SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002
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-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Indicate by check mark whether the Registrant is an accelerated filer as defined
in Exchange Act Rule 12-b-2. Yes [ ] No [X]
The aggregate market value of the voting stock of the Registrant held by
non-affiliates, computed on the average bid and asked prices of such stock in
the over-the-counter market, as of March 25, 2003, was $8,642,432.
The number of shares outstanding of each class of the Registrant's Common Stock
as of March 25, 2002 was: Common Stock, $0.10 par value, 3,695,311.
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, 2003, are
incorporated by reference in Part III hereof.
PRIMEENERGY CORPORATION
FORM 10-K ANNUAL REPORT
FOR THE FISCAL YEAR ENDED
DECEMBER 31, 2002
PART I
ITEM 1. BUSINESS.
GENERAL
This Report contains forward-looking statements that are based on
management's current expectations, estimates and projections. Words such as
"expects," "anticipates," "intends," "plans," "believes," "projects" and
"estimates," and variations of such words and similar expressions are intended
to identify such forward-looking statements. These statements constitute
"forward-looking statements" within the meaning of Section 27A of the Securities
Act of 1933, and are subject to the safe harbors created thereby. These
statements are not guarantees of future performance and involve risks and
uncertainties and are based on a number of assumptions that could ultimately
prove inaccurate and, therefore, there can be no assurance that they will prove
to be accurate. Actual results and outcomes may vary materially from what is
expressed or forecast in such statements due to various risks and uncertainties.
These risks and uncertainties include, among other things, volatility of oil and
gas prices, competition, risks inherent in the Company's oil and gas operations,
the inexact nature of interpretation of seismic and other geological and
geophysical data, imprecision of reserve estimates, the Company's ability to
replace and expand oil and gas reserves, and such other risks and uncertainties
described from time to time in the Company's periodic reports and filings with
the Securities and Exchange Commission. Accordingly, stockholders and potential
investors are cautioned that certain events or circumstances could cause actual
results to differ materially from those projected.
PrimeEnergy Corporation (the "Company") was organized in March, 1973,
under the laws of the State of Delaware.
The Company is engaged generally in the oil and gas business through the
acquisition, exploration, development, and production of crude oil and natural
gas. The Company's properties are located primarily in Texas, Oklahoma, West
Virginia and Louisiana. The Company's wholly-owned subsidiary, PrimeEnergy
Management Corporation ("PEMC"), acts as the managing general partner in 38 oil
and gas limited partnerships (the "Partnerships") of which three are publicly
held, and acts as the managing trustee of two asset and income business trusts
("the Trusts"). The Company, through its wholly-owned subsidiaries Prime
Operating Company, Southwest Oilfield Construction Company, Eastern Oil Well
Service Company and EOWS Midland Company, acts as operator and provides well
servicing support operations for many of the oil and gas wells in which the
Partnerships, the Trusts and the Company have an interest, as well as for third
parties, primarily in Texas, Oklahoma and West Virginia. The Company is also
active in the acquisition of producing oil and gas properties through joint
ventures with industry partners and private investors.
THE PARTNERSHIPS AND TRUSTS
A substantial portion of the assets and revenues of PEMC are derived from
the interest of PEMC in the oil and gas properties acquired by the Partnerships
and Trusts. As the managing general partner in each of the Partnerships and
managing trustee of the Trusts, PEMC receives approximately from 5% to 15% of
the net revenues of each Partnership and Trust as a carried interest in the
Partnership's and Trust's properties.
Since 1975, PEMC has sponsored a total of 59 limited partnerships, 22 of
which were offered publicly and 37 of which were offered in private placements
and two Delaware business trusts, both of which were offered publicly. The
aggregate number of limited partners in the Partnerships and beneficial owners
of the Trusts now administered by PEMC is approximately 5,000. The Partnership
and Trust interests were sold by broker-dealers which are members of the
National Association of Securities Dealers, Inc. through a managing dealer. The
total funds contributed to the Partnerships and Trusts was about $157,550,000.
A significant portion of the Company's business is conducted through the
Partnerships and Trusts, either through its ownership of interests in various
properties derived through the Partnerships and Trusts, or as operator of, and a
provider of oilfield services for, oil and gas wells in which the Partnerships
and Trusts have interests.
2
PEMC, as managing general partner of the Partnerships and managing
trustee of the Trusts, is responsible for all Partnership and Trust activities,
including the review and analysis of oil and gas properties for acquisition, the
drilling of development wells and the production and sale of oil and gas from
productive wells. PEMC also provides administration, accounting and tax
preparation for the Partnerships and Trusts. PEMC is liable for all debts and
liabilities of the Partnerships and Trusts, to the extent that the assets of a
given limited partnership or trust are not sufficient to satisfy its
obligations.
JOINT VENTURES
PEMC organizes and the Company participates in various joint ventures
formed for the purpose of acquiring and developing oil and gas assets. The
Company receives varying interests in the net revenues of each joint venture as
a carried interest in the joint venture properties. The Company's participation
in the joint ventures varies from none to approximately 78%. The Company's
carried interest is generally 10% of funds contributed by outside investors.
Since 1987, our joint venture partners have invested $27.6 million with the
Company.
WELL OPERATIONS
The Company's operations are conducted through a central office in
Houston, Texas, and district offices in Houston and Midland, Texas, Oklahoma
City, Oklahoma, and Charleston, West Virginia. The Company currently operates
1,550 oil and gas wells, 434 through the Houston office, 162 through the Midland
office, 458 through the Oklahoma City office and 496 through the Charleston,
West Virginia office. Substantially all of the wells operated by the Company are
wells in which the Company, the Partnerships, the Trusts or our joint venture
partners have an interest.
The Company operates wells pursuant to operating agreements which govern
the relationship between the Company as operator and the other owners of working
interests in the properties, including the Partnerships, Trusts and joint
venture participants. For each operated well, the Company receives monthly fees
that are competitive in the areas of operations and also is reimbursed for
expenses incurred in connection with well operations.
EXPLORATION, DEVELOPMENT AND ACQUISITION ACTIVITIES; OTHER MATTERS
The Company continues to explore opportunities for the acquisition and
development of producing oil and gas properties, and will continue to engage in
exploratory operations and development drilling of properties in which it has an
interest. The Company attempts to assume the position of operator in all
acquisitions of producing properties.
RECENT ACTIVITIES
During 2002, the Company continued the development of existing properties
in Oklahoma and Texas, and participated in exploratory drilling in Texas.
Drilling activity in 2002 on the East Wakita and DSR prospects in Oklahoma
resulted in nine producers. Two additional wells were drilled in 2003 and are
waiting on pipeline connections. Drilling activity in Gaines County, Texas
resulted in production from two wells and additional potential for development
in 2003.
The Company's exploration program continues to identify prospects to be
evaluated. During 2002, four prospects were drilled resulting in two producers
and two dry holes. Drilling in 2003 has resulted in one successful well and one
dry hole. The Company expects to continue testing prospects in various counties
in Texas during the balance of 2003.
The Company is committed to offer to repurchase the interests of the
limited partners and trust unitholders in certain of the Partnerships, as
described more fully in Note 7 of the Financial Statements. During 2002, the
Company purchased such interests in an amount totaling $1,203,500.
The Company will continue to evaluate prospects for leasehold
acquisitions and for exploration and development operations in areas in which it
owns interests and is actively pursuing the acquisition of producing properties.
In order to diversify and broaden its asset base, the Company will
consider acquiring the assets or stock in other entities and companies in the
oil and gas business. The main objective of the Company in making any such
acquisitions will be to acquire income producing assets so as to increase the
Company's net worth and increase the Company's oil and gas reserve base.
The Company presently owns producing and non-producing properties located
primarily in Texas, Oklahoma, West Virginia and Louisiana, and owns a
substantial amount of well servicing equipment. The Company does not
3
own any refinery or marketing facilities, and does not currently own or lease
any bulk storage facilities or pipelines other than adjacent to and used in
connection with producing wells and the interests in certain gas gathering
systems. All of the Company's oil and gas properties and interests are located
in the continental United States.
In the past, the supply of gas has exceeded demand on a cyclical basis,
and the Company is subject to a combination of shut-in and/or reduced takes of
gas production during summer months. Prolonged shut-ins could result in reduced
field operating income from properties in which the Company acts as operator.
Exploration for oil and gas requires substantial expenditures
particularly in exploratory drilling in undeveloped areas, or "wildcat
drilling." As is customary in the oil and gas industry, substantially all of the
Company's exploration and development activities are conducted through joint
drilling and operating agreements with others engaged in the oil and gas
business.
Summaries of the Company's oil and gas drilling activities, oil and gas
production, and undeveloped leasehold, mineral and royalty interests are set
forth under Item 2., "Properties," below. Summaries of the Company's oil and gas
reserves, future net revenue and present value of future net revenue are also
set forth under Item 2., "Properties - Reserves" below.
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 Company's lease can be canceled in a proceeding instituted
by the United States Attorney General. Although the regulations of the BLM
(which administers the Mineral Act) provide for agency designations of
non-reciprocal countries, there are presently no such designations in effect.
The Company owns interests in federal onshore oil and gas leases. It is possible
that Common Stock could be acquired by citizens of foreign countries, which at
some time in the future might be determined to be non-reciprocal under the
Mineral Act.
TAXATION
The Company's oil and gas operations are affected by federal income tax
laws applicable to the petroleum industry. The Company is permitted to deduct
currently, rather than capitalize, intangible drilling and development costs
incurred or borne by it. As an independent producer, the Company is also
entitled to a deduction for percentage depletion with respect to the first 1,000
barrels per day of domestic crude oil (and/or equivalent units of domestic
natural gas) produced by it, if such percentage depletion exceeds cost
depletion. Generally, this deduction is computed based upon the lesser of 100%
of the net income, or 15% of the gross income from a property, without reference
to the basis in the property. The amount of the percentage depletion deduction
so computed which may be deducted in any given year is limited to 65% of taxable
income. Any percentage depletion deduction disallowed due to the 65% of taxable
income test may be carried forward indefinitely.
4
The Company is entitled to credits for producing fuel from a
non-conventional source under Section 29 of the Internal Revenue Code, primarily
from certain of the Company's operations in West Virginia.
See Notes 1 and 9 to the consolidated financial statements included in
this Report for a discussion of accounting for income taxes and availability of
federal tax net operating loss carryforwards and alternative minimum tax credit
carryforwards.
COMPETITION AND MARKETS
The business of acquiring producing properties and non-producing leases
suitable for exploration and development is highly competitive. Competitors of
the Company in its efforts to acquire both producing and non-producing
properties include oil and gas companies, independent concerns, income programs
and individual producers and operators, many of which have financial resources,
staffs and facilities substantially greater than those available to the Company.
Furthermore, domestic producers of oil and gas must not only compete with each
other in marketing their output, but must also compete with producers of
imported oil and gas and alternative energy sources such as coal, nuclear power
and hydroelectric power. Competition among petroleum companies for favorable oil
and gas properties and leases can be expected to increase.
The availability of a ready market for any oil and gas produced by the
Company at acceptable prices per unit of production will depend upon numerous
factors beyond the control of the Company, including the extent of domestic
production and importation of oil and gas, the proximity of the Company's
producing properties to gas pipelines and the availability and capacity of such
pipelines, the marketing of other competitive fuels, fluctuation in demand,
governmental regulation of production, refining, transportation and sales,
general national and worldwide economic conditions, and use and allocation of
oil and gas and their substitute fuels. There is no assurance that the Company
will be able to market all of the oil or gas produced by it or that favorable
prices can be obtained for the oil and gas production.
Listed below are the percent of the Company's total oil and gas sales
made to each of the customers whose purchases represented more than 10% of the
Company's oil and gas sales.
Texon Distributing L.P. 18.6%
Unimark LLC 20.1%
Plains All American, Inc. 10.1%
Although there are no long-term purchasing agreements with these
purchasers, the Company believes that they will continue to purchase its oil and
gas products and, if not, could be replaced by other purchasers.
ENVIRONMENTAL MATTERS
Over the past 30 years, the petroleum industry has been affected by a
wide variety of environmental issues. Throughout the 1970's and 1980's federal
and state environmental regulations have been enacted that affect all aspects of
the Company's operations. These regulations have primarily focused on correcting
existing environmental concerns and implementing preventive controls to reduce
future pollution.
