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UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
 FORM 10-K þ
    
    Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2003.
 o
    
    Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
 Commission file number 0-9408 PRIMA ENERGY CORPORATION  DELAWARE
(State or other jurisdiction of
incorporation or organization)
    
    84-1097578
(I.R.S. Employer Identification No.)
 1099 18th Street, Suite 400, Denver, Colorado 80202
(Address of principal executive offices) (Zip Code) (303) 297-2100
(Registrants telephone number, including area code) Securities registered pursuant to Section 12(b) of the ActNone Securities registered pursuant to Section 12(g) of the ActCommon Stock, $0.015 Par Value
(Title of Class) Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes x No o 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 the Form 10-K or any amendment to this
Form 10-K. o Indicate by checkmark whether the Registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).
Yes x No o The aggregate market value of the 9,221,894 shares of voting stock held by
non-affiliates of the Registrant, based upon the closing price of the common
stock on June 30, 2003 of $20.82 per share as reported on the Nasdaq National
Market, was $191,999,833. Shares of common stock held by each officer and
director and by each person who owns 10% or more of the outstanding common
stock have been excluded in that such persons may be deemed affiliates. This
determination of affiliate status is not necessarily a conclusive determination
for other purposes. As of February 27, 2004, Registrant had outstanding 12,964,142 shares of Common
Stock, $0.015 Par Value, its only class of voting stock. Document Incorporated by Reference Parts of the following document are incorporated by reference to Items 10, 11,
12, 13 and 14 of Part III of the Form 10-K Report: Definitive Proxy Statement
for the Registrants 2004 Annual Meeting of Stockholders.




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TABLE OF CONTENTS Item
    
    
    
    PagePART I1. and 2.
    
    BUSINESS and PROPERTIES
    
    
    3General  The Company
    
    
    3Strategy
    
    
    4Oil and Gas Properties and Operations
    
    
    6Oilfield Services
    
    
    17Other Properties
    
    
    17Competition
    
    
    18Regulation
    
    
    18Operating Hazards and Insurance
    
    
    21Employees and Offices
    
    
    21Available Information
    
    
    21Cautionary Statement for the Purposes of the Safe Harbor
Provisions of the Private Securities Litigation Reform Act of 1995
    
    
    213.
    
    LEGAL PROCEEDINGS
    
    
    244.
    
    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
    
    
    25PART II5.
    
    MARKET FOR THE REGISTRANTS COMMON STOCK AND RELATED
STOCKHOLDER MATTERS
    
    
    256.
    
    SELECTED FINANCIAL DATA
    
    
    267.
    
    MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
    
    
    27Critical Accounting Policies and Estimates
    
    
    27Liquidity and Capital Resources
    
    
    30Results of Operations
    
    
    32New Accounting Pronouncements
    
    
    387A.
    
    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK
    
    
    388.
    
    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
    
    
    409.
    
    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
    
    
    409A.
    
    CONTROLS AND PROCEDURES
    
    
    40PART III10.
    
    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT .
    
    
    4011.
    
    EXECUTIVE COMPENSATION
    
    
    4012.
    
    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS
    
    
    4013.
    
    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
    
    
    4014.
    
    PRINCIPAL ACCOUNTANT FEES AND SERVICES
    
    
    40PART IV15.
    
    EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K
    
    
    41Code of Ethics for Senior Financial OfficersSubsidiaries of the RegistrantIndependent Auditors ConsentIndependent Reservoir Engineers & GeologistsCertification of Chief Executive OfficerCertification of Chief Financial OfficerCertifications of CEO and CFO
  2




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PART I 
 ITEMS 1 and 2. BUSINESS and PROPERTIES References in this report to Prima, the Company, we, us or our are
intended to refer to Prima Energy Corporation and its consolidated
subsidiaries. This report contains numerous forward-looking statements that
are made pursuant to the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995. These include, without limitation, statements
relating to future drilling and completion of wells, well operations,
production, prices, costs and expenses, cash flow, investments, utilization of
oilfield service equipment, reserve estimates (including estimates for future
net revenues associated with such reserves and the present value of such future
net revenues), business strategies, and other plans and objectives of Prima
management for future operations and activities and other such matters. The
words, believes, plans, intends, estimates, projects, expects,
anticipates, strategy, budgeted and similar expressions, identify
forward-looking statements. Prima does not undertake to update, revise or correct any of the
forward-looking information. Readers are cautioned that such forward-looking
statements should be read in conjunction with Primas disclosures under the
heading: Cautionary Statement for the Purposes of the Safe Harbor Provisions
of the Private Securities Litigation Reform Act of 1995 beginning on page 21
of this report. 
 General  The Company Prima was incorporated in April 1980 to engage in crude oil and natural gas
related exploration, acquisition, development, production, and related business
activities. In October 1980, Prima became publicly owned with a $3.6 million
common stock offering. Our subsequent activities have primarily been related
to oil and gas
production operations, but have also included oil and gas property management,
oilfield services, and, at times, natural gas gathering, marketing and trading.
The substantial majority of Primas consolidated assets and revenues continue
to be related to its oil and gas production operations. Our principal activities are currently organized into two active operating
segments. The larger of these consists of the acquisition, exploration,
development and operation of oil and gas properties. The second segment is
comprised of oilfield service operations conducted for unaffiliated third
parties and for Prima. Though at times in the past we have also been involved
in oil and gas marketing and trading, and in gas gathering and compression
operations, these activities were not significant during the three years ended
December 31, 2003. See Note 7 of Notes to Consolidated Financial Statements
included as a part of Item 8 of this Report for financial information
pertaining to these industry segments. Our oil and gas exploration, development and production operations are
generally conducted within Prima Oil & Gas Company, a wholly owned subsidiary.
We conduct most other activities within wholly owned subsidiaries of Prima Oil
& Gas Company, including Action Oil Field Services, Inc. and Action Energy
Services for oilfield services. We have conducted our activities principally in the Rocky Mountain region of
the United States. At the end of 2003, Prima owned or controlled mineral
leasehold interests in over 510,000 gross, or 390,000 net, acres, predominately
in the Denver-Julesburg (D-J) Basin of Colorado, the Powder River, Wind
River, Big Horn and Green River Basins of Wyoming, and within the Wasatch
Plateau and Overthrust Belt in Utah. Historically, we have grown our proven oil and gas reserves and production
primarily through acquiring oil and gas leaseholds and drilling wells to
exploit and develop tight sand and coalbed methane (CBM) properties.
Generally, the probability that such properties have hydrocarbons in place is
estimated to be relatively high and the viability of establishing proved
reserves is largely dependent on several factors, including: the market price
for oil and gas; the costs of development, production and marketing; and
determination of the amount of recoverable reserves and the rate at which such
reserves can be extracted. To a lesser extent, we have added proved reserves
through exploration activities and acquisition of properties with proved
developed reserves. At the end of 2003, over 90% of our proved oil and gas
reserves and production were associated with tight sand properties in the D-J
Basin in eastern Colorado and CBM properties in the Powder River Basin in
eastern Wyoming. The balance of our proved reserves and production at the end
of 2003 related to properties in the Wind River Basin in central Wyoming and
non-CBM wells in the Powder River Basin. 3




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We have identified more than 2,800 potential exploitation and development
opportunities on our D-J Basin and Powder River Basin CBM-prospective acreage,
of which 485 were assigned proved oil and gas reserves at year-end 2003. Most
of the identified non-proved opportunities represent potential CBM drilling
locations in the Powder River Basin, with the remainder comprised primarily of
recompletion and refracturing projects and other drilling locations in the D-J Basin.
This set of identified opportunities includes only those projects
that we believe have the potential to be economically viable using future oil
and gas prices reflected in commodity futures markets at the end of 2003. We
have also developed an inventory of exploratory prospects in other areas,
including the Green River Basin in western Wyoming, the Overthrust Belt in
northeast Utah and the Uintah Basin in eastern Utah which could, if
successfully tested, establish new areas for future exploitation and
development activities. Our oilfield service operations are presently conducted in two areas where
Prima has an established base of exploitation and production operations. These
are the D-J Basin and the CBM play in the Powder River Basin. Action Oilfield
Services, which operates in the D-J Basin, owns various well servicing
equipment including eight workover rigs, a swab rig, tractor trailer rigs for
water hauling, and oilfield rental equipment, such as pumps, tanks and blowout
preventers. Action Energy Services, which operates in the Powder River Basin,
owns nine CBM drilling and service rigs. Our service companies provide
services to both Prima and other operators, and during 2003 operations provided
to unrelated parties generated approximately 12% of Primas total consolidated
revenues. While these operations have typically generated positive earnings and
cash flow, and have also enabled us to exert more control over costs and the
quality of work performed for some of our well operations, they have not
historically constituted a significant portion of Primas assets or operations. The following is a brief summary of selected key financial and operating data
reported by Prima at December 31, 2003:  
    
    $177,217,000 of assets.
    
    $56,148,000 of net working capital (with $57,192,000 of cash and marketable securities).
    
    No long-term debt.
    
    Estimated net proved reserves of 125,796,000 Mcf of natural gas equivalents (Mcfe), with a pre-tax
net present value using a 10% discount factor (PV10) of $239,800,000, based on constant year-end
average price realizations of $4.95 per Mcf of natural gas and $32.88 per barrel of oil. The related
after-tax standardized measure of discounted future net cash flows was $158,979,000.
    
    Lease holdings of approximately 473,000 gross (360,000 net) undeveloped acres and 37,000 gross (30,000
net) developed acres.
    
