Developed $ 870,000 $ 1,345,000
Undeveloped 1,310,000 231,000
Exploration costs, excluding valuation allowance 1,484,000 2,411,000
Development costs 2,718,000 7,079,000
</TABLE>
See accompanying notes to supplementary information.
F-20
<PAGE> 36
PRIMEENERGY CORPORATION and SUBSIDIARIES
STANDARDIZED MEASURE of DISCOUNTED FUTURE
NET CASH FLOWS RELATING to PROVED OIL and GAS RESERVES
years ended December 31, 1998 AND 1997
(Unaudited)
<TABLE>
<CAPTION>
1998 1997
---- ----
<S> <C> <C>
Future cash inflows $ 49,136,000 $ 62,024,000
Future production and development costs (27,931,000) (31,135,000)
Future income tax expenses (986,000) (1,321,000)
------------- ------------
Future net cash flows 20,219,000 29,568,000
10% annual discount for estimated timing of cash flow (6,938,000) (8,875,000)
------------- ------------
Standardized measure of discounted
future net cash flow $ 13,281,000 $ 20,693,000
============= ============
</TABLE>
See accompanying notes to supplementary information.
F-21
<PAGE> 37
PRIMEENERGY CORPORATION and SUBSIDIARIES
STANDARDIZED MEASURE of DISCOUNTED FUTURE
NET CASH FLOWS and CHANGES THEREIN RELATING
to PROVED OIL and GAS RESERVES
years ended December 31, 1998 and 1997
(Unaudited)
The following are the principal sources of change in the standardized measure of
discounted future net cash flows during 1998 and 1997
<TABLE>
<CAPTION>
1998 1997
---- ----
<S> <C> <C>
Sales of oil and gas produced, net of production costs $ (4,659,000) $ (8,450,000)
Net changes in prices and production costs (8,728,000) (4,735,000)
Extensions, discoveries and improved recovery,
less recovery costs 9,057,000 6,782,000
Revisions of previous quantity estimates (3,482,000) (3,082,000)
Reserves purchases, net of development costs 984,000 2,923,000
Net change in development costs (33,000) (116,000)
Reserves sold (3,527,000) (2,007,000)
Accretion of discount 2,069,000 3,064,000
Net change in income taxes 769,000 (3,405,000)
Other 138,000 (923,000)
------------- ------------
Net change (7,412,000) (9,949,000)
Standardized measure of discounted future net cash flow:
Beginning of year 20,693,000 30,642,000
------------- ------------
End of year $ 13,281,000 $ 20,693,000
============= ============
</TABLE>
See accompanying notes to supplementary information
F-22
<PAGE> 38
PRIMEENERGY CORPORATION and SUBSIDIARIES
RESERVE QUANTITY INFORMATION
years ended December 31, 1998 and 1997
(Unaudited)
<TABLE>
<CAPTION>
1998 1997
------------------------- ---------------------------
Gas Oil Gas Oil
(Mcf) (bbls.) (Mcf) (bbls.)
----- ------- ----- -------
<S> <C> <C> <C> <C>
Proved developed and undeveloped reserves:
Beginning of year 16,661,000 1,441,000 19,065,000 1,466,000
Extensions, discoveries
and improved recovery 5,993,000 80,000 3,764,000 282,000
Revisions of previous
estimates (1,125,000) (103,000) (1,731,000) (121,000)
Sales (2,047,000) (28,000) (2,086,000) (42,000)
Purchases 1,480,000 87,000 1,550,000 133,000
Production (3,621,000) (277,000) (3,901,000) (277,000)
---------- --------- ----------- -----------
End of year 17,341,000 1,200,000 16,661,000 1,441,000
========== ========= =========== ===========
Proved developed reserves 17,341,000 1,122,000 16,661,000 1,364,000
========== ========= =========== ===========
</TABLE>
See accompanying notes to supplementary information
F-23
<PAGE> 39
PRIMEENERGY CORPORATION and SUBSIDIARIES
RESULTS of OPERATIONS from OIL and GAS PRODUCING ACTIVITIES
years ended December 31, 1998 and 1997
(Unaudited)
<TABLE>
<CAPTION>
1998 1997
---- ----
<S> <C> <C>
Revenue:
Oil and gas sales $ 11,354,000 $ 15,485,000
------------ ------------
Costs and expenses:
Lease operating expense 6,695,000 7,035,000
Exploration costs 1,706,000 2,411,000
Depreciation and depletion 6,038,000 5,895,000
Income tax (benefit) expense (183,000) 10,000
------------ ------------
14,256,000 15,351,000
------------ ------------
Results of operations from producing activities
(excluding corporate overhead and interest costs) $ (2,902,000) $ 134,000
============ ============
</TABLE>
See accompanying notes to supplementary information
F-24
<PAGE> 40
PRIMEENERGY CORPORATION and SUBSIDIARIES
NOTES to SUPPLEMENTARY INFORMATION
(Unaudited)
1. PRESENTATION OF RESERVE DISCLOSURE INFORMATION
Reserve disclosure information is presented in accordance with the
provisions of Statement of Financial Accounting Standards No. 69 ("SFAS
69"), "Disclosures About Oil and Gas Producing Activities".