The Company's activities are subject to existing federal, state and
local laws and regulations governing environmental quality and pollution
control. It is anticipated that, absent the occurrence of an extraordinary
event, compliance with existing federal, state and local laws, rules and
regulations regulating the release of materials in the environment or otherwise
relating to the protection of the environment will not have a material effect
upon the operations, capital expenditures, earnings or the competitive position
of the Company. The Company cannot predict what effect additional regulation or
legislation, enforcement policies thereunder, and claims for damages to
property, employees, other persons and the environment resulting from the
Company's operations or ownership of its property could have on its activities.
Activities of the Company with respect to oil and gas facilities,
including the operation and construction of pipelines, plants and other
facilities for transporting, processing, treating or storing oil and gas and
other products, are subject to stringent environmental regulation by state and
federal authorities including the Environmental Protection Agency ("EPA"). Such
regulation can increase the cost of planning, designing, installing and
operating such facilities. In most instances, the regulatory requirements relate
to water and air pollution control measures. Although the Company believes that
compliance with environmental regulations will not have a material adverse
effect on it, risks of substantial costs and liabilities are inherent in oil and
gas facility operations, and there can be no assurance that significant costs
and liabilities will not be incurred. Moreover, it is possible that other
developments, such as stricter environmental laws and regulations, and claims
for damages to property or persons resulting from operation of oil and gas
facilities, would result in substantial costs and liabilities to the Company.
5
The Company currently owns or leases, and has in the past owned or
leased, numerous properties that have been used for production of oil and gas
for many years. Although the Company has utilized operating and disposal
practices that were standard in the industry at the time, hydrocarbons or other
wastes may have been disposed of or released on or under the properties owned or
leased by the Company. In addition, many of these properties have been operated
by third parties over whom the Company had no control as to such entities'
treatment of hydrocarbons or other wastes and the manner in which such
substances may have been disposed of or released. State and federal laws
applicable to oil and gas wastes and properties have gradually become stricter.
Under these new laws, the Company could be required to remove or remediate
previously disposed wastes (including wastes disposed of or released by prior
owners or operators) or property contamination (including groundwater
contamination) or to perform remedial plugging operations to prevent future
contamination.
The Company may generate wastes, including hazardous wastes, that are
subject to the Federal Resource Conservation and Recovery Act and comparable
state statutes. The EPA has limited the disposal options for certain hazardous
wastes and is considering the adoption of stricter disposal standards for
non-hazardous wastes. Furthermore, certain wastes generated by the Company's oil
and gas operations that are currently exempt from treatment as "hazardous
wastes" may in the future be designated as "hazardous wastes," and therefore be
subject to more rigorous and costly operating and disposal requirements.
In addition, legislation has been proposed in Congress from time to
time that would reclassify certain oil and gas exploration and production wastes
as "hazardous wastes," which would make the reclassified wastes subject to much
more stringent handling, disposal and clean-up requirements. If such legislation
were to be enacted, it could have a significant impact on the operating costs of
the Company, as well as the oil and gas industry in general. Initiatives to
further regulate the disposal of oil and gas wastes are also pending in certain
states, and these various initiatives could have a similar impact on the
Company.
The Federal Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "Superfund" law, imposes joint and
several liability, without regard to fault or the legality of the original
conduct, on certain classes of persons with respect to the release of a
"hazardous substance" into the environment. These persons include the current
owner and operator of a site and persons that disposed of or arranged for the
disposal of the hazardous substances found at a site. CERCLA also authorizes the
EPA and, in some cases, third parties to take actions in response to threats to
the public health or the environment and to seek to recover from the responsible
classes of persons the costs of such action. In the course of its operations,
the Company may have generated and may generate wastes that fall within CERCLA'S
definition of "hazardous substances." The Company may also be an owner of sites
on which "hazardous substances" have been released by previous owners or
operators. The Company may be responsible under CERCLA for all or part of the
costs to clean up sites at which such wastes have been released. Neither the
Company nor, to its knowledge, its predecessors has been named a potentially
responsible person under CERCLA, nor does the Company know of any prior owners
or operators of its properties that are named as potentially responsible parties
related to their ownership or operation of such property.
The Company has a proactive environmental policy that management feels
benefits the Company through increased operating profits, improved landowner
relations and an overall enhanced Company image. To this end, the Company has
also adopted a stringent environmental evaluation prior to purchasing a
property. This pre-acquisition assessment, usually referred to as an
Environmental Site Assessment, typically consists of a historical review of the
property combined with a site inspection and limited testing, when necessary.
The objective of this pre-acquisition assessment is to document conditions at
the time of acquisition and to assign liability to the seller for past
operations.
EMPLOYEES
At March 25, 2003, the Company had 196 full-time and 5 part-time
employees, 17 of whom were employed by the Company at its principal offices in
Stamford, Connecticut, 22 in Houston, Texas, at the offices of Prime Operating
Company, Eastern Oil Well Service Company and EOWS Midland Company and 162
employees who were primarily involved in the district operations of the Company
in Houston and Midland, Texas, Oklahoma City, Oklahoma and Charleston, West
Virginia.
ITEM 2. PROPERTIES.
The Company's executive offices and those of PEMC, are located at One
Landmark Square, Stamford, Connecticut, in leased premises of about 8,860 square
feet. The executive offices of Prime Operating Company, Eastern Oil Well Service
Company and EOWS Midland Company are located in leased premises in Houston,
Texas, and the offices of Southwest Oilfield Construction Company are in
Oklahoma City, Oklahoma.
6
The Company maintains district offices in Houston and Midland, Texas,
Oklahoma City, Oklahoma and Charleston, West Virginia, and has field offices in
Carrizo Springs and Midland, Texas, Kingfisher and Garvin, Oklahoma and Orma,
West Virginia.
The Company owns several parcels of land in Oklahoma, on which oil and
gas wells it owns and operates are located. These properties were purchased
primarily to simplify operations of these properties.
Substantially all of the Company's oil and gas properties are subject
to a mortgage given to collateralize indebtedness of the Company, or are subject
to being mortgaged upon request by the Company's lender for additional
collateral.
The information set forth below concerning the Company's properties,
activities, and oil and gas reserves include the Company's interests in the
Partnerships, Trusts and joint ventures.
The following table sets forth the exploratory and development drilling
experience with respect to wells in which the Company participated during the
five years ended December 31, 2002.
<Table>
<Caption>
2002 2001 2000 1999 1998
--------------- --------------- --------------- --------------- ---------------
Gross Net Gross Net Gross Net Gross Net Gross Net
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Exploratory:
Oil 1 1 1 1.000 -- -- 1 .300 1 .468
Gas 1 .25 1 .602 3 1.279 1 .683 2 .387
Dry 4 2.50 -- -- 2 .276 2 .510 2 .686
Development:
Oil 2 1.25 1 .500 -- -- -- -- 1 .145
Gas 10 7.59 7 4.926 7 4.134 2 .015 5 .316
Dry 6 5.30 2 1.585 -- -- 2 .745 -- --
Total:
Oil 3 2.25 2 1.500 -- -- 1 .300 2 .613
Gas 11 7.84 8 5.528 10 5.413 3 .698 7 .703
Dry 10 7.80 2 1.585 2 .276 4 1.255 2 .686
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
24 17.89 12 8.613 12 5.689 8 2.253 11 2.002
====== ====== ====== ====== ====== ====== ====== ====== ====== ======
</Table>
OIL AND GAS PRODUCTION
As of December 31, 2002, the Company had ownership interests in the
following numbers of gross and net producing oil and gas wells and gross and net
producing acres (1).
<Table>
<Caption>
Gross Net
------- ------
Producing wells(1)
Oil Wells 891 244.85
Gas Wells 1,156 297.64
Producing Acres 269,298 68,657
</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, 2002. "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>
2002 2001 2000 1999 1998
--------- --------- --------- --------- ---------
Oil (barrels) ................ 321,000 306,000 298,000 264,000 277,000
Gas (Mcf) .................... 3,540,000 3,764,000 3,930,000 3,289,000 3,621,000
</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, 2002.
7
<Table>
<Caption>
2002 2001 2000 1999 1998
------------ ------------ ------------ ----------- ----------
Average sales price per barrel ...... $ 23.37 24.92 28.34 15.71 12.39
Average sales price Per Mcf ......... $ 3.06 4.08 3.76 2.32 2.19
Average production costs per net
equivalent barrel(1) .............. $ 11.80 11.88 9.57 7.76 7.60
</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, 2002. "Undeveloped acreage" is that acreage on
which wells have not been drilled or completed to a point that would permit the
production of commercial quantities of oil and gas, regardless of whether or not
such acreage contains proved reserves.
<Table>
<Caption>
Leasehold Mineral Royalty
Interests Interests Interests
------------------------- ------------------------- -------------------------
Gross Net Gross Net Gross Net
State Acres Acres Acres Acres Acres Acres
- ------------ ---------- ---------- ---------- ---------- ---------- ----------
Colorado -- -- 799 23 -- --
Montana -- -- 13,984 59 786 5
Nebraska -- -- 2,553 331 -- --
North Dakota -- -- 640 1 -- --
Oklahoma 6,462 3,228 320 1 -- --
Texas 8,411 5,472 680 16 -- --
Wyoming 1,000 125 5043 35 140 35
---------- ---------- ---------- ---------- ---------- ----------
TOTAL 15,873 8,825 24,019 466 926 40
========== ========== ========== ========== ========== ==========
</Table>
RESERVES
The Company's interests in proved developed and undeveloped oil and gas
properties have been evaluated by Ryder Scott & Company L.P. for the years ended
December 31, 1998, 1999, 2000, 2001 and 2002. 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)
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
1998 1,122,000 17,341,000 78,000 -- 1,200,000 17,341,000
1999 2,110,000 22,046,000 -- 156,000 2,110,000 22,202,000
2000 2,362,000 27,029,000 -- -- 2,362,000 27,029,000
2001 1,996,000 24,266,000 -- 453,000 1,996,000 24,719,000
2002 2,319,000 29,917,000 -- -- 2,319,000 29,917,000
</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, 2002, are summarized as follows (figures
rounded):
8
<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
----- ------------ ------------ ------------- ------------- ------------- -------------
1998 $ 20,839,000 13,444,000 359,000 212,000 21,198,000 13,656,000
1999 $ 41,103,000 26,057,000 258,000 151,000 41,361,000 26,208,000
2000 $199,376,000 113,137,000 -- -- 199,376,000 113,137,000
2001 $ 41,086,000 24,653,000 957,000 629,000 42,043,000 25,282,000
2002 $ 97,600,000 56,855,000 -- -- 97,600,000 56,855,000
</Table>
"Proved developed" oil and gas reserves are reserves that can be
expected to be recovered from existing wells with existing equipment and
operating methods. "Proved undeveloped" oil and gas reserves are reserves that
are expected to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required for
recompletion.
In accordance with FASB Statement No. 69, December 31 market prices are
determined using the daily oil price or daily gas sales price ("spot price")
adjusted for oilfield or gas gathering hub and wellhead price differentials
(e.g. grade, transportation, gravity, sulfur, and BS&W) as appropriate. Also in
accordance with SEC and FASB specifications, changes in market prices subsequent
to December 31 are not considered.
The spot prices for gas at December 31, 2002 and 2001 were $4.75 and
$2.63 per MMBTU, respectively. The range of spot prices during the year 2002 was
a low of $1.98 and a high of $5.05 and the average was $3.38. The range during
the first quarter of 2003 has been from $4.88 to $9.50 with an average of $6.62.
The recent futures market prices have been around $5.00.
The NYMEX price for oil at December 31, 2002 and 2001 was $31.23 and
$19.84 per barrel, respectively. The range of NYMEX prices during the year 2002
was a low of $17.97 and a high of $32.49 and the average was $26.15. The range
during the first quarter of 2003 has been from $30.56 to $37.83 with an average
of $33.89. The recent futures market prices have fluctuated around $30.
While it may reasonably be anticipated that the prices received by the
Company for the sale of its production may be higher or lower than the prices
used in this evaluation, as described above, and the operating costs relating to
such production may also increase or decrease from existing levels, such
possible changes in prices and costs were, in accordance with rules adopted by
the SEC, omitted from consideration in making this evaluation for the SEC case.
Actual volumes produced, prices received and costs incurred by the Company may
vary significantly from the SEC case.
Since January 1, 2003, the Company has not filed any estimates of its
oil and gas reserves with, nor were any such estimates included in any reports
to, any federal authority or agency, other than the Securities and Exchange
Commission, except Form EIA-23, Annual Survey of Domestic Oil and Gas Reserves,
filed with The Energy Information Administration of the U.S. Department of
Energy.
ITEM 3. LEGAL PROCEEDINGS.
From time to time, the Company is party to certain legal actions and
claims arising in the ordinary course of business. While the outcome of these
events cannot be predicted with certainty, management does not expect these
matters to have a materially adverse effect on the financial position or results
of operations of the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS.