    Operations of 708 productive wells (91% of the productive wells in which we own a working interest). For the year ended December 31, 2003, we reported the following:  
    
    Net income of $23,795,000.
    
    Net cash provided by operating activities of $46,149,000.
    
    Average daily net production of 35,658 Mcf of natural gas and 1,099 barrels of crude oil (42,252 Mcfe).
    
    Average price realizations of $3.53 per Mcf of natural gas and $31.71 per barrel of crude oil. 
 Strategy Objectives.We seek to create shareholder value by identifying, evaluating and
capturing opportunities related to the oil and gas industry. Most of our
investment activities have been, and are projected to be, associated with our
exploration and production operations, including the acquisition, exploration,
development, and exploitation of properties, and 4




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production of oil and gas. We
have also invested and conducted operations in oilfield services, gas gathering
and processing, and in oil and gas marketing and trading, and we intend to
continue seeking such opportunities in the future. One of Primas goals is to
be among the lowest-cost full-cycle producers of oil and gas, and to realize
among the highest cash flow margins for reinvestment, in the industry. Through
our related activities in other segments of the energy business, we seek to
complement and reinforce the achievement of goals in our exploration and
production operations, and to enhance total returns to shareholders. Acreage.We seek to acquire oil and gas leaseholds in prospective areas at
reasonable costs and with attractive terms. We can potentially benefit from
the activities of other operators in these areas as well as from our own
activities. Operations.We generally prefer to operate oil and gas properties in which we
own significant economic interests. As operator, we are in a better position
to control the costs, timing, quality and safety of work performed, and other
factors that can affect the profitability of a property. In some instances,
however, we may prefer to retain non-operating interests in properties where
another operator has achieved economies of scale or has other operating
advantages. Exploitation.We intend to continue property exploitation activities in our
principal operating areas. In the D-J Basin, we plan to continue well
refracturing, recompletions and development drilling, to the extent warranted
by ongoing results and market conditions. We also plan to continue
exploitation activities targeting CBM in the
Powder River Basin and conventional reservoirs in the Wind River Basin,
depending upon the merits of each activity and subject to regulatory
considerations. We generally assess these activities as low-to-moderate risk
endeavors that can be undertaken whenever market conditions are projected to be
adequate for projects to meet our investment criteria, provided we are able to
obtain necessary approvals from regulatory authorities. Exploration.We generally seek to allocate 5% to 20% of our capital
expenditures budget toward higher-risk exploration activities. These activities
may include leasehold acquisitions, geologic and geophysical evaluation, and
drilling test wells on prospects. Our exploratory prospects can be either
internally generated or result from acquiring interests in other operators
prospects. The objective of our exploration activities is to expose a portion
of our capital to higher-risk projects that we believe have the potential to
deliver high rates of return if successful. As compared to individual
exploitation opportunities, a successful exploration project could have a more
significant impact on Primas value but the likelihood of success is
considerably lower. Gathering, Marketing and Trading.We elect to market our own natural gas and
crude oil production whenever we believe that we can enhance our net price
realizations by doing so. At times, Prima may also own assets downstream of the
wellhead, including, but not limited to, gathering and compression facilities.
We invest in such downstream assets where we believe opportunities exist to
enhance Primas overall project economics by capturing an additional portion of
the value chain from the wellhead to the burner tip. We may also gather,
compress and market third-party gas, if we expect that project rates of return
will be attractive. Oilfield Services.We believe that we can, at times, achieve better control of
the timing, quality and cost of work performed on our wells by owning and
operating well servicing equipment. We also intend for these activities to
constitute a separate business segment and profit center through providing such
services to other operators. Mergers, Acquisitions and Divestitures.We regularly review merger,
acquisition and divestiture opportunities related to the oil and gas industry
that could complement or enhance Primas existing businesses. We intend to
pursue, and if possible consummate, such transactions when we believe that they
would improve the risk-adjusted returns realized by Primas shareholders over
the long term. Derivatives.We periodically use commodity futures contracts to mitigate the
impact of the volatility of oil and gas prices on a portion of our production
and gas marketing activities. Our use of such derivatives is also intended to
improve our average oil and gas price realizations over time, to enhance
profitability, though such outcome cannot be assured. We may also elect at
times to enter into derivatives contracts for volumes that exceed our projected
total production, or which increase, rather than decrease, our exposure to a
decline in oil and gas prices or expansion of basis differentials. We would
consider establishing such positions if our analyses lead us to believe that
prices are likely to move in a manner 5




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that would generate gains from the
positions. Derivative positions for volumes greater than our expected
production, or which would increase our exposure to a decline in oil and gas
prices or expansion of basis differentials, would be speculative and would be
limited in size to an amount that, in managements judgment would not be
material to our balance sheet taken as a whole, but they might have a
significant positive or negative impact on reported net earnings. 
 Oil and Gas Properties and Operations Major Properties Denver-Julesburg Basin This basin has been under extensive development since the 1970s and has been
substantially drilled. However, continued development has been supported by
improvements in fracturing (or frac) technology to enhance oil and gas
recoveries from tight sand reservoirs and by higher oil and gas prices. Because
of the additional drilling and well stimulations encouraged by these factors,
the D-J Basin continues to be under very active development and basin-wide
production is near all-time peak levels. Our activities in the D-J Basin have been conducted primarily in the Wattenberg
Area, which encompasses more
than 1,000 square miles, between 20 and 55 miles northeast of Denver, Colorado.
We have conducted operations in the D-J basin for more than 20 years, and at
the end of 2003 we owned working interests in 455 wells in the area, 436 of
which we operated. Our drilling and production activities to date in the D-J
Basin have been centered in a portion of the Wattenberg Field where the primary
productive reservoirs are found in the Codell and Niobrara formations, which
blanket large areas of the field at depths of approximately 7,000 to 7,300
feet. These formations have moderate porosity and low permeability, and require
fracture stimulation to establish economic production. Recoverable reserves
from any individual wellbore are largely dependent on reservoir quality, sand
thickness, and fracture stimulation techniques. Our D-J Basin wells produce both natural gas and crude oil. Primas natural gas
production in this area averages approximately 1,240 Btu per Mcf at the
wellhead. Natural gas liquids (propane, butane, ethane, isobutane, and pentane)
are extracted from the well stream and sold separately by third-party
gatherer/purchasers but their value is reflected in our wellhead price for
natural gas. Our average gas price realizations per Mcf in this area have
ordinarily slightly exceeded Rocky Mountain spot prices due to the high Btu
content of the gas, but this relationship varies with market conditions and is
dependent, in part, on the price levels of natural gas liquids. In 2003, our
gas price realizations for D-J Basin production averaged $4.13 per Mcf,
compared to the Colorado Interstate Gas (CIG) index average of $4.04 per
MMBtu. Our crude oil in this area is sweet and generally commands a price
comparable to oil traded on the New York Mercantile Exchange (NYMEX). Primas leasehold
position in the D-J Basin at the end of 2003 included 19,110
gross (16,570 net) developed acres, and an additional 12,000 gross (11,000 net)
undeveloped acres. Our estimated proved reserves in the D-J Basin at that date
were approximately 53,753,000 Mcf of natural gas and 4,892,000 barrels of oil,
or 83,105,000 Mcfe, representing 66% of our total estimated proved reserve
quantities. During 2003, Primas net production from D-J Basin properties
averaged approximately 14,700 Mcf of gas and 1,065 barrels of oil, or 21,100
Mcfe, per day, accounting for 50% of our total oil and gas production and 59%
of our oil and gas sales revenues (excluding hedging effects). Our net
production from D-J Basin wells was less than 1% lower in 2003 than in 2002,
reflecting roughly offsetting effects of natural depletion and new activities. Codell/Niobrara wells that we recently drilled and completed in this area have
generally cost approximately $285,000 and targeted approximately 200,000 to
250,000 Mcfe of gross recoverable reserves per well (excluding refracs,
discussed below). At year-end 2003, we controlled approximately 200 potential
drill sites in the D-J Basin, with 90 of these attributed proved undeveloped
reserves. These proved locations have projected rates of return above 35%
using futures prices reflected on forward markets on December 31, 2003. During
2003, we drilled 28 gross (27.0 net) wells in the D-J Basin, all of which were
successfully completed and placed on production. Advancements in refracturing (refrac) stimulation technology have enabled us
to add deliverability and reserves from the Codell and Niobrara formations. A
refrac is a procedure in which a formation in an older well that has been 6