2. DETERMINATION OF PROVED RESERVES
The estimates of the Company's proved reserves were determined by an
independent petroleum engineer in accordance with the provisions of
SFAS 69. The estimates of proved reserves are inherently imprecise and
are continually subject to revision based on production history,
results of additional exploration and development and other factors.
Estimated future net revenues were computed by reserves, less estimated
future development and production costs based on current costs.
3. RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES
The results of operations from oil and gas producing activities were
prepared in accordance with the provisions of SFAS 69. General and
administrative expenses, interest costs and other unrelated costs are
not deducted in computing results of operations from oil and gas
activities.
4. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND
CHANGES THEREIN RELATING TO PROVED OIL AND GAS RESERVES
The standardized measure of discounted future net flows relating oil
and gas reserves and the changes of standardized measure of discounted
future net cash flows relating to proved oil and gas reserves were
prepared in accordance with the provisions of SFAS 69.
Future cash inflows are computed as described in Note 2 by applying
current prices to year-end quantities of proved reserves.
Future production and development costs are computed estimating the
expenditures to be incurred in developing and producing the oil and gas
reserves at year-end, based on year-end costs and assuming continuation
of existing economic conditions.
Future income tax expenses are calculated by applying the year-end U.S.
tax rate to future pre-tax cash inflows relating to proved oil and gas
reserves, less the tax basis of properties involved. Future income tax
expenses give effect to permanent differences and tax credits and
allowances relating to the proved oil and gas reserves.
Future net cash flows are discounted at a rate of 10% annually
(pursuant to SFAS 69) to derive the standardized measure of discounted
future net cash flows. This calculation does not necessarily represent
an estimate of fair market value or the present value of such cash
flows since future prices and costs can vary substantially from
year-end and the use of a 10% discount figure is arbitrary.
F-25
<PAGE> 41
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
21 Subsidiaries
22 Consent of Ryder Scott Company
27 Financial Data Schedule
</TABLE>
<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 22
[RYDER SCOTT COMPANY PETROLEUM ENGINEER 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 17, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 2,247
<SECURITIES> 0
<RECEIVABLES> 3,017
<ALLOWANCES> 127
<INVENTORY> 0
<CURRENT-ASSETS> 8,537
<PP&E> 48,437
<DEPRECIATION> 29,310
<TOTAL-ASSETS> 28,611
<CURRENT-LIABILITIES> 8,430
<BONDS> 16,505<F1>
0
0
<COMMON> 761
<OTHER-SE> 2,858<F2>
<TOTAL-LIABILITY-AND-EQUITY> 28,611
<SALES> 11,354
<TOTAL-REVENUES> 24,795
<CGS> 0
<TOTAL-COSTS> 25,603
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 1,337
<INCOME-PRETAX> (1,875)
<INCOME-TAX> (183)
<INCOME-CONTINUING> (1,692)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (1,692)
<EPS-PRIMARY> (0.38)
<EPS-DILUTED> (0.38)
<FN>
<F1>CURRENT PORTION LT DEBT
<F2>RETAINED EARNINGS (721) AND
TREASURY STOCK 7,323
</FN>
</TABLE>