No matters were submitted during the fourth quarter of the fiscal year
ended December 31, 2002, 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, 2002, were as follows:
<Table>
<Caption>
2002 High Low 2001 High Low
- -------------------------------- ---------- ---------- ------------------------ --------- ---------
First Quarter .................. $ 8.53 $ 7.90 First Quarter .......... $ 6.56 $ 6.49
Second Quarter ................. 9.07 8.00 Second Quarter ......... 8.11 7.75
Third Quarter .................. 9.01 8.00 Third Quarter .......... 8.47 8.30
Fourth Quarter ................. 8.25 8.00 Fourth Quarter ......... 8.00 7.95
</Table>
9
The above quotations reflect inter-dealer prices, without retail mark-up,
mark-down or commissions, and may not represent actual transactions.
The approximate number of record holders of the Company's Common Stock
as of March 25, 2003 was 1,025.
No dividends have been declared or paid during the past two years on
the Company's Common Stock. Provisions of the Company's line of credit agreement
restrict the Company's ability to pay dividends. Such dividends may be declared
out of funds legally available therefore, when and as declared by the Company's
Board of Directors.
ITEM 6. SELECTED FINANCIAL DATA
The following table summarizes certain selected financial data to
highlight significant trends in the Company's financial condition and results of
operations for the periods indicated. The selected financial data should be read
in conjunction with the Financial Statements and related notes included
elsewhere in this Report.
<Table>
<Caption>
2002 2001 2000 1999 1998
----------- ----------- ----------- ----------- -----------
Revenues $35,934,000 42,408,000 39,182,000 25,520,000 24,795,000
Income (loss) from operations $ 2,168,000 6,968,000 6,148,000 (2,116,000) (2,061,000)
Net Income (loss) $ 1,757,000 5,413,000 5,365,000 (2,138,000) (1,692,000)
Income (loss) per common share $ 0.47 1.39 1.26 (0.48) (0.38)
Net Cash provided by operations $ 9,644,000 12,313,000 11,498,000 7,677,000 6,846,000
Total Assets $44,887,000 35,816,000 35,094,000 30,475,000 28,611,000
Long-term obligations $23,734,000 16,958,000 18,213,000 19,217,000 16,505,000
Cash Dividends None None None None None
</Table>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
This discussion should be read in conjunction with the financial
statements of the Company and notes thereto. The Company's subsidiaries are
defined in Note 1 of the financial statements. PEMC is the managing general
partner or managing trustee in several Limited Partnerships and Trusts
(collectively, the "Partnerships").
LIQUIDITY AND CAPITAL RESOURCES
Net cash provided by operations was $9,644,000 in 2002, $12,313,000 in
2001, and $11,498,000 in 2000.
As of December, 2002, the Company entered in to a credit agreement with
a new primary lender. The Company and the lender agreed to amend and restate in
its entirety the credit agreement dated April 26, 1995 between the Company and
its predecessor lender. This agreement will continue to provide for borrowings
under a Master Note. Advances under the agreement, as amended, are limited to
the borrowing base as defined in the agreement. The borrowing base is
re-determined by the lender on a semi-annual basis. The current borrowing base
is $25 million and includes a Term Loan of $4 million. The Term Loan will be
paid back in monthly installments of $66,667 beginning January 2003 and
continuing until December 19, 2004, when such Term Loan shall be paid in full.
The credit agreement provides for interest on outstanding borrowings at the
bank's base rate, as defined, payable monthly, or at rates 2% over the London
Inter-Bank Offered Rate (LIBO rate) payable at the end of the applicable
interest period.
The Company had been party to a series of credit agreements with its
former lender or its predecessors since 1983. The agreement, entered into in
April 1995, provided for borrowings under a Master Note. Advances under the
agreement, as amended, were limited to the borrowing base as defined in the
agreement and re-determined by the lender on a semi-annual basis. Since the
beginning of 2000, the borrowing base ranged from $20 million to $23.7 million.
The credit agreement provided for interest on outstanding borrowings at the
bank's base rate, as defined, payable monthly, or at rates ranging from 1 1/2%
to 2% over the London Inter-Bank Offered Rate (LIBO rate) depending upon the
Company's utilization of the available line of credit, payable at the end of the
applicable interest period. This credit agreement was assigned to the Company's
primary lender effective December 2002.
The average interest rates paid on outstanding borrowings subject to
interest at the bank's base rate during 2002 and 2001 were 4.25% and 6.92%,
respectively. During the same periods, the average rates paid on outstanding
borrowings bearing interest based upon the LIBO rate were 3.59% and 5.98% As of
December 31,
10
2002 and 2001, the total outstanding borrowings were $24,500,000 and
$16,950,000, respectively, with an additional $500,000 and $6,050,000 available.
As of December 31, 2001 $14,950,000 of the amounts outstanding accrued interest
at the LIBO rate option.
The Company's oil and gas properties as well as certain receivables and
equipment are pledged as security under the credit agreement. The agreement
requires the Company to maintain, as defined, a minimum current ratio, tangible
net worth, debt coverage ratio and interest coverage ratio, and restrictions are
placed on the payment of dividends and the amount of treasury stock the Company
may purchase.
The Company spent approximately $3,000,000 developing the East Wakita
field during 2002. Seven successful wells were drilled on this property in 2002,
and two more successful wells were drilled in the first quarter of 2003. Further
development of this prospect is planned for the future.
The Company spent $2,200,000 developing the DSR prospect in Garvin
County, Oklahoma. First sales from this field occurred in January 2002.
Additional development of this field is planned for 2003.
In total, the Company spent $13,186,000 on the acquisition and
development of oil and gas properties during 2002, including $1,203,500 spent to
repurchase partnership interests from investors in its oil and gas partnerships.
The Company spent $1,310,000 on field service equipment during 2002,
and an additional $180,000 on computers, software and related equipment. The
Company spent $745,000 to repurchase shares of its treasury stock in 2002. As of
the date of this Report, the Company had spent an additional $27,000 on treasury
stock purchases in 2003.
It is the goal of the Company to increase its oil and gas reserves and
production through the acquisition and development of oil and gas properties.
The Company also continues to explore and consider opportunities to further
expand its oilfield servicing revenues through additional investment in field
service equipment. However, the majority of the Company's capital spending is
discretionary, and the ultimate level of expenditures will be dependent on the
Company's assessment of the oil and gas business environment, the number and
quality of oil and gas prospects available, the market for oilfield services,
and oil and gas business opportunities in general.
RESULTS OF OPERATIONS:
2002 AS COMPARED TO 2001
The Company had net income of $1,757,000 in 2002 as compared to
$5,413,000 in 2001. The decrease in net income is primarily due to lower
commodity prices.
Oil and gas sales were $18,330,000 in 2002 as compared to $22,998,000
in 2001 A chart summarizing oil and gas production and revenue, including the
Company's share of production and revenue from the Partnerships, follows.
<Table>
<Caption>
2002 2001 Increase (Decrease)
----------- ----------- -------------------
Barrels of Oil Produced 321,384 306,016 15,368
Average Price Received $ 23.37 $ 24.9199 $ (1.5499)
----------- -----------
Oil Revenue $ 7,510,000 $ 7,626,000 $ (117,000)
----------- -----------
Mcf of Gas Produced 3,540,000 3,763,605 (259,605)
Average Price Received $ 3.0564 $ 4.0843 $ (1.0279)
----------- -----------
Gas Revenue $10,820,000 $15,372,000 $(4,552,000)
----------- -----------
Total Oil & Gas Revenue $18,330,000 $22,998,000 $(4,668,000)
=========== ===========
</Table>
District operating income decreased from $17,082,000 in 2001 to
$15,308,000 in 2002. This decrease is due to reduced utilization of equipment
combined with discounted rates in effect during the first half of 2002.
11
Lease operating expenses decreased by 8% to $10,210,000 in 2002 as
compared to $11,083,000 in 2001. The difference is attributable to production
taxes related to lower prices combined with discounts on expenses due to the
weak price environment in the first half of 2002.
Administrative revenue, which represents the reimbursement of general
and administrative overhead expended on behalf of the Partnerships and the
Company's joint venture partners decreased by 4% to $1,473,000 in 2002 as
compared to $1,535,000 in 2001. In both years, amounts received from certain of
the Partnerships were substantially less than the amounts allocable to these
Partnerships under the partnership agreements. The lower amounts reflect PEMC's
continuing efforts to reduce costs, both incurred and allocated to the
Partnerships.
Reporting and management fees are earned from providing the accounting
and reporting functions for certain of the Partnerships.
The Company receives reimbursement for costs incurred related to the
evaluation and acquisition of properties on behalf of the Partnerships and other
joint venture partners. To the extent that these property acquisition costs are
expended at the district level, the reimbursements are recorded as a reduction
of total district operating expenses. When expenses are incurred at the
corporate headquarters level, such reimbursements are recorded as a reduction of
total general and administrative expenses. During 2002 and 2001, the Company's
total reimbursements for property acquisition costs were approximately $450,000
and $558,000, respectively.
General and administrative expenses increased to $4,888,000 in 2002 as
compared to $4,310,000 in 2001. This increase reflects the change in cost
reimbursement combined with an increase in the Company's share of general and
administrative expenses incurred by the Partnerships.
Depreciation and depletion of oil and gas properties decreased by 12%
to $3,988,000 in 2002 as compared to $4,522,000 in 2001 as a result of increases
in estimates of proved reserves.
Exploration costs of $894,000 were incurred during 2002 drilling five
dry holes. Exploration costs of $509,000 in 2001 consist primarily of the cost
of three dry holes drilled in 2001.
Interest expense declined to $766,000 in 2002 as compared to $895,000
in 2001 due to a combination of lower interest rates and lower average
outstanding debt. The average interest rates paid on outstanding borrowings
subject to interest at the bank's base rate during 2002 and 2001 were 4.25% and
6.92%, respectively. During the same periods, the average rates paid on
outstanding borrowings bearing interest based upon the LIBO rate were 3.58% and
5.98%. As of December 31, 2002 and 2001, the total outstanding borrowings
were$24,500,000 and $16,950,000, respectively.
Income tax expense of $443,000 in 2002 represents a 20% effective rate
as compared to the effective rate of 24% in 2001. Current tax expense in 2002
was $199,000, with the remainder being attributable to an increase in the
Company's deferred tax liability. The low current tax expense is primarily
attributable to federal tax credits for producing fuel from a nonconventional
source, percentage depletion deductions, larger depreciation deductions allowed
for tax purposes, and the utilization of federal net operating loss carry
forward.
All of the Company's net operating loss carry forwards will have been
used or expired as of the end of 2002, and under current law the credit for
producing fuel from a nonconventional source will no longer be allowed after
2002. It is possible that the Company's current and overall tax rates may be
significantly higher in future years.
12
2001 AS COMPARED TO 2000
The Company had net income of $5,413,000 in 2001, as compared to
$5,365,000 in 2000. Oil and gas production and revenue remained flat, and
district operating income increased by 26% to $17,082,000, contributing to an 8%
increase in overall revenues to $42,408,000.
Oil and gas sales were $22,998,000 in 2001 as compared to $23,223,000
in 2000, a drop of less than 1%. A chart summarizing oil and gas production and
revenue, including the Company's share of production and revenue from the
Partnerships, follows.
<Table>
<Caption>
2001 2000 Increase (Decrease)
----------- ----------- -------------------
Barrels of Oil Produced 306,016 297,562 8,454
Average Price Received $ 24.9199 $ 28.3354 $ (3.4155)
----------- -----------
Oil Revenue $ 7,626,000 $ 8,432,000 $(806,000)
----------- -----------
Mcf of Gas Produced 3,763,605 3,929,532 (165,927)
Average Price Received $ 4.0843 $ 3.7641 $ 0.3202
----------- -----------
Gas Revenue $15,372,000 $14,791,000 $ 581,000
----------- -----------
Total Oil & Gas Revenue $22,998,000 $23,223,000 $(225,000)
=========== ===========
</Table>
The Company completed a successful well on its Cadiz field in Bee
County, Texas during 2001. Two successful wells had been completed on this
prospect in 2000. These three wells contributed 3,400 barrels of oil, 380,000
Mcf of gas and $1,624,000 in revenue in 2001, as compared to 1,200 barrels,
168,000 Mcf of gas and $853,000 in 2000. No further drilling is currently
planned for this prospect.
The Company drilled three successful wells on the East Wakita field
in 2001. This prospect contributed $915,000 to oil and gas revenues in 2001.