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previously fractured at least once is stimulated by another fracture treatment.
We generally target older wells with declining deliverability for
restimulation. Prima performed 38 refracs in Wattenberg during 2003, with such
activities primarily focused on the Codell formation. These had an average
cost of approximately $120,000 and are projected to deliver rates of return in
excess of 100% based on actual cash flows through year-end, projected
incremental production and futures prices reflected on forward markets on
December 31, 2003. At the end of 2003, we had 136 proven D-J Basin refrac
projects reflected in our reserve report. During the fourth quarter of 2003,
we conducted two well operations to fracture-stimulate the Codell formation for
a third time, referred to as a tri-frac. Based on encouraging short-term
performance results, we believe that tri-frac operations may provide future
opportunities to add reserves and production on many of our existing D-J Basin
wells, but none of these are included in estimated proved reserves at the end
of 2003. We plan to continue our development and exploitation activities in the D-J
Basin, and are currently budgeting for capital investments in the area
aggregating approximately $14 million in 2004. Planned activities include
drilling approximately 35 new Codell/Niobrara wells and refracing, tri-fracing
or recompleting approximately 50 wells in the Codell and/or the Niobrara
formation. Our plans are subject to revision, however, based on economic
conditions, performance results, activities conducted in other areas, and other
factors. New wells, refracs and recompletion operations in the D-J Basin are
characterized by flush production at relatively high rates for a few
months, after which relatively shallow decline rates are established at lower
production levels. Therefore, we may accelerate these operations when oil and
gas prices are high or defer them when prices are low, to enhance the impact on
investment returns from the flush production. Powder River Basin Coalbed Methane At December 31, 2003, we controlled leaseholds covering approximately 110,000
gross (97,000 net) acres in the Powder River Basin CBM play and had established
proved gas reserves totaling approximately 34,965,000 Mcf on a small portion of
this acreage. These CBM reserves represented 28% of Primas total estimated
proved oil and gas reserve quantities at the end of 2003. Our net gas
production from this area increased from an average of approximately 4,300 Mcf
per day in 2002 to 17,700 Mcf per day in 2003, due to performance of our
Porcupine-Tuit property where wells placed on-line in 2002 produced for a full
year and additional wells were drilled and brought on-line. In 2003, the
Powder River Basin CBM area accounted for 42% of our total oil and gas
production and 32% of our oil and gas sales revenues (excluding hedging
effects). Based on current market conditions and excluding the potential
impact of exploratory discoveries or proved property acquisitions, we expect
that our future activities in the Powder River Basin CBM area will account for
significant portions of our capital expenditures, proved reserve additions and
new sources of production during the next several years. There is no certainty,
however, that future activities will generate the results that we currently
project. As of December 31, 2003, we had drilled 418 wells and acquired five wells in
the Powder River Basin CBM play. At that date, 105 of these were connected to
sales lines (including 99 that were producing gas), 153 were waiting on
connection to gathering systems (of which 16 were already on pump, in the
process of being de-watered), and the remaining wells were sold (most in 2002).
We anticipate that approximately 130 of the 153 wells awaiting connection to
gathering systems will be connected during the second half of 2004 and will
begin gas production after sufficient de-watering has occurred. The remaining
wells awaiting hook-up will be connected to a gathering system once wider-scale
development occurs in the areas where these wells are located. Based on
engineering estimates prepared as of the end of 2003, our reserve report for
this CBM area included 254 proved undeveloped locations and identified over
2,350 additional non-proved prospective drill sites on our leaseholds, subject
to economic viability that will be dependent upon projected regional gas
prices, estimated development and operating costs, future drilling results from
activities by Prima and other operators, and other factors. Prima is majority
(often 100%) owner and operator of all of the Powder River Basin CBM properties
where it owns a working interest. The CBM play in the Powder River Basin is prospective over a vast geographic
area encompassing approximately three million acres in northeastern Wyoming and
southeastern Montana. Industry drilling activity to date has primarily been
focused in Wyoming, where most of the acreage and thicker coal seams lie.
According to the Wyoming Oil & Gas Commission, over 16,000 Powder River Basin
CBM wells have been drilled in the state through the end of 2003 and 7




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approximately 12,000 of these
wells were producing an aggregate of approximately 950 MMcf of
natural gas per day during December 2003. At times during the past five years,
this has been the most active drilling play in the United States. Although
activity levels moderated in 2002 and 2003, due to unsettled federal land use
issues (discussed below), depressed regional gas prices in 2002, and other
factors, significant estimated potential gas reserves remain unexploited in the
area. The primary target coals are found in the Fort Union formation at depths
ranging from 600 feet to 2,200 feet. It is common to encounter multiple coal
zones varying in thickness from a few feet to over 150 feet between these
depths. The methane in coal beds is adsorbed, or attached, within the coal
layers and is held in place by water
within the coals. When water is produced from the coal seam, the pressure is
reduced, allowing the gas to desorb from the coal. Operators in the area have
experienced de-watering times ranging from a few days to over one year, with
the de-watering time influenced by well density, coal depth, permeability, gas
content, structure and other factors. Gas production rates from individual
wells in the play have ranged from a few Mcf per day to over 1,000 Mcf per day
after sufficient de-watering. Significant industry CBM drilling activities in this area began in 1994 and
have primarily been focused on developing reserves in the Wyodak coal, on the
east side of the basin. Typically, costs for these wells (including allocable
costs for related surface equipment and infrastructure) averaged $70,000 to
$90,000 per well, and yielded gross gas reserves averaging 250,000 to 300,000
Mcf per well. Future drilling operations are expected to be focused on
development of the Big George, Wall and other coal seams that are generally
deeper and often thicker than the Wyodak coal. We expect that as these deeper,
thicker coals are developed, the gas reserves and production per well and the
average drilling, completion and operating costs per well will be greater than
experienced so far to develop the Wyodak coal seam. To produce gas in this CBM play, wells generally must be hooked-up to a
low-pressure gathering system and compression, commonly referred to as screw
compression, which typically holds wellhead pressure to less than 10 pounds
per square inch gauged (psig). The gas must then move through a gathering
system where, at its terminus, gas needs to be further boosted to about 1,400
psig to enter a high-pressure header-system line. This high-pressure boost is
commonly referred to as reciprocating (or recip) compression. CBM gas from
this area is generally somewhat less than 1,000 Btu per Mcf and may require
carbon dioxide extraction to meet interstate pipeline gas quality
specifications. Due to relatively high compression and transportation costs,
net price realizations for this gas are below Rocky Mountain indices. The
amount of the discount varies with the nominal level of the indices, Btu
content of the gas, location of the property, fuel use and other factors, but
in 2003 Primas realized price on production from CBM wells averaged $2.87 per
Mcf, compared to the CIG index average of $4.04, for a difference of $1.17 per
Mcf. Our CBM-prospective net acreage holdings in the Powder River Basin at the end
of 2003 were comprised of approximately 83% federal, 7% state, and 10% fee
(private) leases. Generally, the federal leases have an initial ten-year term,
state leases have a five-year term, and the terms of fee leases vary from a few
months to several years. The primary lease terms of federal acreage have
generally been extended for the period that access to the lands has been
restricted while an Environmental Impact Statement (EIS) was pending or
subject to legal challenge after its completion. On April 30, 2003, the BLM issued the final Record of Decision (ROD) in
relation to its EIS regarding future CBM drilling in the Powder River Basin.
Among other conditions for future operations, this ROD requires additional
surveys for plant and animal species and cultural artifacts, and noxious weed
mitigation. We have filed permit applications for approval by the BLM under
the terms of the new EIS, but cannot predict whether or when such permits will
be granted. Since the issuance of the final ROD, the BLM has been reviewing
their permitting processes in an effort to eventually facilitate issuance to
industry of approximately 3,000 drilling permits per year for this
area, but actual issuances of permits have so far continued to be made at a fraction of that pace. BLM
permit issuances may also be affected for some period by several pending
lawsuits that were filed shortly after the ROD was issued, challenging portions
of the BLMs decision. At this time, we are unable to predict the outcome of
this matter or its impact on our planned operations in the Powder River Basin.
A significant portion of the wells we plan to drill in 2004 would require
federal permits to be issued by the BLM. However, we do not expect that any
limitations on our ability to drill during 2004 will affect the rate of our
production until late in the year. 8




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##### Table of Contents



The Wyoming Department of Environmental Quality (DEQ) is responsible for
considering applications for water discharge permits and air discharge permits,
which are required to operate natural gas fired compressors. Water produced
from CBM wells is generally potable (drinking water quality) and permits to
discharge water on the surface had generally been attainable early in
development of the eastern side of the basin. However, issuance of permits to
surface discharge water was significantly slowed during the past two years in
order to allow further study of the potential impacts of the mineral content of
the water on agriculture and wildlife. It is expected that, in the future, the
Wyoming DEQ will generally require water management techniques other than
surface discharge, such as collection in containment reservoirs or treating, in
accordance with conditions also outlined in the BLMs EIS. These additional
requirements will add to the costs of CBM development and production, but we do
not believe that they will materially impact the economic viability of the
play. We have not encountered, nor do we expect to encounter, significant
difficulties in obtaining air permits for our CBM operations from the DEQ. The transportation infrastructure in this basin is currently capable of moving
approximately 1,500,000 Mcf per day of natural gas, compared to the estimated
950,000 Mcf per day produced in December 2003. Downstream of these header
systems serving the Powder River Basin, the pipeline grid has been
significantly enhanced over the past year by several interstate pipeline
expansions, creating adequate capacity at present to transport gas from the
Rocky Mountain region to other markets. We do not currently own firm
transportation for our own account, and so are relying on availability of
capacity on pipelines in order to market our gas. We established our first significant Powder River Basin CBM production in 2001
from the Stones Throw property (in the northern part of the play), where gross
production rates increased over several months to a level in excess of 8,000
Mcf per day (approximately 6,800 Mcf net) shortly before the time the property was sold in
March 2002. In July 2002, we initiated production from 27 wells at our
Porcupine-Tuit CBM property (in the southern part of the play). Production from
this property increased over the balance of the year and in 2003, as wells
de-watered, more wells were drilled and hooked up, and additional
third-party-owned compression capacity was installed. At the end of 2003, 85
wells had been drilled and hooked up at Porcupine-Tuit and were producing at a
combined gross rate of approximately 25,000 Mcf per day (approximately 19,500
Mcf net). Overall, predominantly reflecting contributions these two properties,
Primas Powder River Basin CBM properties accounted for net production
averaging approximately 4,000 Mcf per day, 4,300 Mcf per day, and 17,700 Mcf
per day, respectively, in 2001, 2002, and 2003. These early-stage developments
primarily targeted relatively shallow Wyodak coals. During 2003, Prima drilled 76 gross (57.7 net) Powder River Basin CBM wells and
our direct capital expenditures on the Powder River Basin CBM play, including
surface equipment and related infrastructure, totaled approximately $8.5
million. Activities during the year were focused on Porcupine-Tuit, where we
drilled 24 wells, and on project areas in the central part of the basin where
most of our core undeveloped land holdings in the play are concentrated. These
include our Kingsbury, Cedar Draw and North Shell Draw project areas, located
approximately 15 to 25 miles west and northwest of Gillette, Wyoming, where
2003 drilling activities were conducted to continue evaluation and development
of four main identified coal seams, from the shallower Lower Anderson
coal to the deeper Wall coal, found at depths ranging from
700 feet to 2,000 feet. These areas account for most of the previously-drilled
wells that we intend to tie in to a gathering system in 2004. Further west lie
additional key project areas where we control significant acreage, including
Wild Turkey, where the Big George coal is found at approximately 1,300
feet, and Fortification Creek, which also has multiple developable coal
seams at depths ranging from 700 feet to 1,600 feet.
We anticipate that it will take some time to establish significant proved CBM
reserves and production from these areas, particularly from the deeper coals,
as they are untested in much of the basin and extensive de-watering will likely
need to occur before commercial quantities of gas production can be
realized. Furthermore, it is not assured that these projects will ultimately be
successful and that they will yield significant reserves and production. We are currently budgeting for capital investments in the Powder River Basin
CBM play during 2004 of approximately $24 million for drilling costs,
production equipment, and related infrastructure costs. Planned activities are
focused primarily in the Kingsbury, Cedar Draw, North Shell Draw and Wild
Turkey project areas. Our preliminary plans call for drilling an estimated 150
wells and hooking up most of these and 130 previously-drilled wells into
gathering systems, as 9