The Francis Martin well experienced a natural decline in gas and oil
production and increase in water production as well as shut-ins for mechanical
work during 2001. This well contributed 2,000 barrels of oil, 115,000 Mcf of gas
and $654,000 in revenue in 2001, as compared to 6,000 barrels, 371,000 Mcf and
$1,654,000 in 2000.
District operating income increased 26% to $17,082,000 in 2001 as
compared to $13,585,000 in 2000. This increase reflects the utilization of the
over $2,000,000 in field service equipment the Company purchased during the
year, and its focus on expanding the amount of work performed for third parties
on wells not operated by the Company. This increase also reflects full
administrative overhead charges on marginal properties where the Company had
previously discounted such fees.
Lease operating expenses increased by 22% to $11,083,000 in 2001 as
compared to $9,114,000 in 2000. Approximately $874,000 of this amount is
attributable to properties purchased or developed during 2000 or 2001. The
remainder of the difference is primarily attributable to an increase in repair
and fix-up work performed, and a decrease in discounts received on
administrative overheads due to the strong price environment in 2001.
Administrative revenue, which represents the reimbursement of general
and administrative overhead expended on behalf of the Partnerships and the
Company's joint venture partners decreased by 7% to $1,535,000 in 2001 as
compared to $1,655,000 in 2000. In both years, amounts received from certain of
the Partnerships were substantially less than the amounts allocable to these
Partnerships under the partnership agreements. The lower amounts reflect PEMC's
continuing efforts to reduce costs, both incurred and allocated to the
Partnerships.
Reporting and management fees are earned from providing the accounting
and reporting functions for certain of the Partnerships.
The Company receives reimbursement for costs incurred related to the
evaluation and acquisition of properties on behalf of the Partnerships and other
joint venture partners. To the extent that these property acquisition costs are
expended at the district level, the reimbursements are recorded as a reduction
of total district operating expenses. When expenses are incurred at the
corporate headquarters level, such reimbursements are
13
recorded as a reduction of total general and administrative expenses. During
2001 and 2000, the Company's total reimbursements for property acquisition costs
were approximately $558,000 and $1,100,000, respectively.
General and administrative expenses increased 7% to $4,310,000 in 2001
as compared to $4,033,000 in 2000. This increase reflects the change in cost
reimbursement offset by savings related to overhead efficiencies.
Depreciation and depletion of oil and gas properties decreased by 11%
to $4,522,000 in 2001 as compared to $5,060,000 in 2000, while impairments
increased to $753,000 in 2001 as compared to $295,000 in 2000. Total depletion
and impairment expense in 2001 was $5,275,000 in 2001 as compared to $5,355,000
in 2000, a decline of approximately 1%.
Exploration costs of $509,000 in 2001 consist primarily of the cost of
three dry holes drilled in 2001. Exploration costs of $1,797,000 in 2000
consisted primarily of dry hole costs relating to the drilling of two offshore
wells in the fourth quarter of that year.
Interest expense decreased by 40% to $895,000 in 2001 as compared to
$1,500,000 in 2000 due to a combination of lower interest rates and lower
average outstanding debt. The average interest rates paid on outstanding
borrowings subject to interest at the bank's base rate during 2001 and 2000 were
6.92% and 9.46%, respectively. During the same periods, the average rates paid
on outstanding borrowings bearing interest based upon the LIBO rate were 5.98%
and 8.46%. As of December 31, 2001 and 2000, the total outstanding borrowings
were $16,950,000 and $17,200,000, respectively, with an additional $6,050,000
and $1,750,000 available, and $14,950,000 and $13,500,000 of the amounts
outstanding accruing interest at the LIBO rate option.
Income tax expense increased by 112% to $1,721,000 in 2001 as compared
to $811,000 in 2000. The effective rate was 24% in 2001 as compared to 13% in
2000. In both 1998 and 1999, the Company had large federal net operating losses.
The value of these loss carryforwards was fully reserved against due to the
uncertainty as to whether the Company would have future net income against which
these losses could be offset. The use of these previously reserved against
carryforwards were the primary reason for the low effective rate in 2000.
Current tax expense in 2001 was $38,000, with the remainder of expense
being attributable to an increase in the Company's deferred tax liability. The
Company generates approximately $350,000 of federal tax credits under Internal
Revenue Code Section 29 for producing fuel from a non-conventional source. These
credits, which significantly lower current tax expense, are scheduled to expire
after 2002. Another contributing factor to the extremely low current expense is
that the Company is allowed to deduct currently for income tax purposes
intangible drilling costs which are capitalized for financial reporting
purposes. The Company had over $5,000,000 in such costs during 2001.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The Company is exposed to interest rate risk on its line of credit,
which has variable rates based upon the lenders base rate, as defined, and the
London Inter-Bank Offered rate. Based on the balance outstanding at December 31,
2002, a hypothetical 2% increase in the applicable interest rates would increase
interest expense by approximately $375,500.
Oil and gas prices have historically been extremely volatile, and have
been particularly so in recent years. The Company did not enter into significant
hedging transactions during 2002, and had no open hedging transactions at
December 31, 2002. Declines in domestic oil and gas prices could have a material
adverse effect on the Company's revenues, operating results, estimates of
economically recoverable reserves and the net revenue therefrom.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Included on pages F-1 through F-26 of this Report. The Index to
Financial Statements is at page F-1 of this Report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
14
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information relating to the Company's Directors, nominees for Directors
and executive officers is included in the Company's definitive proxy statement
relating to the Company's Annual Meeting of Stockholders to be held in June,
2003, which will be filed with the Securities and Exchange Commission within 120
days of December 31, 2002, and which is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION.
Information relating to executive compensation is included in the
Company's definitive proxy statement relating to the Company's Annual Meeting of
Stockholders to be held in June, 2003, which will be filed with the Securities
and Exchange Commission within 120 days of December 31, 2002, and which is
incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS.
Information relating to security ownership of certain beneficial owners
and management is included in the Company's definitive proxy statement relating
to the Company's Annual Meeting of Stockholders to be held in June, 2003, which
will be filed with the Securities and Exchange Commission within 120 days of
December 31, 2002, and which is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Information relating to certain transactions by Directors and executive
officers of the Company is included in the Company's definitive proxy statement
relating to the Company's Annual Meeting of Stockholders to be held in June,
2003, which will be filed with the Securities and Exchange Commission within 120
days of December 31, 2002, and which is incorporated herein by reference.
ITEM 14. INTERNAL CONTROLS AND PROCEDURES.
Based upon an evaluation within the 90 days prior to the filing date of
this Report, our Chief Executive Officer and Chief Financial Officer have each
concluded that our disclosure controls and procedures as defined in Rules 13a-14
and 15d-14 of the Securities Exchange Act of 1934, as amended, are effective, as
of the evaluation date, in timely alerting them to material information relating
to our Company required to be included in our reports filed or submitted under
the Exchange Act. Since the date of the evaluation, there have been no
significant changes in our internal controls or in other factors that could
significantly affect such controls, including any corrective actions with regard
to significant deficiencies and material weaknesses.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) The following documents are filed as a part of this Report:
1. Financial Statements (Index to Financial Statements at
page F-1 of this Report)
2. Financial Statement Schedules (Index to Financial Statements
-- Supplementary Information)
3. Exhibits:
No.
3.1 Restated Certificate of Incorporation of PrimeEnergy
Corporation. (Incorporated herein by reference to Exhibit 3.1
of PrimeEnergy Corporation Form 10-KSB for the year ended
December 31, 1999)
3.2 Bylaws of PrimeEnergy Corporation. (Incorporated herein by
reference to Exhibit 3.2 of PrimeEnergy Corporation Form
10-KSB for the year ended December 31, 1999)
10.3 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)
15
10.17 Amended Marketing Agreement between PrimeEnergy Management
Corporation and Charles E. Drimal, Jr. (Incorporated herein by
reference to Exhibit 10.17 of PrimeEnergy Corporation Form 10-KSB
for the year ended December 31, 1994)(1)
10.18 Composite copy of Non-Statutory Option Agreements (Incorporated
by reference to Exhibit 10.18 of PrimeEnergy Corporation for
10-KSB for the year ended December 31, 1997)(1)
10.22 Credit Agreement dated as of December 19, 2002, between
PrimeEnergy Corporation, PrimeEnergy Management Corporation,
Eastern Oil Well Service Company, Southwest Oilfield
Construction Company, EOWS Midland Company, and Guaranty Bank,
FSB (filed herewith)
10.23 Mortgage, Deed of Trust, Security Agreement, Financing Statement
and Assignment of Production from PrimeEnergy Corporation and
PrimeEnergy Management Corporation for the benefit of Guaranty
Bank, FSB (filed herewith)
10.24 Act of Mortgage and Security Agreement by PrimeEnergy Corporation
and PrimeEnergy Management Corporation to Guaranty Bank, FSB
(filed herewith)
21 Subsidiaries. (filed herewith)
23 Consent of Ryder Scott & Company L.P. (filed herewith)
99.1 Certification of Chief Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to section 906 of the
Sarbanes-Oxley Act of 2002 (filed herewith).
99.2 Certification of Chief Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to section 906 of the
Sarbanes-Oxley Act of 2002 (filed herewith).
(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.
- -----------
(1) Management contract or compensatory plan or arrangement required to be
filed as an Exhibit to this Form 10-K.
16
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, on the 31st day of
March, 2003.
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 31st day of March, 2003.
<Table>
/s/ CHARLES E. DRIMAL, JR. Director and President;
- -------------------------- The Principal Executive Officer
Charles E. Drimal, Jr.
/s/ BEVERLY A. CUMMINGS Director, Executive Vice President and Treasurer;
- -------------------------- The Principal Financial and Accounting Officer
Beverly A. Cummings
/s/ JAMES P. BOLDRICK Director /s/ CLINT HURT Director
- -------------------------- ------------------------
James P. Boldrick Clint Hurt
Director Director
- -------------------------- ------------------------
Samuel R. Campbell Robert de Rothschild
/s/ JAMES E. CLARK Director Director
- -------------------------- ------------------------
James E. Clark Jarvis K. Slade
/s/ MATTHIAS ECKENSTEIN Director /s/ JAN K. SMEETS Director
- -------------------------- ------------------------
Matthias Eckenstein Jan K. Smeets
/s/ H. GIFFORD FONG Director Director
- -------------------------- ------------------------
H. Gifford Fong Gaines Wehrle
Director Director
- -------------------------- ------------------------
Thomas S.T. Gimbel Michael Wehrle
</Table>
-17-
CERTIFICATION
I, Charles E. Drimal, Jr., certify that:
1. I have reviewed this annual report on Form 10-K of PrimeEnergy Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent
functions):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
March 31, 2003 /s/ Charles E. Drimal Jr.
-------------------------------------
Charles E. Drimal Jr
Chief Executive Officer
PrimeEnergy Management Corporation
Managing General Partner
CERTIFICATION
I, Beverly A. Cummings, certify that:
1. I have reviewed this annual report on Form 10-K of PrimeEnergy Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent
functions):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
March 31, 2003 /s/ Beverly A. Cummings
----------------------------------
Beverly A Cummings
Chief Financial Officer
PrimeEnergy Management Corporation
Managing General Partner
INDEX TO FINANCIAL STATEMENTS
<Table>
Financial Statements (Included herein at pages F-1 through F-26):
Report of Independent Public Accountants F-2
Financial Statements
Consolidated Balance Sheets -- December 31, 2002 and 2001 F-3
Consolidated Statements of Operations -- for the years ended December 31,
2002, 2001 and 2000 F-5
Consolidated Statements of Stockholders' Equity -- for the years ended
December 31, 2002, 2001 and 2000 F-6
Consolidated Statements of Cash Flows -- for the years ended December 31,
2002, 2001 and 2000 F-7
Notes to Consolidated Financial Statements F-8
Supplementary Information: F-20
Capitalized Costs Relating to Oil and Gas Producing Operations
December 31, 2002, 2001 and 2000 F-21
Costs Incurred in Oil and Gas Property Acquisition, Exploration and
Development Activities, years ended December 31, 2002, 2001 and 2000 F-21
Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas reserves, years ended December 31, 2002,
2001 and 2000 F-22
Standardized Measure of Discounted Future Net Cash Flows and Changes
Therein Relating to Proved Oil an Gas Reserves, years ended December 31,
2002, 2001 and 2000 F-23
Reserve Quantity Information, years ended December 31, 2002, 2001
and 2000 F-24
Results of Operations from Oil and Gas Producing Activities, years ended
December 31, 2002, 2001 and 2000 F-25
Notes to Supplementary Information F-26
</Table>
F-1
PUSTORINO, PUGLISI, & CO., LLP
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of
PrimeEnergy Corporation and Subsidiaries:
We have audited the accompanying consolidated balance sheets of PrimeEnergy
Corporation and Subsidiaries as of December 31, 2002 and 2001, and the related
consolidated statements of operations, stockholders' equity, and cash flows for
the years ended December 31, 2002, 2001, and 2000. 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 auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of PrimeEnergy Corporation and
Subsidiaries as of December 31, 2002 and 2001, and the results of its operations
and their cash flows for the years ended December 31, 2002, 2001 and 2000 in
conformity with accounting principles generally accepted in the United States of
America.
/s/ PUSTORINO, PUGLISI & CO., LLP
Pustorino, Puglisi & Co., LLP
New York, New York
March 28, 2003
F-2
PRIMEENERGY CORPORATION and SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, December 31, 2002 and 2001
<Table>
<Caption>
2002 2001
------------ ------------
ASSETS:
Current assets:
Cash and cash equivalents $ 1,886,000 $ 85,000
Restricted cash and cash equivalents (Note 12) 750,000 1,174,000
Accounts receivable, net (Note 3) 4,126,000 3,798,000
Due from related parties (less allowance for doubtful
accounts of $800,000 in 2002 and 2001) (Note 11) 4,771,000 4,924,000
Prepaid expenses 239,000 64,000
Other current assets (Notes 4 and 9) 322,000 1,006,000
Deferred income taxes (Notes 1 and 9) 309,000 274,000
------------ ------------
Total current assets 12,403,000 11,325,000
------------ ------------
Property and equipment, at cost (Notes 1 and 2):
Oil and gas properties(successful efforts method):
Proved 74,319,000 63,418,000
Unproved 1,134,000 286,000
Furniture, fixtures and equipment including leasehold
improvements 8,949,000 8,622,000
------------ ------------
84,402,000 72,326,000
Accumulated depreciation, depletion and amortization (52,102,000) (48,039,000)
------------ ------------
Net property and equipment 32,300,000 24,287,000
------------ ------------
Other assets 206,000 204,000
------------ ------------
Total assets $ 44,909,000 $ 35,816,000
============ ============
</Table>
The accompanying notes are an integral part of the
consolidated financial statements.
F-3
PRIMEENERGY CORPORATION and SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, December 31, 2002 and 2001
<Table>
<Caption>
2002 2001
------------ ------------
LIABILITIES and STOCKHOLDERS' EQUITY:
Current liabilities:
Accounts payable (Note 14) $ 6,100,000 $ 5,788,000
Current portion of other long-term obligations (Notes 5 and 6) 824,000 230,000
Accrued liabilities:
Payroll, Benefits, and Related Items 996,000 1,157,000
Interest and other 803,000 1,023,000
Due to related parties (Note 11) 1,485,000 983,000
------------ ------------
Total current liabilities 10,208,000 9,181,000
Long-term bank debt (Note 5) 23,700,000 16,950,000
Other long-term obligations (Note 6) 34,000 8,000
Deferred income taxes (Note 9) 2,592,000 2,314,000
------------ ------------
Total liabilities 36,534,000 28,453,000
------------ ------------
Stockholders' equity:
Preferred stock, $.10 par value, authorized 5,000,000 shares;
none issued -- --
Common stock, $.10 par value, authorized 10,000,000 shares;
issued 7,694,970 in 2002 and 2001 769,000 769,000
Paid in capital 11,024,000 11,024,000
Retained earnings 9,676,000 7,919,000
------------ ------------
21,469,000 19,712,000
Treasury stock, at cost 4,001,964 common shares in 2002
and 3,909,102 in 2001 (13,094,000) (12,349,000)
------------ ------------
Total stockholders' equity 8,375,000 7,363,000
------------ ------------
Total liabilities and equity $ 44,909,000 $ 35,816,000
============ ============
</Table>
The accompanying notes are an integral part of the
consolidated financial statements.
F-4
PRIMEENERGY CORPORATION and SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
for the years ended December 31, 2002, 2001 and 2000
<Table>
<Caption>
2002 2001 2000
------------ ------------ ------------
Revenue:
Oil and gas sales $ 18,330,000 $ 22,998,000 $ 23,223,000
District operating income 15,308,000 17,082,000 13,585,000
Administrative revenue (Note 11) 1,473,000 1,535,000 1,655,000
Reporting and management fees (Note 11) 275,000 297,000 321,000
Gains/(losses) on derivative instruments net (113,000) -- --
Interest income 52,000 138,000 169,000
Other income 609,000 358,000 229,000
------------ ------------ ------------
35,934,000 42,408,000 39,182,000
------------ ------------ ------------
Costs and expenses:
Lease operating expense 10,210,000 11,083,000 9,114,000
District operating expense 13,020,000 13,368,000 11,235,000
Depreciation and depletion of oil and gas properties 3,988,000 4,522,000 5,060,000
Impairment of oil and gas properties (Note 1) -- 753,000 295,000
General and administrative expense 4,888,000 4,310,000 4,033,000
Exploration costs 894,000 509,000 1,797,000
Interest expense (Note 5) 766,000 895,000 1,500,000
------------ ------------ ------------
33,766,000 35,440,000 33,034,000
------------ ------------ ------------
Income (loss) from operations 2,168,000 6,968,000 6,148,000
Other income:
Gain on sale and exchange of assets 32,000 166,000 28,000
------------ ------------ ------------
Income before provision for income taxes 2,200,000 7,134,000 6,176,000
Provision for income taxes (Notes 1 and 9) 443,000 1,721,000 811,000
------------ ------------ ------------
Net income $ 1,757,000 $ 5,413,000 $ 5,365,000
============ ============ ============
Basic net income per common share (Notes 1 and 15) $ 0.47 $ 1.39 $ 1.26
Diluted net income per common share (Notes 1 and 15)
$ 0.40 $ 1.18 $ 1.08
</Table>
The accompanying notes are an integral part of the
consolidated financial statements
F-5
PRIMEENERGY CORPORATION and SUBSIDIARIES
CONSOLIDATED STATEMENT of STOCKHOLDERS' EQUITY
for the years ended December 31, 2002, 2001 and 2000
<Table>
<Caption>
Retained
Additional Earnings
Common Stock Paid In (Accumulated Treasury
Shares Amount Capital Deficit) Stock Total
------------ ------------ ------------ ------------ ------------ ------------
Balance at December 31, 1999 7,607,970 $ 761,000 $ 10,902,000 $ (2,859,000) $ (7,870,000) $ 934,000
Purchased 222,879 shares of
common stock (1,323,000) (1,323,000)
Net income 5,365,000 5,365,000
------------ ------------ ------------ ------------ ------------ ------------
Balance at December 31, 2000 7,607,970 $ 761,000 $ 10,902,000 $ 2,506,000 $ (9,193,000) $ 4,976,000
Exercised stock options 87,000 8,000 122,000 130,000
Purchased 420,160 shares of
common stock (3,156,000) (3,156,000)
Net income 5,413,000 5,413,000
------------ ------------ ------------ ------------ ------------ ------------
Balance at December 31, 2001 7,694,970 $ 769,000 $ 11,024,000 $ 7,919,000 $(12,349,000) $ 7,363,000
Purchased 92,862 shares of
common stock (745,000) (745,000)
Net income 1,757,000 1,757,000
------------ ------------ ------------ ------------ ------------ ------------
Balance at December 31, 2002 7,694,970 $ 769,000 $ 11,024,000 $ 9,676,000 $(13,094,000) $ 8,375,000
============ ============ ============ ============ ============ ============
</Table>
The accompanying notes are an integral part of the
consolidated financial statements.
F-6
PRIMEENERGY CORPORATION and SUBSIDIARIES
CONSOLIDATED STATEMENTS of CASH FLOWS
for the years ended December 31, 2002, 2001 and 2000
<Table>
<Caption>
2002 2001 2000
------------ ------------ ------------
Cash flows from operating activities:
Net income (loss) $ 1,757,000 $ 5,413,000 $ 5,365,000
Adjustments to reconcile net loss to net cash
provided by operating activities:
Depreciation, depletion and amortization 5,231,000 5,599,000 6,000,000
Impairment of oil and gas properties -- 753,000 295,000
Dry hole and abandonment costs 894,000 496,000 1,787,000
Gain on sale of properties (32,000) (166,000) (28,000)
Provision (benefit) of deferred income taxes 243,000 1,684,000 356,000
Changes in assets and liabilities:
(Increase) decrease in accounts receivable (328,000) 1,865,000 (2,028,000)
(Increase) decrease in due from related parties 153,000 (578,000) (1,177,000)
(Increase) decrease in other assets 682,000 (874,000) 36,000
(Increase) decrease in prepaid expenses (175,000) 48,000 (28,000)
Increase (decrease) in accounts payable 736,000 (1,086,000) (346,000)
Increase (decrease) in accrued liabilities (19,000) (559,000) 944,000
Increase (decrease) in due to related parties 502,000 (282,000) 322,000
------------ ------------ ------------
Net cash provided by operating activities 9,644,000 12,313,000 11,498,000
------------ ------------ ------------
Cash flows from investing activities:
Proceeds from sale of properties and equipment 32,000 520,000 71,000
Additions to property and equipment (14,442,000) (8,527,000) (11,632,000)
Proceeds from payment on notes receivable 453,000
------------ ------------ ------------
Net cash used in investing activities (14,410,000) (8,007,000) (11,108,000)
Cash flows from financing activities:
Purchase of stock for treasury (745,000) (3,156,000) (1,323,000)
Repayment of long-term bank debt and other
long-term obligations (43,260,000) (40,619,000) (27,844,000)
Increase in long-term bank debt and other
long-term obligations 50,572,000 38,740,000 27,690,000
Proceeds from exercised stock options -- 130,000 --
------------ ------------ ------------
Net cash provided by (used in)
financing activities 6,567,000 (4,905,000) (1,477,000)
------------ ------------ ------------
Net increase (decrease) in cash 1,801,000 (599,000) (1,087,000)
Cash and cash equivalents, beginning of year 85,000 684,000 1,771,000
------------ ------------ ------------
Cash and cash equivalents, end of year $ 1,886,000 85,000 684,000
============ ============ ============
Supplemental disclosures:
Income taxes paid during the year -- 1,200,000 53,000
Net income tax refunds received during the year 745,000 -- --
Interest paid during the year 766,000 901,000 1,462,000
</Table>
Supplemental information of noncash investing and financing activities:
In 2002, the Company recorded capital lease obligations in the amount of
$59,000.
The accompanying notes are an integral part of the consolidated financial
statements.
F-7
PRIMEENERGY CORPORATION and SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
---------
1. DESCRIPTION OF OPERATIONS AND SIGNIFICANT ACCOUNTING 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
38 private and publicly-held limited partnerships and 2 trusts
(collectively, the "Partnerships"). PEC owns Eastern Oil Well Service
Company ("EOWSC"), EOWS Midland Company and Southwest Oilfield
Construction Company ("SOCC"), all of which perform oil and gas field
servicing. PEC also owns Prime Operating Company ("POC"), which serves
as operator for most of the producing oil and gas properties owned by
the Company and affiliated entities. Field service revenues and the
administrative overhead fees earned as operator are reported as
'District operating income' on the consolidated statement of
operations. PrimeEnergy Corporation and its wholly-owned subsidiaries
are herein referred to as the "Company."
The Company is engaged in the development, acquisition and production
of oil and natural gas properties. The Company owns leasehold, mineral
and royalty interests in producing and non-producing oil and gas
properties across the continental United States, including Colorado,
Kansas, Louisiana, Mississippi, Montana, Nebraska, New Mexico, North
Dakota, Oklahoma, Texas, Utah, West Virginia and Wyoming. The Company
operates 1,550 wells and owns non-operating interests in over 800
additional wells. Additionally, the Company provides well-servicing
support operations, site-preparation and construction services for oil
and gas drilling and re-working operations, both in connection with the
Company's activities and providing contract services for third parties.
The Company is publicly traded on the NASDAQ under the symbol "PNRG."
The markets for the Company's products are highly competitive, as oil
and gas are commodity products and prices depend upon numerous factors
beyond the control of the Company, such as economic, political and
regulatory developments and competition from alternative energy
sources.
Principles of Consolidation:
The consolidated financial statements include the accounts of
PrimeEnergy Corporation and its wholly-owned subsidiaries. All material
inter-company accounts and transactions between these entities have
been eliminated. Oil and gas properties include ownership interests in
the Partnerships. The statement of operations includes the Company's
proportionate share of revenue and expenses related to oil and gas
interests owned by the Partnerships.