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##### Table of Contents



well as investing in infrastructure such as power
connections and water management facilities. Due to uncertainties regarding
regulatory approvals needed to conduct these activities, we can make no
assurance that we will be able to conduct the operations that we have planned
or that we will reach the targeted level of capital investments. Other Powder River Basin,
Conventional. At the end of 2003, Prima owned working
interests in 17 gross (12.8 net) conventional wells in the Powder River Basin,
and deep-rights (below the coals) under 2,000 gross (1,400 net) developed acres
and 160,000 gross (146,500 net) undeveloped acres in the area. Our estimated
proved reserves at the end of 2003 from conventional sands in the Powder River
Basin totaled 2,602,000 Mcf of natural gas and 60,000 barrels of oil, or
2,964,000 Mcfe, representing 2.4% of our total estimated proved reserve
quantities. During 2003, Primas net production from these properties averaged
approximately 1,400 Mcfe per day, accounting for 3.3% of our total oil and gas
production and 3.4% of our oil and gas sales revenues (excluding hedging
effects). Our net production from Powder River Basin conventional wells was
24% lower in 2003 than in 2002, reflecting natural depletion, as no new wells
were drilled. No significant activity is currently planned for 2004. Cave Gulch (Wind River
Basin). At the end of 2003, Prima owned primarily
non-operated working interests in 50 gross (3.8 net) wells in the Cave Gulch
Field in the Wind River Basin. Our Wind River Basin acreage position is
comprised of 1,240 gross (170 net) developed acres and 37,000 gross (23,000
net) undeveloped acres. Primas estimated proved reserves at the end of 2003
attributable to this area totaled 4,644,000 Mcf of natural gas and 14,000
barrels of oil, or 4,727,000 Mcfe, representing 3.8% of our total estimated
proved reserve quantities. During 2003, Primas net production from the Cave
Gulch Field averaged approximately 2,000 Mcfe per day, accounting for 4.7% of
our total oil and gas production and 5.3% of our oil and gas sales revenues
(excluding hedging effects). Our net production from Cave Gulch wells was 20%
higher in 2003 than in 2002, as new wells and recompletions offset natural
depletion. Primas capital investments at Cave Gulch in 2003 aggregated
approximately $2.3 million, including costs of participating in drilling 17
gross (1.3 net) wells. The operator has indicated that up to six gross (0.5
net) additional wells are preliminarily planned for 2004, for a projected net
Prima investment of approximately $1 million. Coyote Flats Prospect. Primas Coyote Flats Prospect is located 15 to 25 miles
northwest of Price, Utah, and is approximately 15 miles northwest of the
Drunkards Wash Field, which is expected to ultimately produce in excess of 1.2
Tcf of natural gas from the Cretaceous Ferron coals and sandstones. We control
approximately 75,000 gross (73,000 net) undeveloped acres within the prospect
area. Data from drilling operations conducted on the Coyote Flats acreage
during the 1950s indicated gas shows from the Emery coal seam interval, the
Ferron sand and the Dakota sand. Our primary exploratory objectives at Coyote
Flats are coal beds in the Emery member of the Mancos shale and the Ferron
sandstone interval. Emery coals are found across the majority of the lease
position at depths below 3,000 feet, while the Ferron sandstone is found on the
acreage at depths ranging from 5,000 to 8,500 feet. During the fourth quarter of 2002, we drilled a 100%-owned exploratory well on
the Coyote Flats Prospect, to begin to evaluate the Emery coals and the Ferron
sandstone. The Scofield-Thorpe #22-41 well was drilled and cased to a total
depth of 6,247 feet, before operations were suspended for the winter. The well
encountered an aggregate 122 feet of Emery coal, from numerous coal beds,
including eight with a thickness exceeding five feet, and the Ferron sandstone
section was drilled between 5,991 and 6,247 feet. Encouraging gas shows were
encountered while drilling from several of the Emery coal beds and from
fractured shales and sandstones in the Ferron section. In the second half of 2003, Prima initiated completion and testing of the
Ferron sandstone reservoirs in the Scofield-Thorpe #22-41 well. We completed a
30-day production test on the well followed by a 7-day pressure build-up test.
The test results were encouraging, as gas rates of 1,100 Mcf per day and water
rates of 150 bpd were measured, with gradually increasing gas rates and
decreasing water rates. During 2004, we plan to conduct follow-up drilling on
the Coyote Flats Prospect to further evaluate the Ferron sandstone reservoirs,
and we also expect to initiate a multi-well pilot program to test the Emery CBM
potential. We may seek a partner to participate in these operations. 10




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##### Table of Contents



East Clear Creek
Prospect. We control approximately 9,000 gross and net acres
in our East Clear Creek Prospect, located approximately 15 miles west of Price,
Utah. This prospect is one mile east of Clear Creek Field, and two miles west
of the Gordon Creek Field, both of which have produced from the Cretaceous
Ferron sandstone. The Clear Creek Field produced in excess of 135 Bcf from 16
wells and the Gordon Creek Field was recently producing at a gross rate of
approximately 2,700 Mcf per day from five wells placed on line over the past
year. Prima has been working with the U.S. Forest Service and the Bureau of
Land Management on an EIS that must be completed before drilling permits will
be issued on this prospect. We expect to receive a permit to drill a test well
on this prospect later this year and plan to drill a well as soon as
practicable thereafter that will target the Ferron and Dakota sandstones at a
depth of approximately 7,000 feet on a seismically-defined structure. Flat Canyon Prospect. Prima owns approximately 6,600 gross and net acres under
its Flat Canyon Prospect, located in Emery County, Utah. Our acreage
immediately offsets the Flat Canyon Field, which was discovered in 1952. The
Flat Canyon Field has produced 9.6 Bcf of natural gas and 14,000 barrels of oil
from six wells completed in the Cretaceous Ferron sandstones. We plan to test
the Cretaceous Ferron and Dakota formations on the prospect at depths between
6,500 and 7,500 feet. Prima is currently working with the U.S. Forest Service
and the Bureau of Land Management to permit a well on this prospect. Christmas Meadows Prospect. Prima currently holds leases or farmout rights
representing approximately a 47% working interest in the Table Top Federal
Unit, which is comprised of approximately 24,000 gross acres in Summit County,
Utah, roughly 30 miles south of Evanston, Wyoming. The Christmas Meadows
prospect, within the Unit, is a large seismically-defined anticlinal closure
along the Uinta Mountain front, within the Rocky Mountain Overthrust Belt.
Several potential pay sands have been identified down to an estimated depth of
approximately 18,000 feet. This project has been delayed for several years and
the federal leases have been temporarily suspended while the U.S. Forest
Service was preparing an EIS and considering a revision of the forest plan for
the area. It currently appears that these issues may be near resolution,
enabling a test well to be spudded in the second half of 2004 or in 2005. The
initial test well is expected to be drilled to a depth of approximately 15,000
feet to test the Frontier and Dakota sandstones. Once operations in the unit
are commenced, Prima and its partners will have approximately six months to
establish capability of commercial production, otherwise certain leases will
expire. We anticipate participating in the test well for all or a portion of
our current working interest. Merna Prospect. Prima owns an average 35% working interest in 74,000 gross
acres in the greater Merna area, located in the northern Green River Basin, in
Sublette County, Wyoming. The Merna anticlinal structure is 20 miles northwest
of the prolific Pinedale Anticline, where the over-pressured Cretaceous Lance
and Mesaverde formations are under extensive development. The same objectives
are targeted on the Merna Prospect. In late 2002, the Miller Federal #7-4 well
was drilled by another operator along the Merna anticline on lands in which
Prima had farmed out its 50% working interest. An affiliate of this operator
installed a 36-mile natural gas pipeline to facilitate extended production
testing and market sales for this well and future wells that might be drilled
in the Merna area. The Miller Federal #7-4 well exhibited strong gas shows at
high pressure while drilling but subsequent completion of the well in 2003
resulted in only modest production rates. This well and previous drilling in
the area have established the presence of a thick Lance sand interval with gas
in place, but project success will likely depend on encountering
naturally-fractured reservoirs or successful application of fracture
stimulation, due to relatively low porosity and permeability. In 2002, a large
regional 3-D seismic survey that encompassed a large portion of the Merna
Prospect acreage was completed. In late 2003, another operator initiated a
test well on Merna acreage in which Prima held an interest. Prima is
participating in the Sage Flat Federal #17-20 well, with a 6.3% working
interest before payout and a 10.9% working interest after payout. The Sage Flat
Federal #17-20 well is located three miles north of the Miller Federal #7-4
well. 11




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##### Table of Contents



Proved Reserves Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Net proved
reserves as of December 31, 2003, 2002 and 2001 were estimated by Primas
engineers and audited by Netherland, Sewell and Associates, Inc., independent
petroleum engineers. The table below sets forth the estimated quantities of net proved reserves
attributed to our property interests at the end of each of the last three
years, and the present value of estimated future net cash flows attributed to
such reserves using prices in effect as of the respective year-end dates, held
constant. The average net realizable prices used to estimate proved reserve
quantities at the end of 2003, 2002, and 2001, respectively, were as follows:
$4.95, $2.64, and $1.94 per Mcf for natural gas; and $32.88, $31.30, and $19.71
per barrel of oil. In accordance with Securities and Exchange Commission
guidelines, projected future net cash flows from production of proved reserves
were discounted by ten percent per annum to derive present values and the
Standardized Measure of discounted future net cash flows after income taxes.
The 10% discount factor is not necessarily a market rate, and present value, no
matter what discount factor used, is materially affected by assumptions as to
future prices and costs and timing of future production, which may prove to be
inaccurate. For further information concerning estimated proved reserves and
the discounted future net cash flows related to these reserves, see unaudited
Supplementary Oil and Gas Information in Note 12 within the Notes to
Consolidated Financial Statements. 2003
    
    2002
    
    2001Estimated proved natural gas reserves (Mcf)
    
    
    96,000,000
    
    
    
    87,440,000
    
    
    
    115,222,000Estimated proved oil reserves (barrels)
    
    
    4,966,000
    
    
    
    3,944,000
    
    
    
    3,394,000Present value of estimated future net cash
flows, before future income tax expense
    
    $
    239,800,000
    
    
    $
    128,843,000
    
    
    $
    91,905,000Standardized measure of discounted
future net cash flows
    
    $
    158,979,000
    
    
    $
    91,279,000
    
    
    $
    66,801,000
 There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates
of production and timing and amounts of development expenditures. Oil and gas
reserve engineering should be recognized as a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured in an
exact way. The accuracy of any reserve estimate is a function of the quality
of available engineering and geological data and interpretation, and judgment.
Results of drilling, testing and production after estimates are prepared may
justify revisions. Accordingly, reserve estimates are often materially
different from the quantities of oil and natural gas that are ultimately
produced. We are not currently aware of any developments subsequent to
December 31, 2003 that we believe would warrant a significant upward or
downward revision to our estimated proved reserves as of that date. Oil and
natural gas prices have historically been volatile and are expected to continue
to be so in the future. Changes in product prices affect the economic limits
and, therefore, recoverable reserve quantities of oil and gas wells, as well as
the present value of estimated future net cash flows and the standardized
measure of discounted future net cash flows. Since January 1, 2003, we have filed Department of Energy Form EIA-23, Annual
Survey of Oil and Gas Reserves, as required of operators of domestic oil and
gas properties. There are differences between the reserves as reported on Form
EIA-23 and reserves as reported herein. Form EIA-23 requires that operators
report on total proved developed reserves for operated wells only and that the
reserves be reported on a gross operated basis rather than on a net interest
basis. 12




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##### Table of Contents



Production The following table summarizes information with respect to our producing oil
and gas properties for each of the periods shown. 2003
    
    2002
    
    2001Quantities sold:Natural gas (Mcf)
    
    
    13,015,000
    
    
    
    8,343,000
    
    
    
    9,277,000Oil (barrels)
    
    
    401,000
    
    
    
    373,000
    
    
    
    431,000Total natural gas equivalents (Mcfe)(1)
    
    
    15,421,000
    
    
    
    10,580,000
    
    
    
    11,863,000Average sales price (including hedging effects):Natural gas (per Mcf)
    
    $
    3.53
    
    
    $
    1.97
    
    
    $
    3.60Oil (per barrel)
    
    $
    31.71
    
    
    $
    25.14
    
    
    $
    25.88Total natural gas equivalents (per Mcfe)(1)
    
    $
    3.80
    
    
    $
    2.44
    
    
    $
    3.76Average production costs, including production taxes,
per Mcfe (1)
    
    $
    0.61
    
    
    $
    0.49
    
    
    $
    0.56
   (1)
    
    Oil production has been converted to a common unit of production (Mcfe of
natural gas) on the basis of relative energy content (one barrel of oil to
six Mcf of natural gas). Productive Wells The following table summarizes our total gross and net productive wells as of
December 31, 2003. Productive WellsOil
    
    GasGross (1)
    
    Net (2)
    
    Gross (1)(3)
    
    Net (2)(3)Operated:Colorado
    
    
    21
    
    
    
    20.0
    
    
    
    415
    
    
    
    383.6Wyoming
    
    
    
    
    
    
    
    
    
    
    272
    
    
    
    232.5Non-operated:Colorado
    
    
    
    
    
    
    
    
    
    
    19
    
    
    
    8.1Utah
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    0.4Wyoming
    
    
    
    
    
    
    
    
    
    
    53
    
    
    
    4.7Total (4)
    
    
    21
    
    
    
    20.0
    
    
    
    760
    
    
    
    629.3
 Additionally, we own royalty interests in 148 gross wells that are not included
in the above table.   (1)
    
    A gross well is a well in which a working interest is held. The number of
gross wells is the total number of
wells in which a working interest is owned.(2)
    
    A net well is deemed to exist when the sum of fractional ownership
interests in gross wells equals one. The number of net wells is the sum
of the fractional working interests owned in gross wells expressed as
whole numbers and fractions thereof.(3)
    
    Includes 153 gross (124.1 net) CBM wells in Wyoming that were awaiting
hook-up at year-end.(4)
    
    Wells are classified as oil wells or gas wells according to predominate
production stream. Multiple completions (28 wells) are counted as one
well. 13




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##### Table of Contents



Developed and Undeveloped Acreage At December 31, 2003, our oil and gas lease holdings were as follows: Developed Acreage (1)
    
    Undeveloped Acreage (2)Location
    
    Gross (3)
    
    Net (4)
    
    Gross (3)
    
    Net (4)Denver-Julesburg
Basin
    
    
    19,110
    
    
    
    16,570
    
    
    
    12,000
    
    
    
    11,000Green River Basin
    
    
    320
    
    
    
    40
    
    
    
    86,000
    
    
    
    36,000Powder River Basin
    
    
    14,870
    
    
    
    12,900
    
    
    
    177,000
    
    
    
    158,000Uinta Basin
    
    
    160
    
    
    
    160
    
    
    
    105,000
    
    
    
    102,000Wind River Basin
    
    
    1,240
    
    
    
    170
    
    
    
    37,000
    
    
    
    23,000Other basins
    
    
    1,500
    
    
    
    60
    
    
    
    56,000
    
    
    
    30,000Total
    
    
    37,200
    
    
    
    29,900
    
    
    
    473,000
    
    
    
    360,000
   (1)
    
    Developed acres are acres spaced or assigned to productive wells.(2)
    
    Undeveloped acres are acres on which wells have not been drilled or
completed to a point that would permit the production of commercial
quantities of oil or natural gas, regardless of whether such acreage
contains proved reserves.(3)
    
    A gross acre is an acre in which a working interest is owned. The number
of gross acres is the total number of acres in which a working interest is
owned.(4)
    
    A net acre is deemed to exist when the sum of the fractional ownership
working interests in gross acres equals one. The number of net acres is
the sum of the fractional working interests owned in gross acres expressed
as whole numbers and fractions thereof. Many of the leases comprising the undeveloped acreage set forth in the table
above will expire at the end of their respective primary terms unless
production from the leasehold acreage has been established prior to such date,
in which event the lease will remain in effect until the cessation of
production. We have generally been able to obtain extensions of the primary
terms of our federal leases for the period that we have been unable to obtain
drilling permits due to a pending EIS or related legal challenges. The following table sets forth the
expiration periods of the gross and net acres subject to leases summarized in
the table of undeveloped acreage, unless such leases are currently held by
production from a portion of the lease that has been developed. Acres ExpiringTwelve Months Ending:
    
    Gross
    
    NetDecember 31, 2004
    
    
    51,000
    
    
    
    25,000December 31, 2005
    
    
    82,000
    
    
    
    56,000December 31, 2006
    
    
    34,000
    
    
    
    34,000December 31, 2007
    
    
    25,000
    
    
    