Use of Estimates:
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ
from those estimates.
Estimates of oil and gas reserves, as determined by independent
petroleum engineers, are continually subject to revision based on
price, production history and other factors. Depletion expense, which
is computed based on the units of production method, could be
significantly impacted by changes in such estimates. Additionally, FAS
144 requires that if the expected future cash flow from an asset is
less than its carrying cost, that asset must be written down to its
fair market value. As the fair market value of an oil and gas property
will usually be significantly less than the total future net revenue
expected from that property, small changes in the estimated future net
revenue from an asset could lead to the necessity of recording a
significant impairment of that asset.
F-8
PRIMEENERGY CORPORATION and SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
---------
Property and Equipment
The Company follows the "successful efforts" method of accounting for
its oil and gas properties. Under the successful efforts method, costs
of acquiring undeveloped oil and gas leasehold acreage, including lease
bonuses, brokers' fees and other related costs are capitalized.
Provisions for impairment of undeveloped oil and gas leases are based
on periodic evaluations. Annual lease rentals and exploration expenses,
including geological and geophysical expenses and exploratory dry hole
costs, are charged against income as incurred. Costs of drilling and
equipping productive wells, including development dry holes and related
production facilities, are capitalized. Costs incurred by the Company
related to the exploration, development and acquisition of oil and gas
properties on behalf of the Partnerships or joint ventures are deferred
and charged to the related entity upon the completion of the
acquisition. To the extent that the Company acquires an interest in the
property, an appropriate allocation of internal costs are capitalized
as part of the depletable base of the property.
All other property and equipment are carried at cost. Depreciation and
depletion of oil and gas production equipment and properties are
determined under the unit-of-production method based on estimated
proved recoverable oil and gas reserves. Depreciation of all other
equipment is determined under the straight-line method using various
rates based on useful lives. The cost of assets and related accumulated
depreciation is removed from the accounts when such assets are disposed
of, and any related gains or losses are reflected in current earnings.
Income Taxes:
The Company records income taxes in accordance with Statement of
Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income
Taxes." SFAS No. 109 is an asset and liability approach to accounting
for income taxes, which requires the recognition of deferred tax assets
and liabilities for the expected future tax consequences of events that
have been recognized in the Company's financial statements or tax
returns.
Deferred tax liabilities or assets are established for temporary
differences between financial and tax reporting bases and are
subsequently adjusted to reflect changes in the rates expected to be in
effect when the temporary differences reverse. A valuation allowance is
established for any deferred tax asset for which realization is not
likely.
General and Administrative Expenses:
General and administrative expenses represent costs and expenses
associated with the operation of the Company. Certain of the
Partnerships sponsored by the Company reimburse general and
administrative expenses incurred on their behalf.
Income Per Common Share:
Income per share of common stock has been computed based on the
weighted average number of common shares outstanding during the
respective periods in accordance with SFAS No. 128, "Earnings per
Share".
Statements of cash flows:
For purposes of the consolidated statements of cash flows, the Company
considers short-term, highly liquid investments with original
maturities of less than ninety days to be cash equivalents.
F-9
PRIMEENERGY CORPORATION and SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
---------
Concentration of Credit Risk:
The Company maintains significant banking relationships with financial
institutions in the State of Texas. The Company limits its risk by
periodically evaluating the relative credit standing of these financial
institutions. The Company's oil and gas production purchasers consist
primarily of independent marketers and major gas pipeline companies.
Hedging:
The Company periodically enters into oil and gas financial instruments
to manage its exposure to oil and gas price volatility. The oil and gas
reference prices upon which the price hedging instruments are based
reflect various market indices that have a high degree of historical
correlation with actual prices received by the Company.
The financial instruments are accounted for in accordance with
Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities", which established new
accounting and reporting requirements for derivative instruments and
hedging activities. SFAS No. 133, as amended by SFAS No. 138, requires
that all derivative instruments subject to the requirements of the
statement be measured at fair market value and recognized as assets or
liabilities in the balance sheet. The accounting for changes in the
fair value of a derivative depends on the intended use of the
derivative and the resulting designation is generally established at
the inception of a derivative. For derivatives designated as cash flow
hedges and meeting the effectiveness guidelines of SFAS No. 133,
changes in fair value, to the extent effective, are recognized in other
comprehensive income until the hedged item is recognized in earnings.
Hedge effectiveness is measured at least quarterly based on the
relative changes in fair value between the derivative contract and the
hedged item over time. Any change in fair value of a derivative
resulting from ineffectiveness or an excluded component of the
gain/loss is recognized immediately in the statement of operations.
Recently Issued Accounting Standards:
In December 1999, the Securities and Exchange Commission issued Staff
Accounting Bulletin No. 101, Revenue Recognition in Financial
Statements ("SAB No. 101"). SAB No. 101 provides guidance for revenue
recognition under certain circumstances. The adoption of SAB 101 in
2000 did not have a significant impact on the Company's financial
position, results of operations or cash flows.
In July 2001, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 141, "Business Combinations." SFAS No. 141 is intended to
improve the transparency of the accounting and reporting for business
combinations by requiring that all business combinations be accounted
for under a single method - the purchase method. SFAS 141 is effective
for all transactions completed after June 30, 2001, except transactions
using the pooling-of-interests method that were initiated prior to July
1, 2001. The adoption of SFAS 141 did not have an impact on the
Company's consolidated financial statements.
In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other
Intangible Assets." This statement applies to intangibles and goodwill
acquired after June 30, 2001, as well as goodwill and intangibles
previously acquired. Under this statement, goodwill as well as other
intangibles determined to have an infinite life will no longer be
amortized; however, these assets will be reviewed for impairment on a
periodic basis. The adoption of SFAS 142 did not have an impact on the
Company's consolidated financial statements.
In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 requires the fair value of a
liability for an asset retirement obligation to be recognized in the
period in which it is incurred if a reasonable estimate of fair value
can be made. The associated asset retirement costs are capitalized as
part of the carrying amount of the long-lived asset. SFAS No. 143 is
effective for fiscal years beginning after June 15, 2002. Management
has not yet determined the impact of the adoption of this statement.
F-10
PRIMEENERGY CORPORATION and SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
---------
In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 requires
that long-lived assets be measured at the lower of carrying amount or
fair value less cost to sell, whether reported in continuing operations
or in discontinued operations. Therefore, discontinued operations will
no longer be measured at net realizable value or include amounts for
operating losses that have not yet occurred. SFAS No. 144 is effective
for financial statements issued for fiscal years beginning after
December 15, 2001 and generally, is to be applied prospectively. The
adoption of SFAS 144 did not have an impact on the Company's
consolidated financial statements.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and
Technical Corrections." Prior to the adoption of the provisions of SFAS
No. 145, generally accepted accounting principles required gains or
losses on the early extinguishment of debt be classified in a company's
periodic consolidated statements of operations as extraordinary gains
or losses, net of associated income taxes, below the determination of
income or loss from continuing operations. SFAS No. 145 changes
generally accepted accounting principles to require, except in the case
of events or transactions of a highly unusual and infrequent nature,
gains or losses from the early extinguishment of debt be classified as
components of a company's income or loss from continuing operations.
The adoption of the provisions of SFAS No. 145 in 2003 is not expected
to affect the Company's financial position or results of operations.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS No. 146 requires
that a liability for a cost associated with an exit or disposal
activity be recognized and measured initially at fair value only when
the liability is incurred. SFAS No. 146 is effective for exit or
disposal activities that are initiated after December 31, 2002. The
adoption of SFAS No. 146 in 2003 is not expected to have an effect on
the Company's financial position or results of operations.
In November 2002, the FASB issued Financial Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees,
including Indirect Guarantee of Indebtedness of Others" (FIN 45). FIN
45 requires that upon issuance of a guarantee, the guarantor must
recognize a liability for the fair value of the obligation it assumes
under that guarantee. FIN 45's provisions for initial recognition and
measurement should be applied on a prospective basis to guarantees
issued or modified after December 31, 2002. The guarantor's previous
accounting for guarantees that were issued before the date of FIN 45's
initial application may not be revised or restated to reflect the
effect of the recognition and measurement provisions of the
Interpretation. The disclosure requirements are effective for financial
statements of both interim and annual periods that end after December
15, 2002. The adoption of FIN 45 did not have an impact on the
Company's consolidated financial statements.
In December 2002, the FASB issued SFAS 148, "Accounting for Stock-Based
Compensation--Transition and Disclosure." SFAS No. 148 amends FASB
Statement No. 123, "Accounting for Stock-Based Compensation" to provide
alternative methods of transition for a voluntary change to the fair
value based method of accounting for stock-based employee compensation.
In addition, this Statement amends the disclosure for stock-based
employee compensation and the effect of the method used on the reported
results. The provisions of SFAS 148 are effective for financial
statements with fiscal years ending after December 15, 2002. The
adoption of this statement did not impact the Company's financial
position or results of operations.
In January 2003, the FASB issued Financial Interpretation No. 46,
"Consolidation of Variable Interest Entities--an interpretation of ARB
No. 51" (FIN 46). FIN 46 is an interpretation of Accounting Research
Bulletin 51, "Consolidated Financial Statements", and addresses
consolidation by business enterprises of variable interest entities
(VIE's). The primary objective of FIN 46 is to provide guidance on the
identification of, and financial reporting for, entities over which
control is achieved through means other than voting rights; such
entities are known as VIE's. FIN 46 requires an enterprise to
consolidate a variable interest entity if that enterprise has a
variable interest that will absorb a majority of the entity's expected
losses if they occur, receive a majority of the entity's expected
residual return if they occur, or both. An enterprise shall consider
the rights and obligations conveyed by its variable interests in making
this determination. This guidance applies immediately to variable
interest entities created after January 31, 2003, and to variable
interest entities in which an enterprise obtains an interest after that
date. It applies in the first fiscal
F-11
PRIMEENERGY CORPORATION and SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
---------
year or interim period beginning after June 15, 2003, to variable
interest entities in which an enterprise holds a variable interest that
it acquired before February 1, 2003. The adoption of this
interpretation is not expected to have an effect on the Company's
financial position or results of operations.
2. SIGNIFICANT ACQUISITIONS AND DISPOSITIONS
2002
As more fully described in Note 7, the Company is committed to offer to
repurchase the interests of the partners and trust unit holders in
certain of the Partnerships. During 2002, the Company purchased such
interests in an amount totaling $1,203,500.
2001
As more fully described in Note 7, the Company is committed to offer to
repurchase the interests of the partners and trust unit holders in
certain of the Partnerships. During 2001, the Company purchased such
interests in an amount totaling $545,000.
2000
Effective January 1, 2000, the Company purchased additional interests
in the San Pedro Ranch field of Dimmit and Maverick Counties, Texas for
$150,000.
Effective April 1, 2000, the Company purchased additional interest in
the Eola Robberson field of Garvin County, Oklahoma for $400,000. These
interests are related to certain contingency payments created at the
time the Company made its original acquisition of the field in 1988,
and are based on property performance.
Effective July 1, 2000, the Company invested $265,000 in the purchase
of various interests in five leases located in Garvin County, Oklahoma.
These leases contain 26 producing wells and 5 salt-water injection
wells. The Company assumed operation of the wells, which at the time of
the acquisition were collectively producing 61 (26.63 net) barrels of
oil per day.
In September of 2000, the Company purchased nine wells in Upton Co.
Texas. In October, the Company began a series of workovers to tap
additional oil and gas behind pipe reserves in the wells. Through
March, 2001 the Company has performed workovers on five of the nine
wells, resulting in a three fold increase in oil production and over a
six fold increase in gas production. Currently the acquisition is
producing at a rate of 55 (39 net) barrels of oil per day and 250 (177
net) Mcf of gas per day. The Company owns from 94% to 100% working
interest and 69% to 73% net revenue interest in the properties.
As more fully described in Note 7, the Company is committed to offer to
repurchase the interests of the partners and trust unitholders in
certain of the Partnerships. During 2000, the Company purchased such
interests in an amount totaling $1,257,000.
3. ACCOUNTS RECEIVABLE
Accounts receivable at December 31, 2002 and 2001 consisted of the
following:
<Table>
<Caption>
December 31,
----------------------------
2002 2001
------------ ------------
Joint interest billing $ 571,000 $ 1,372,000
Trade receivables 1,243,000 1,151,000
Oil and gas sales 2,070,000 1,460,000
Other 561,000 154,000
------------ ------------
4,445,000 4,137,000
Less, allowance for doubtful accounts (319,000) (339,000)
------------ ------------
Total $ 4,126,000 $ 3,798,000
============ ============
</Table>
F-12
PRIMEENERGY CORPORATION and SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
---------
4. OTHER CURRENT ASSETS
Other current assets at December 31, 2002 and 2001 consisted of the
following:
<Table>
<Caption>
December 31,
---------------------------
2002 2001
------------ ------------
Tax overpayments $ 73,000 $ 708,000
Field service inventory 249,000 268,000
Other 0 30,000
------------ ------------
Total $ 322,000 $ 1,006,000
============ ============
</Table>
5. LONG-TERM BANK DEBT
As of December 2002, the Company entered in to a credit agreement with
a new primary lender. The Company and the lender agreed to amend and
restate in its entirety the credit agreement dated April 26, 1995
between the Company and its predecessor lender. This agreement will
continue to provide for borrowings under a Master Note. Advances under
the agreement, as amended, are limited to the borrowing base as defined
in the agreement. The borrowing base is re-determined by the lender on
a semi-annual basis. The current borrowing base is $25 million and
includes a Term Loan of $4 million. The Term Loan will be paid back in
monthly installments of $66,667 beginning January 2003 and continuing
until December 19, 2004 when such Term Loan shall be paid in full. The
credit agreement provides for interest on outstanding borrowings at the
bank's base rate, as defined, payable monthly, or at rates 2% over the
London Inter-Bank Offered Rate (LIBO rate) payable at the end of the
applicable interest period.
The Company had been party to a series of credit agreements with its
former lender or its predecessors since 1983. The agreement, entered
into in April 1995, provided for borrowings under a Master Note.
Advances under the agreement, as amended, were limited to the borrowing
base as defined in the agreement and re-determined by the lender on a
semi-annual basis. Since the beginning of 2000, the borrowing base
ranged from $20 million to $23.7 million. The credit agreement provided
for interest on outstanding borrowings at the bank's base rate, as
defined, payable monthly, or at rates ranging from 1 1/2% to 2% over
the London Inter-Bank Offered Rate (LIBO rate) depending upon the
Company's utilization of the available line of credit, payable at the
end of the applicable interest period. This credit agreement was
assigned to the Company's primary lender effective December 2002.
The average interest rates paid on outstanding borrowings subject to
interest at the bank's base rate during 2002 and 2001 were 4.25% and
6.92%, respectively. During the same periods, the average rates paid on
outstanding borrowings bearing interest based upon the LIBO rate were
3.59% and 5.98% As of December 31, 2002 and 2001, the total outstanding
borrowings were $24,500,000 and $16,950,000, respectively, with an
additional $500,000 and $6,050,000 available. As of December 31, 2001
$14,950,000 of the amounts outstanding accrued interest at the LIBO
rate option.
The Company's oil and gas properties as well as certain receivables and
equipment are pledged as security under the loan agreement. The
agreement requires the Company to maintain, as defined, a minimum
current ratio, tangible net worth, debt coverage ratio and interest
coverage ratio, and restrictions are placed on the payment of dividends
and the amount of treasury stock the Company may purchase.
6. COMMITMENTS
Operating Leases:
The Company has several noncancelable operating leases, primarily for
rental of office space, that have a term of more than one year.
F-13
PRIMEENERGY CORPORATION and SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
6. COMMITMENTS CONTINUED
Capital Leases:
The Company has two capital lease for office equipment in other
long-term obligations. Future minimum lease payments under operating
and capital leases are as follows:
<Table>
<Caption>
Operating Capital
Leases Leases
------------ ------------
2003 434,000 26,000
2004 83,000 24,000
2005 5,000 11,000
2006 -- --
Thereafter -- --
------------ ------------
Total minimum payments $ 522,000 61,000
============
Less imputed interest (3,000)
------------
Present value of minimum
Lease payments $ 58,000
============
</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 percent of the
revenues received by it from such partnership in the previous year.
Purchase prices are based upon annual reserve reports of independent
petroleum engineering firms discounted by a risk factor. Based upon
historical production rates and prices, management estimates that if
all such offers were to be accepted, the maximum annual future purchase
commitment would be approximately $500,000.
The Company owns approximately a 27% interest in a limited partnership
which owns a shopping center in Alabama. The Company is a guarantor on
a mortgage secured by the shopping center. The Company believes the
cash flow from the center is sufficient to service the mortgage. The
market value of the center is currently substantially higher than the
balance owed on the mortgage. If the partnership were unable to pay its
obligations under the mortgage agreement, the maximum amount the
Company is committed to pay is $350,000.
F-14
PRIMEENERGY CORPORATION and SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS,
---------
8. STOCK OPTIONS AND OTHER COMPENSATION
In May 1989, non-statutory stock options were granted by the Company to
four key executive officers for the purchase of shares of common stock.
At December 31, 2001 and 2000, options on 767,500 shares were
outstanding and exercisable at prices ranging from $1.00 to $1.25.
On January 27, 1983, the Company adopted the 1983 Incentive Stock
Option Plan. At December 31, 2000, options on 87,000 shares were
exercisable at $1.50 per share. During July 2001, all outstanding
options under this plan were exercised.
PEMC has a marketing agreement with its current President to provide
assistance and advice to PEMC in connection with the organization and
marketing of oil and gas partnerships and joint ventures and other
investment vehicles of which PEMC is to serve as general or managing
partner. The Company had a similar agreement with its former Chairman.
Although that agreement expired, the former Chairman was still entitled
to receive certain payments relating to partnerships formed during the
time the agreement was in effect. In October 2002, the President and
the former Chairman sold and assigned all rights, title and interest
related to certain Partnerships formed under these marketing agreements
to the Company. The President is still entitled to a percentage of the
Company's carried interest depending on total capital raised and annual
performance of other Partnerships and joint ventures.
9. INCOME TAXES
The components of the provision for income taxes for the years ended
December 31, 2002, 2001 and 2000 are as follows:
<Table>
<Caption>
2002 2001 2000
------------ ------------ ------------
Federal:
Current $ 95,000 $ 25,000 $ 201,000
Deferred 216,000 1,500,000 141,000
State:
Current 104,000 13,000 254,000
Deferred 28,000 183,000 215,000
------------ ------------ ------------
Total $ 443,000 $ 1,721,000 $ 811,000
============ ============ ============
</Table>
F-15
PRIMEENERGY CORPORATION and SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued
---------
The components of net deferred tax assets (liabilities) are as follows:
<Table>
<Caption>
December 31, December 31,
2002 2001
------------ ------------
Current assets:
Compensation and benefits $ 184,000 $ 185,000
Allowance for doubtful accounts 125,000 89,000
------------ ------------
309,000 274,000
------------ ------------
Noncurrent assets:
Depreciation 485,000 387,000
Due from related parties reserve 312,000 312,000
Federal net operating loss carryforwards -- 124,000
Percentage depletion carryforwards 297,000 367,000
Alternative minimum tax credits 1,040,000 943,000
------------ ------------
2,134,000 2,133,000
------------ ------------
Noncurrent liabilities:
Basis differences relating to limited partnerships 1,211,000 1,798,000
Depletion 3,515,000 2,649,000
------------ ------------
4,726,000 4,447,000
------------ ------------
Net deferred tax liabilities: $ 2,283,000 $ 2,040,000
============ ============
</Table>
The total provision for income taxes for the years ended December 31, 2002, 2001
and 2000 varies from the federal statutory tax rate as a result of the
following:
<Table>
<Caption>
December 31, December 31, December 31,
2002 2001 2000
------------ ------------ ------------
Expected tax expense $ 748,000 $ 2,426,000 $ 2,100,000
State income tax, net of federal benefit 132,000 196,000 469,000
Benefit from net operating losses and other
carryforwards previously reserved against -- -- (1,670,000)
Credit for producing fuel from a
non-conventional source (134,000) (299,000) (88,000)
Percentage depletion (303,000) (602,000) --
------------ ------------ ------------
Tax expense $ 443,000 $ 1,721,000 $ 811,000
============ ============ ============
</Table>
F-16
PRIMEENERGY CORPORATION and SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued
---------
In both 1998 and 1999 the Company had large federal net operating
losses. The value of these loss carryforwards was fully reserved
against due to the uncertainty as to whether the Company would have
future net income against which these losses could be offset. The use
of these previously reserved against carryforwards were the primary
reason for the low federal rate in the 2000 tax year.
The Company will utilize the $366,000 of net operating loss
carryforwards for both regular and alternate minimum tax purposes in
2002. All of the Company's net operating losses will be used or have
expired as of December 31, 2002.
In 2002 the Company generated approximately $380,000 in federal tax
credits for producing fuel from a non-conventional source. These
credits may be used to reduce the regular tax, but not the alternative
minimum tax liability of the taxpayer. To the extent they cannot be
utilized due to the alternative minimum tax, they become part of the
Company's alternative minimum tax credit carryforward. Under current
law the credit for producing fuel from a non conventional source will
no longer be allowed after 2002.
The Company has percentage depletion carryforwards of approximately
$760,000 for regular tax purposes. The Company has approximately
$1,040,,000 in alternative minimum tax credit carryforwards. Both the
percentage depletion deductions and the alternative minimum tax credits
may be carried forward indefinitely for tax purposes.
10. SEGMENT INFORMATION AND MAJOR CUSTOMERS
The Company operates in one industry - oil and gas exploration,
development, operation and servicing. The Company's oil and gas
activities are entirely in the continental United States.
The Company sells its oil and gas production to a number of purchasers.
Listed below are the percent of the Company's total oil and gas sales
made to each of the customers whose purchases represented more than 10%
of the Company's oil and gas sales in the year 2002.
Texon Distributing L.P. 18.6%
Unimark LLC 20.1%
Plains All American, Inc. 10.1%
Although there are no long-term oil and gas purchasing agreements with
these purchasers, the Company believes that they will continue to
purchase its oil and gas products and, if not, could be replaced by
other purchasers.
11. RELATED PARTY TRANSACTIONS
PEMC is a general partner in several oil and gas Partnerships in which
certain directors have limited and general partnership interests. As
the managing general partner in each of the Partnerships, PEMC receives
approximately 5% to 15% of the net revenues of each Partnership as a
carried interest in the Partnerships' properties.
The Partnership agreements allow PEMC to receive management fees for
various services to the Partnerships as well as a reimbursement for
property acquisition and development costs incurred on behalf of the
Partnerships and general and administrative overhead, which is reported
in the statements of operations as administrative revenue.
Due to related parties at December 31, 2002 and 2001 primarily
represent receipts collected by the Company, as agent, from oil and gas
sales net of expenses. The amount of such receipts due the
F-17
PRIMEENERGY CORPORATION and SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued
---------
affiliated Partnerships was $1,485,000 and $983,000 at December 31,
2002 and 2001, respectively. Receivables from related parties consist
of reimbursable general and administrative costs, lease operating
expenses and reimbursements for property acquisitions, development, and
related costs.
Treasury stock purchases in 2002 and 2001 included shares acquired from
related parties. Purchases from related parties include a total of
49,267 shares purchased for a total consideration of $394,000 in 2002,
and 228,800 shares purchased for a total consideration of $1,676,000 in
2001.
12. RESTRICTED CASH AND CASH EQUIVALENTS
Restricted cash and cash equivalents includes $750,000 and $1,174,000
at December 31, 2002 and 2001, respectively, of cash primarily
pertaining to unclaimed royalty payments. There were corresponding
accounts payable recorded at December 31, 2002 and 2001 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 $261,000 and $255,000 in 2002 and 2001, respectively.