    22,000December 31, 2008
    
    
    80,000
    
    
    
    73,000December 31, 2009 and later
    
    
    126,000
    
    
    
    117,000398,000
    
    
    
    327,000
 14




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##### Table of Contents



Drilling Activities Certain information with regard to our drilling activities for the years ended
December 31, 2003, 2002 and 2001 is set forth below: 2003
    
    2002
    
    2001Gross
    
    Net
    
    Gross
    
    Net
    
    Gross
    
    NetDevelopment:Productive
    
    
    67
    
    
    
    51.1
    
    
    
    55
    
    
    
    50.1
    
    
    
    123
    
    
    
    121.3Dry
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    67
    
    
    
    51.1
    
    
    
    55
    
    
    
    50.1
    
    
    
    123
    
    
    
    121.3Exploratory:Productive
    
    
    52
    
    
    
    34.7
    
    
    
    18
    
    
    
    11.0
    
    
    
    14
    
    
    
    14.0Dry
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    0.352
    
    
    
    34.7
    
    
    
    18
    
    
    
    11.0
    
    
    
    16
    
    
    
    14.3Total:Productive
    
    
    119
    
    
    
    85.8
    
    
    
    73
    
    
    
    61.1
    
    
    
    137
    
    
    
    135.3Dry
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    0.3119
    
    
    
    85.8
    
    
    
    73
    
    
    
    61.1
    
    
    
    139
    
    
    
    135.6
 Present Activities Year-to-date through February 27, 2004, we had drilled nine gross and net wells
in the D-J Basin. Six of these wells were producing at that date, one was
waiting on tie-in to a sales line and two were waiting on completion. We also
restimulated (refraced or tri-fraced) 14 gross (12.8 net) wells in the D-J
Basin, all of which have been restored to production. During this same period,
we drilled five gross and net wells in the Powder River Basin CBM play and
participated in drilling two non-operated (0.1 net) wells in the Cave Gulch
area, all of which were waiting on completion as of February 27, 2004. Natural Gas and Oil Marketing, Trading and Price Risk Management Primas marketing and trading activities may include marketing our own
production, marketing the production of other owners in wells that we operate,
and the purchase and resale of third-party owned production. This oil and gas
production is principally sold to end users, marketers, refiners and other
purchasers having access to pipeline facilities or the ability to truck oil to
local refineries. The marketing of oil and gas can be affected by a number of
factors that are beyond our control and which cannot be accurately predicted.
At times, we use financial instruments to hedge the price of a portion of our
production or production of others that we have committed to purchase for
resale. In 2003, revenues from the sale of Primas natural gas production, including
related hedging effects, totaled $45,911,000, representing 78% of our and gas
sales and 65% of our consolidated total revenues. Revenues from the sale of
Primas crude oil in 2003, including hedging effects, totaled $12,711,000,
representing 22% of our oil and gas sales and 18% of our consolidated total
revenues. Natural Gas The terms and conditions of our natural gas sales contracts vary as to price,
quantity, term and other conditions, but in general follow 30-day index or
day-to-day spot market prices. We occasionally sell gas at a fixed price for
periods greater than 30 days as an effective price hedge, but had no such
fixed-price sales arrangements in effect at
year-end 2003. We currently have two significant purchasers for our natural
gas, Duke Energy Field Services, LLC (Duke) and Western Gas Resources, Inc
(Western). Neither of these companies is affiliated with Prima and, while
loss of either as a purchaser or customer might have a material adverse effect
on our business, we believe that we could arrange to sell our gas to alternate
customers on reasonably comparable terms. 15




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##### Table of Contents



Natural gas produced in the D-J Basin is high in heating content and must be
processed to extract natural gas liquids. Duke purchases most of our D-J Basin
gas at the wellhead, under contracts that provide for Prima to receive fixed
percentages of the proceeds generated by Dukes sale of residue gas and natural
gas liquids after the gas is processed at Dukes plants. Net sales to Duke in
2003 accounted for approximately $19,193,000, or 27% of our total consolidated
revenues. Western purchases much of our gas production in the Powder River Basin,
including CBM gas from wells in the Porcupine-Tuit area. This CBM gas, which
accounted for over 95% of our sales to Western in 2003, is sold at the inlet to
Westerns compression facilities at prices based on the monthly CIG index less
certain costs for compression and transportation. Net sales to Western in 2003
accounted for approximately $19,062,000, or 27%, of our total consolidated
revenues. Our current gas gathering and marketing agreements generally arrange to get our
gas from the wellhead into high-pressure header systems or interstate
pipelines. We have not, however, contracted for downstream transportation on a
firm basis. As such, we have no liability to pay reservation (demand) charges
for header or pipeline capacity, but we also have no assurance that our gas
will flow every day and we are at risk that regional imbalances between gas
supply and pipeline capacity will unfavorably impact the gas prices that we
realize for our production. No significant curtailments of gas production
occurred during the three-year period ended December 31, 2003, but limited
pipeline capacity did create conditions during several months, particularly
between mid-2002 and mid-2003, in which the netback price that we received for
our natural gas was significantly below prices being paid for gas elsewhere in
the country. Due to expansions of pipeline capacity during 2003, we do not
expect such conditions to recur in the near-term. At times, we have also engaged in purchasing and re-selling third-party gas
within our areas of operations. These arrangements typically provide for the
purchase of natural gas at a known price or index, with a corresponding sale at
a net margin. However, from time to time we may have open purchase or sale
commitments without corresponding re-sale contracts, which could result in
losses. Primas Chief Executive Officer reviews such opportunities before
commitments are made and we closely monitor the mark-to-market gains or losses
of such positions. We had no purchase-for-resale trading obligations
outstanding at the end of 2003 and had entered into no commitments after
year-end 2003 through February 27, 2004. Oil Our oil production is typically sold to refiners, marketers and other
purchasers that truck it to local refineries or pipelines. The price is
generally based on a prevailing spot market index, such as NYMEX, with
adjustments for quality and location. We currently have one significant
purchaser of crude oil, Valero Energy Corporation, which accounted for
approximately $11,831,000, or 17%, of our total consolidated revenues in 2003.
We are not affiliated with Valero and believe that we could sell our crude oil
to other purchasers should we lose Valero as a purchaser, though the terms
might be less favorable. Price Risk Management We sometimes utilize commodity futures, over-the-counter swaps or similar
derivatives to mitigate risks related to the volatility of oil and gas prices.
Such transactions can also be used to protect against the risk of an expanding
differential between NYMEX and Rocky Mountain gas prices, which can occur when Rocky
Mountain gas supplies exceed regional demand and pipeline capacity out of the
Rocky Mountain region or due to other factors, such as regional weather
differences. A portion of these contracts did not meet all of the conditions
required for utilization of hedge accounting, but were nevertheless viewed by
us as providing considerable revenue protection in the event of declining oil
or gas prices. See Item 7A, Quantitative and Qualitative Disclosures about
Market Risk, below for
additional disclosures relating to derivatives, including our open derivative
positions as of February 27, 2004. Title to Oil and Gas Properties As is customary in the oil and gas industry, we typically conduct only a
preliminary title examination at the time that we acquire leases of properties
believed to be suitable for drilling operations. Prior to the commencement of
drilling 16




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operations, however, we engage independent attorneys to conduct a
thorough title examination of drill site tracts. Once production from a given
well is established, a division order title report is prepared, which indicates
the proper parties and percentages for payment of production proceeds,
including royalties. We believe that titles to Primas leasehold properties are
good and defensible in accordance with standards generally acceptable in the
oil and gas industry. 
 Oilfield Services We conduct our oilfield services business under the names of Action Oilfield
Services in Colorado and Action Energy Services in Wyoming. Action Oilfield Services Action Oilfield Services (AOS) has been active in the D-J Basin since 1986,
operating out of a field office and yard near LaSalle, Colorado. AOS owns
various well servicing equipment including eight completion rigs, a swab rig,
tractor trailer rigs for water hauling, and oilfield rental equipment, such as
pumps, tanks and blowout preventers. During 2003, we experienced high
utilization rates for our people and equipment due to strong demand for
services for well recompletions, re-works and drilling in the area. We intend
to continue with our well servicing activities in the D-J Basin and will seek
opportunities to profitably expand the business. AOS provides services for
Prima as well as third-party operators in the area. During 2003, 22% of AOSs
revenues were from activities performed for Prima. AOS fees and costs
associated with providing services to Prima are eliminated in the consolidated
financial statements. Third-party revenues recorded by AOS in 2003 totaled
$6,718,000, or 9.6% of our consolidated revenues. Action Energy Services We formed Action Energy Services (AES) in the first quarter of 1999 to
conduct CBM well drilling and servicing activities in the Powder River Basin.
AES leases an office and yard in Gillette, Wyoming. AES has nine CBM
drilling and service rigs and related equipment. During 2003,
industry activity levels in the Powder River Basin CBM play were relatively
modest, due largely to limited availability of drilling permits on federal
lands caused, in part, by the pending status of the EIS early in the year and
subsequent legal challenges to the EIS after the record of decision was
published at the end of April 2003. As a result, we experienced moderate
utilization rates for our people and equipment during the year. However, we
believe that activity levels in the area will increase as the underlying causes
of the slowdown are addressed and we intend to continue to conduct both
drilling and well servicing operations in the Powder River Basin on behalf of
both Prima and unaffiliated third parties. During 2003, 30% of AESs revenues
were services conducted for Prima, and these revenues and the related costs
have been eliminated in consolidation. AESs third-party revenues were
$1,858,000 in 2003, accounting for 2.6% of our consolidated revenues. 
 Other Properties We lease 15,840 square feet of office space in Denver, Colorado for our
corporate headquarters, at an escalating annual cost averaging approximately
$275,000 over the seven-year term that commenced December 1, 2000. We lease
office space with a yard and shop facilities in Gillette, Wyoming on a
month-to-month basis for use in our Powder River Basin oil and gas production
and oilfield service operations. We own 160 acres of land in Weld County,
Colorado with a shop, office building and yard facilities for use in our D-J
Basin oil and gas production and oilfield service operations. At December 31,
2003, this land in Weld County had a net book value of $111,000 and the
furniture and office equipment at these three locations had a combined net book
value of $195,000. We own approximately ten acres of surface land with no mineral rights on the
western side of Greeley, Colorado. The land, which was acquired in March 2001
in exchange for minor undeveloped mineral rights, is part of a planned 760-acre
commercial and office park development. We plan to hold this land, which had a
net book value of $944,000 at the end of 2003, for future sale, exchange or
development. Prima is a 6% limited partner in a real estate limited partnership that owns
approximately 22 acres of undeveloped land in Phoenix, Arizona for investment.
The net book value of this partnership interest was $141,000 at December 31,
2003. 17