14. ACCOUNTS PAYABLE
A summary of accounts payable at December 31, 2002 and 2001 is as
follows:
<Table>
<Caption>
2002 2001
------------ ------------
Payables to unaffiliated interests $ 5,816,000 $ 5,743,000
Other 284,000 45,000
------------ ------------
$ 6,100,000 $ 5,788,000
============ ============
</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 December 31, 2002
----------------------------------------------
Number of Per share
Net Income Shares Amount
------------ ------------ ------------
Net income per common share $ 1,757,000 3,738,753 $ 0.47
Effect of dilutive securities:
Options 666,839
------------ ------------
Diluted net income per common share $ 1,757,000 4,405,592 $ 0.40
============ ============
</Table>
F-18
PRIMEENERGY CORPORATION and SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued
---------
<Table>
<Caption>
Year ended December 31, 2001
----------------------------------------------
Number of Per share
Net Income Shares Amount
------------ ------------ ------------
Net income per common share $ 5,413,000 3,882,721 $ 1.39
Effect of dilutive securities:
Options 709,384
------------ ------------ ------------
Diluted net income per common share $ 5,413,000 4,592,105 $ 1.18
============ ============ ============
</Table>
<Table>
<Caption>
Year ended December 31, 2000
----------------------------------------------
Number of Per share
Net Income Shares Amount
------------ ------------ ------------
Net income per common share $ 5,365,000 4,266,186 $ 1.26
Effect of dilutive securities:
Options 686,057
------------ ------------ ------------
Diluted net income per common share $ 5,365,000 4,952,243 $ 1.08
============ ============ ============
</Table>
16. SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
<Table>
<Caption>
December 31, Fourth Third Second First
2002 Quarter Quarter Quarter Quarter
------------- ------------- ------------- ------------- -------------
Revenue $ 35,934,000 $ 9,764,000 9,580,000 8,434,000 8,155,000
Operating income 2,168,000 752,000 795 ,000 593,000 85,000
Net income 1,757,000 585,000 642,000 475,000 70,000
Net income per common share $ 0.47 $ 0.16 $ 0.17 $ 0.13 $ 0.02
Diluted net income per
common share $ 0.40 $ 0.13 $ 0.15 $ 0.11 $ 0.02
</Table>
<Table>
<Caption>
December 31, Fourth Third Second First
2001 Quarter Quarter Quarter Quarter
------------ ------------ ------------ ------------ ------------
Revenue $ 42,408,000 $ 8,880,000 $ 10,103,000 $ 11,113,000 $ 12,312,000
Operating income 6,968,000 (67,000) 1,002,000 2,277,000 3,756,000
Net income 5,413,000 207,000 630,000 1,571,000 3,005,000
Net income per common share $ 1.39 $ .06 $ .16 $ .41 $ .76
Diluted net income per share $ 1.18 $ .06 $ .14 $ .34 $ .64
</Table>
F-19
PRIMEENERGY CORPORATION AND SUBSIDIARIES
SUPPLEMENTARY INFORMATION
-----
(UNAUDITED)
F-20
PRIMEENERGY CORPORATION and SUBSIDIARIES
CAPITALIZED COSTS RELATING to OIL and GAS PRODUCING ACTIVITIES
December 31, 2002, 2001 and 2000
---------
(Unaudited)
<Table>
<Caption>
2002 2001 2000
----------- ----------- -----------
Developed oil and gas properties $74,319,000 $63,418,000 $57,439,000
Undeveloped oil and gas properties 1,134,000 286,000 159,000
----------- ----------- -----------
75,453,000 63,704,000 57,598,000
Accumulated depreciation, depletion and
valuation allowance 46,912,000 42,924,000 37,686,000
----------- ----------- -----------
Net capitalized costs $28,541,000 $20,780,000 $19,912,000
=========== =========== ===========
</Table>
COSTS INCURRED in OIL and GAS PROPERTY ACQUISITION,
EXPLORATION and DEVELOPMENT ACTIVITIES
Years ended December 31, 2001, 2000 and 1999
---------
(Unaudited)
<Table>
<Caption>
2002 2001 2000
------------ ------------ ------------
Acquisition of Properties:
Developed $ 1,668,000 $ 316,000 $ 4,679,000
Undeveloped 848,000 164,000 106,000
Exploration Costs 894,000 509,000 1,797,000
Development Costs 8,385,000 5,661,000 3,351,000
</Table>
See accompanying notes to supplementary information.
F-21
PRIMEENERGY CORPORATION and SUBSIDIARIES
STANDARDIZED MEASURE of DISCOUNTED FUTURE
NET CASH FLOWS RELATING to PROVED OIL and GAS RESERVES
Years ended December 31, 2002, 2001 and 2000
---------
(Unaudited)
<Table>
<Caption>
2002 2001 2000
------------- ------------ ------------
Future cash inflows $ 201,750,000 $102,916,000 $ 315,680,000
Future production and development costs (104,232,000) (60,841,000) (116,417,000)
Future income tax expenses (24,230,000) (7,930,000) (59,914,000)
------------- ----------- ------------
Future net cash flows 73,288,000 34,145,000 139,349,000
10% annual discount for estimated timing of cash flow (30,512,000) (13,179,000) (59,339,000)
------------ ------------ ------------
Standardized measure of discounted future net cash flows $ 42,776,000 $ 20,966,000 $ 80,010,000
============ ============ ============
</Table>
See accompanying notes to supplementary information.
F-22
PRIMEENERGY CORPORATION and SUBSIDIARIES
STANDARDIZED MEASURE of DISCOUNTED FUTURE
NET CASH FLOWS and CHANGES THEREIN RELATING
to PROVED OIL and GAS RESERVES
Years ended December 31, 2002, 2001 and 2000
---------
(Unaudited)
The following are the principal sources of change in the standardized measure of
discounted future net cash flows during 2002, 2001 and 2000:
<Table>
<Caption>
2002 2001 2000
------------- ------------- -------------
Sales of oil and gas produced, net of production costs (8,120,000) (11,915,000) $ (14,109,000)
Net changes in prices and production costs 18,488,000 (92,118,000) 69,822,000
Extensions, discoveries and improved recovery 8,462,000 3,335,000 13,705,000
Revisions of previous quantity estimates 5,192,000 422,000 3,577,000
Reserves purchased, net of development costs 5,824,000 1,082,000 11,698,000
Net change in development costs (311,000) (594,000) (99,000)
Accretion of discount 2,097,000 8,001,000 2,386,000
Net change in income taxes (9,809,000) 33,127,000 (30,779,000)
Other (13,000) (384,000) (51,000)
------------ ------------- -------------
Net change 21,810,000 (59,044,000) 56,150,000
Standardized measure of discounted future net cash flow:
Beginning of year 20,966,000 80,010,000 23,860,000
------------ ------------- -------------
End of year $ 42,776,000 20,966,000 80,010,000
============ ============= =============
</Table>
See accompanying notes to supplementary information
F-23
PRIMEENERGY CORPORATION and SUBSIDIARIES
RESERVE QUANTITY INFORMATION
Years ended December 31, 2002, 2001 and 2000
---------
(Unaudited)
<Table>
<Caption>
2002 2002 2001 2001 2000 2000
------------ ------------ ------------ ------------ ------------ ------------
Gas Oil Gas Oil Gas Oil
(Mcf) (bbls.) (Mcf) (bbls.) (Mcf) (bbls.)
----------- ----------- ------------ ------------ ------------ ------------
Proved developed and
undeveloped reserves:
Beginning of year 24,719,000 1,996,000 27,029,000 2,362,000 22,202,000 2,110,000
Extensions, discoveries
and improved recovery 3,011,000 273,000 2,764,000 136,000 1,961,000 13,000
Revisions of previous
estimates 2,798,000 198,000 (2,458,000) (307,000) 3,763,000 162,000
Purchases 2,929,000 173,000 1,148,000 111,000 3,034,000 375,000
Production (3,540,000) (321,000) (3,764,000) (306,000) (3,931,000) (298,000)
---------- ----------- ------------ ------------ ------------ ------------
End of year 29,917,000 2,319,000 24,719,000 1,996,000 27,029,000 2,362,000
========== =========== ============ ============ ============ ============
Proved developed reserves 29,917,000 2,319,000 24,226,000 1,996,000 27,029,000 2,362,000
========== =========== ============ ============ ============ ============
</Table>
See accompanying notes to supplementary information
F-24
PRIMEENERGY CORPORATION and SUBSIDIARIES
RESULTS of OPERATIONS from OIL and GAS PRODUCING ACTIVITIES
Years ended December 31, 2002, 2001 and 2000
---------
(Unaudited)
<Table>
<Caption>
2002 2001 2000
----------- ----------- -----------
Revenue:
Oil and gas sales $18,330,000 $22,998,000 $23,223,000
----------- ----------- -----------
Costs and expenses:
Lease operating expense 10,210,000 11,083,000 9,114,000
Exploration costs 894,000 509,000 1,717,000
Depreciation and depletion 3,988,000 4,544,000 5,060,000
Write down of oil and gas properties --- 753,000 295,000
Income tax expense 443,000 1,473,000 811,000
----------- ----------- -----------
15,535,000 18,362,000 16,997,000
----------- ----------- -----------
Results of operations from producing activities $ 2,735,000 $ 4,636,000 $ 6,226,000
(excluding corporate overhead and interest costs) =========== =========== ===========
</Table>
See accompanying notes to supplementary information
F-25
PRIMEENERGY CORPORATION and SUBSIDIARIES
NOTES to SUPPLEMENTARY INFORMATION
---------
(Unaudited)
1. PRESENTATION OF RESERVE DISCLOSURE INFORMATION
Reserve disclosure information is presented in accordance with the
provisions of Statement of Financial Accounting Standards No. 69 ("SFAS
69"), "Disclosures About Oil and Gas Producing Activities".
2. DETERMINATION OF PROVED RESERVES
The estimates of the Company's proved reserves were determined by an
independent petroleum engineer in accordance with the provisions of
SFAS 69. The estimates of proved reserves are inherently imprecise and
are continually subject to revision based on production history,
results of additional exploration and development and other factors.
Estimated future net revenues were computed by reserves, less estimated
future development and production costs based on current costs.
3. RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES
The results of operations from oil and gas producing activities were
prepared in accordance with the provisions of SFAS 69. General and
administrative expenses, interest costs and other unrelated costs are
not deducted in computing results of operations from oil and gas
activities.
4. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND
CHANGES THEREIN RELATING TO PROVED OIL AND GAS RESERVES
The standardized measure of discounted future net flows relating oil
and gas reserves and the changes of standardized measure of discounted
future net cash flows relating to proved oil and gas reserves were
prepared in accordance with the provisions of SFAS 69.
Future cash inflows are computed as described in Note 2 by applying
current prices to year-end quantities of proved reserves.
Future production and development costs are computed estimating the
expenditures to be incurred in developing and producing the oil and gas
reserves at year-end, based on year-end costs and assuming continuation
of existing economic conditions.
Future income tax expenses are calculated by applying the year-end U.S.
tax rate to future pre-tax cash inflows relating to proved oil and gas
reserves, less the tax basis of properties involved. Future income tax
expenses give effect to permanent differences and tax credits and
allowances relating to the proved oil and gas reserves.
Future net cash flows are discounted at a rate of 10% annually
(pursuant to SFAS 69) to derive the standardized measure of discounted
future net cash flows. This calculation does not necessarily represent
an estimate of fair market value or the present value of such cash
flows since future prices and costs can vary substantially from
year-end and the use of a 10% discount figure is arbitrary.
F-26
EXHIBIT INDEX
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
3.1 Restated Certificate of Incorporation of PrimeEnergy Corporation.
(Incorporated herein by reference to Exhibit 3.1 of PrimeEnergy
Corporation Form 10-KSB for the year ended December 31, 1999)
3.2 Bylaws of PrimeEnergy Corporation. (Incorporated herein by reference
to Exhibit 3.2 of PrimeEnergy Corporation Form 10-KSB for the year
ended December 31, 1999)
10.3 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)
10.17 Amended Marketing Agreement between PrimeEnergy Management
Corporation and Charles E. Drimal, Jr. (Incorporated herein by
reference to Exhibit 10.17 of PrimeEnergy Corporation Form 10-KSB
for the year ended December 31, 1994)(1)
10.18 Composite copy of Non-Statutory Option Agreements (Incorporated
by reference to Exhibit 10.18 of PrimeEnergy Corporation for
10-KSB for the year ended December 31, 1997)(1)
10.22 Credit Agreement dated as of December 19, 2002, between
PrimeEnergy Corporation, PrimeEnergy Management Corporation,
Eastern Oil Well Service Company, Southwest Oilfield
Construction Company, EOWS Midland Company, and Guaranty Bank,
FSB (filed herewith)
10.23 Mortgage, Deed of Trust, Security Agreement, Financing Statement
and Assignment of Production from PrimeEnergy Corporation and
PrimeEnergy Management Corporation for the benefit of Guaranty
Bank, FSB (filed herewith)
10.24 Act of Mortgage and Security Agreement by PrimeEnergy Corporation
and PrimeEnergy Management Corporation to Guaranty Bank, FSB
(filed herewith)
21 Subsidiaries. (filed herewith)
23 Consent of Ryder Scott & Company L.P. (filed herewith)
99.1 Certification of Chief Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to section 906 of the
Sarbanes-Oxley Act of 2002 (filed herewith).
99.2 Certification of Chief Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to section 906 of the
Sarbanes-Oxley Act of 2002 (filed herewith).
(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.
</Table>
- -----------
(1) Management contract or compensatory plan or arrangement required to be
filed as an Exhibit to this Form 10-K.