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Competition All of the businesses in which we operate are highly competitive. Our oil and
natural gas operations encounter strong competition from major oil and gas
companies, independent operators and others. Competition is particularly
intense with respect to the acquisition of desirable undeveloped and developed
oil and gas properties. The principal competitive factors in the acquisition of
oil and gas properties include the availability and quality of staff and data
necessary to identify, investigate and purchase such properties, and the
financial resources necessary to acquire and develop such assets. Many of our
competitors have appreciably greater financial, technical and other resources
and have more experience in the exploration for and production of oil and
natural gas than we have. Competition in oilfield services traditionally involves such factors as price,
efficiency, condition of equipment, availability of labor and equipment,
reputation and customer relations. Some of our competitors in the oilfield
services business are substantially larger than we are and have appreciably
greater financial and other resources. The competitive environment within which
we operate is uncertain and extremely price oriented. Likewise, other
businesses that we may participate in, including gas marketing and trading, and
gas gathering and processing, are characterized by significant competition from
companies with greater financial resources than Prima and, potentially, better
information regarding markets than we have access to. 
 Regulation Our businesses are subject to extensive federal, state and local laws and
regulations on the exploration for and the development, production and
marketing of oil and gas. Oilfield service operations are also subject to
various types of regulation by state and federal agencies. Legislation
affecting the oil and gas industry is under constant review for amendment or
expansion, and numerous federal and state departments and agencies are
authorized by statute to issue rules and regulations binding on the oil and gas
industry and its operators. The regulatory compliance burden on the oil and gas
industry significantly impacts the cost of doing business, and failure to
comply with regulations may carry substantial penalties. Under some
circumstances, regulations may impose prohibitive costs that render development
of an oil and gas property uneconomic or otherwise may impede development of a
property. A partial overview of prominent regulations applying to oil and gas
operations follows. Drilling and Production Matters States in which Prima conducts its gas and oil activities regulate drilling
activities and the production and sale of natural gas and crude oil. Such
regulations establish and implement requirements for obtaining drilling
permits, the method of developing new fields, the spacing and operation of
wells and the prevention of waste of oil and gas resources. In addition, states
may regulate the rate of production and establish maximum daily production
allowables for wells on a market demand or conservation basis. At times in the
past, the federal government has regulated the prices at which oil and gas
could be sold. Sales prices of oil and gas are not currently regulated, but
there is no assurance that price controls will not be reinstituted in the
future. Congress could re-enact price controls or other regulations in the
future. Environmental Matters Prima is subject to extensive federal, state and local environmental laws and
regulations that, among other things, regulate the discharge or disposal of
materials or substances into the environment and otherwise are intended to
protect the environment. Numerous governmental agencies issue rules and
regulations to implement and enforce such laws, which are often difficult and
costly to comply with and which carry substantial administrative, civil and/or
criminal penalties and in some cases injunctive relief for failure to comply.
Some laws, rules and regulations relating to the protection of the environment
may, in certain circumstances, impose strict liability for environmental
contamination. Such laws render a person or company liable for environmental
and natural resource damages, cleanup costs and, in the case of oil spills in
certain states, consequential damages without regard to negligence or fault. 18




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Other laws, rules and regulations may require the rate of oil and natural gas
production to be below the economically optimal rate or may even prohibit
exploration or production activities in environmentally sensitive areas. In
addition, state laws often require some form of remedial action such as closure
of inactive pits and plugging of abandoned wells to prevent pollution from
former or suspended operations. Legislation has been proposed and continues to
be evaluated in Congress from time to time that would reclassify certain oil
and gas exploration and production wastes as hazardous wastes. This
reclassification would make such wastes subject to much more stringent and
expensive storage, treatment, disposal and clean-up requirements. If such
legislation were to be enacted, it could have a significant adverse impact on
operating costs for the oil and gas industry, including Prima. Initiatives to
further regulate the disposal of oil and gas wastes are also proposed in
certain states from time to time and may include initiatives at county,
municipal and local government levels. These various initiatives could have a
similar adverse impact on our operations. The regulatory burden on the oil and
natural gas industry increases its cost and risk of doing business and
consequently affects its profitability. Compliance with these environmental requirements, including financial assurance
requirements and the costs associated with the cleanup of any spill, could have
a material adverse effect upon Primas capital expenditures, earnings or
competitive position. We believe that we are in substantial compliance with
current applicable environmental laws and regulations and that continued
compliance with existing requirements would not have a material adverse impact
on our competitiveness. Nevertheless, changes in environmental laws and
regulations have the potential to adversely affect Primas operations. For
example, the federal Comprehensive Environmental Response, Compensation and
Liability Act of 1980, as amended (CERCLA), also known as the Superfund
law, imposes liability, without regard to fault (i.e. strict and joint and
several liability) 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 or prior owner or operator of
the disposal site or sites where the release occurred and companies that
transported, disposed or arranged for the transport or disposal of the
hazardous substances found at the site. Persons who are or were responsible for
releases of hazardous substances under CERCLA may be subject to joint and
several liability for the costs of cleaning up the hazardous substances that
have been released into the environment and for damages to natural resources,
and it is not uncommon for the federal or state government to pursue such
claims. It is also not uncommon for neighboring landowners and other third
parties to file claims for personal injury or property or natural resource
damages allegedly caused by the hazardous substances released into the
environment. Under CERCLA, certain oil and gas materials and products are, by
definition, excluded from the term hazardous substances. However, certain
federal courts have held that some wastes associated with the production of
crude oil may be classified as hazardous substances under CERCLA. Similarly, under the federal Resource, Conservation and Recovery Act of 1976,
as amended (RCRA), which governs the generation, treatment, storage and
disposal of solid wastes and hazardous wastes, certain exploration and
production wastes are exempt from the definition of hazardous wastes. This
exemption continues to be subject to judicial interpretation and increasingly
stringent state interpretation. During the normal course of its operations,
Prima generates or has generated in the past exempt and non-exempt wastes,
including hazardous wastes that are subject to RCRA and comparable state
statutes and implementing regulations. The federal Environmental Protection
Agency (EPA) and various state agencies continue to promulgate regulations
that limit the disposal and permitting options for certain hazardous and
non-hazardous wastes. The state of Colorado, where a significant portion of Primas producing
properties are located, amended its statute concerning oil and natural gas
development in 1994 to provide the Colorado Oil & Gas Conservation Commission
(the COGCC) with enhanced authority to regulate oil and gas activities to
protect public health, safety and welfare, including the environment. The COGCC
has implemented several rules pursuant to these statutory changes concerning
groundwater protection, soil conservation and site reclamation, setbacks in
urban areas and other safety concerns, and financial assurance for industry
obligations in these areas. To date, these rule changes have not adversely
affected Primas operations, as the COGCC is required to enact cost-effective
and technically feasible regulations. However, there can be no assurance that,
in the aggregate, these and other regulatory developments will not increase the
cost of operations in the future. 19




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Also in Colorado, a number of city and county governments have enacted oil and
gas regulations. These ordinances increase the involvement of local governments
in the permitting of oil and gas operations, and impose additional restrictions
or conditions on the conduct of operations so as to reduce their impact on the
surrounding community. Accordingly, these local ordinances have the potential
to delay and increase the cost of drilling, refracing and recompletion
operations. In Primas CBM gas production operations in the Powder River Basin, we
typically bring naturally occurring groundwater to the surface as a by-product
of the production of methane gas. Federal and state authorities regulate the
disposition of this water. To-date, most of the water produced from Primas
wells has been discharged on the surface, in accordance with permits obtained
in compliance with federal and state statutes and regulations. However, water
disposal alternatives are currently under review by federal and state
regulatory authorities and future development of properties in the area may
require utilization of other methods. Implementation of such alternatives,
potentially including but not limited to, construction of evaporation ponds
near the well site and treatment of the water, could add delays and costs in
developing and operating these properties. Prima may also explore on or acquire
properties in other areas where disposal of produced water will be subject to
regulation by federal and state authorities. A significant portion of Primas leasehold interests in the Powder River Basin
in Wyoming, the Uinta Basin in Utah, and elsewhere in the Rocky Mountain region
is federal acreage where mineral rights, and sometimes surface ownership as
well, are managed by the Bureau of Land Management (the BLM). Drilling and
development of federal minerals and construction activities on federal surface
are subject to the National Environmental Policy Act (NEPA). The BLM has
delayed drilling on a substantial portion of the federal oil and gas leases
held by Prima, as well as those of other operators in these areas, pending
completion of environmental impact statements or assessments under NEPA. Delays
in obtaining access to these lands, and conditions imposed on development of
the properties, may affect the value of Primas reserves and prospects. In some circumstances, our operations involve the use of gas-fired compressors
to transport collected gas.
Operation of these compressors is subject to federal and state regulations for
the control of air emissions. The Federal Water Pollution Control Act (FWPCA) imposes restrictions and
strict controls regarding the discharge of produced waters and other oil and
gas wastes into navigable waters. Permits must be obtained to discharge
pollutants into state and federal waters. The FWPCA and analogous state laws
provide for civil, criminal and administrative penalties for any unauthorized
discharges of oil and other hazardous substances in reportable quantities and
may impose substantial potential liability for the costs of removal,
remediation and damages. State water discharge regulations and the federal
National Pollutant Discharge Elimination System permits applicable to the oil
and gas industry generally prohibit the discharge of produced water, sand and
some other substances into coastal waters. The costs to comply with zero
discharges mandated under federal and state law have not had a material adverse
impact on Primas financial condition and results of operations. Some oil and
gas exploration and production facilities are required to obtain permits for
their storm water discharges. Costs may be incurred in connection with
treatment of wastewater or developing storm water pollution prevention plans. The Oil Pollution Act of 1990 (OPA) imposes regulations on responsible
parties related to the prevention of oil spills and liability for damages
resulting from spills in waters of the United States. A responsible party
includes the owner or operator of an onshore facility, vessel or pipeline, or
the lessee or permittee of the area in which an offshore facility is located.
OPA assigns strict, joint and several liability to each responsible party for
oil removal costs and a variety of public and private damages, including
natural resource damages. While liability limits apply in some circumstances, a
party cannot take advantage of liability limits if the spill was caused by
gross negligence or willful misconduct or resulted from violation of a federal
safety, construction or operating regulation, or if the party fails to report a
spill or to cooperate fully in the cleanup. Even if applicable, the liability
limits for onshore facilities require the responsible party to pay all removal
costs, plus up to $350 million in other damages. Few defenses exist to the
liability imposed by OPA. Failure to comply with ongoing requirements or
inadequate cooperation during a spill event may subject a responsible party to
administrative civil or criminal enforcement actions. 20




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Operating Hazards and Insurance The oil and natural gas business involves a variety of operating risks,
including fires, explosions, blowouts, environmental hazards and other
potential events that could adversely affect our ability to conduct operations
or cause us to incur substantial losses. Such impairment or losses could reduce
or eliminate funds available for exploration, exploitation or acquisitions, or
result in loss of properties. In accordance with customary industry practices,
we maintain insurance against some, but not all, potential risks and losses. We
do not carry business interruption insurance. For some risks, we may elect not
to obtain insurance if we believe the cost of available insurance is excessive
relative to the risks presented. In addition, pollution and environmental risks
generally are not fully insurable at a reasonable cost. If a significant
accident or other event occurs and is not fully covered by insurance, it could
adversely affect us. 
 Employees and Offices As of December 31, 2003, we had 146 full-time employees, including 40 in our
Denver office and 106 in district and field offices. Of the district and field
employees, 22 were employed in Primas lease and well management operations and
84 were employed with our oilfield service operations. We also contract for
the services of independent consultants involved in land, geology, engineering,
accounting, regulatory affairs, and other disciplines as needed. We believe
that Primas relations with its employees are good. Primas principal
executive offices are located at 1099 18th Street, Suite 400, Denver, Colorado
80202. 
 Available Information Our website address is www.primaenergy.com. We make available free of charge
through our internet website our annual report on Form 10-K, quarterly reports
on Form 10-Q, current reports on Form 8-K and amendments to those reports filed
with or furnished to the SEC under applicable securities laws as soon as
reasonably practicable after we electronically file such material with, or
furnish it to, the Securities and Exchange Commission. Our website information
is not incorporated by reference into this Annual Report on Form 10-K. 
 Cautionary Statement for the Purposes of the Safe Harbor
Provisions of the Private Securities Litigation Reform Act of 1995 We are including the following cautionary statement to take advantage of the
safe harbor provisions of the Private Securities Litigation Reform Act of
1995 for any forward-looking statement made by, or on behalf of, Prima. The
factors identified in this cautionary statement are important factors (but not
necessarily all of the important factors) that could cause actual results to
differ materially from those expressed in any forward-looking statement made
by, or on behalf of, Prima. Where any such forward-looking statement includes
a statement of the assumptions or bases underlying such forward-looking
statement, we caution that, while we believe such assumptions or bases to be
reasonable and make them in good faith, assumed facts or bases almost always
vary from actual results, and the differences between assumed facts or bases
and actual results can be material, depending upon the circumstances. Where,
in any forward-looking statement, Prima or its management expresses an
expectation or belief as to the future results, such expectation or belief is
expressed in good faith and believed to have a reasonable basis, but there can
be no assurance that the statement of expectation or belief will result, or be
achieved or accomplished. We do not undertake to update, revise or correct any
of the forward-looking information. Taking into account the foregoing, the
following are identified as important risk factors that could cause actual
results to differ materially from those expressed in any forward-looking
statement made by, or on behalf of, Prima: Volatility of Oil and Natural Gas Prices.Historically, oil and natural gas
prices have been volatile and are likely to continue to be volatile. Prices
are affected by, among other things, market supply and demand factors, market
uncertainty, and actions of the United States and foreign governments and
international cartels. These factors are beyond our control. To the extent that
oil and gas prices decline, our revenues, cash flows, earnings and operations
are adversely impacted. Further, in adversely affecting our cash flows and
access to capital, low oil and gas prices could reduce our ability to replace
production and grow. Because of the dynamism of, and number of influences on,
commodity markets, we cannot accurately predict future oil and natural gas
prices. 21




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Uncertainty of Oil and Natural Gas Reserve Estimates.Estimates of our proved
reserves and related future net revenues are based on engineering reports
prepared by our engineers and audited by independent engineers. These estimates
are based on several assumptions that the Securities and Exchange Commission
requires oil and natural gas companies to use, including that oil and natural
gas prices in effect as of the end of the year remain constant. Such estimates
are inherently imprecise indications of future net revenues. Actual future
production, revenues, production taxes, operating expenses, and development
costs may vary substantially from estimates. In addition, our reserves might be
subject to upward or downward adjustment based on future production, results of
future exploration and development, prevailing oil and natural gas prices and
other factors. Risks of Oil and Natural Gas Exploration, Development and Production.The
search for oil and natural gas often results in unprofitable efforts, not only
from dry holes, but also from wells that, though productive, do not produce oil
or natural gas in sufficient quantities to return a profit on the costs
incurred. No assurance can be given that our exploration, development and
acquisition activities in the future will result in the addition of any oil or
natural gas reserves that will be commercially productive. In addition, the
costs of drilling, completing and operating wells are often uncertain, and
drilling may be delayed or canceled as a result of many factors, including
unacceptably low oil and natural gas prices, availability of drilling rigs, oil
and natural gas property title problems, government regulation, inclement
weather conditions and financial instability of third-party operators and
working interest owners. Need to Replace Reserves.Our future success depends to a significant degree
upon our ability to continue to find,
develop or acquire additional oil and gas reserves that are economically
recoverable. Unless we replace the reserves that we produce through successful
exploration, exploitation or acquisition, our proved reserves will decline.
Additionally, approximately 30% of our total proved reserves at December 31,
2003 were undeveloped. Recovery of such reserves will require significant
capital expenditures and successful drilling and/or recompletion operations.
There can be no assurance that we will be successful in our future efforts to
develop our proved reserves or replace our production. Acquisitions Risks.We continually evaluate opportunities for property or
corporate acquisitions that could enhance our business. Acquisitions of
properties or companies involve assessments of several factors, including
recoverable reserves, future oil and gas prices, future capital and operating
costs, and potential environmental and other liabilities. Such assessments
incorporate estimates and projections that are inherently imprecise and
uncertain. In connection with any future acquisitions, we would intend to
perform a review of the subject properties consistent with industry practices.
However, such review will not reveal all existing or potential problems nor
will it permit us to become sufficiently familiar with the properties to fully
assess their deficiencies and capabilities. Inspections may not always be
performed on every property and environmental problems are not necessarily
observable even when an inspection is undertaken. Even when problems are
identified, the seller may be unwilling or unable to provide effective
contractual protection against all or part of the problems. Additionally,
significant acquisitions can change the nature of our operations and business
depending upon the character of the acquired properties, which may have
substantially different operating and geological characteristics or be in
different geographic locations than our existing properties. While it is our
current intention to continue to concentrate on acquiring properties with
development, exploitation and exploration potential located in our core
operating areas, we cannot assure you that in the future we will not decide to
pursue acquisitions or properties located in other geographic regions. To the
extent that such acquired properties are substantially different than our
existing properties, our ability to efficiently realize the economic benefits
of such transactions may be limited. We may not be able to successfully
integrate future property or corporate acquisitions. We seek to make selective
niche acquisitions of oil and gas properties, and we will pursue corporate
acquisitions that we believe will be accretive. However, integrating acquired
properties and businesses involves a number of special risks. These risks
include the possibility that management may be distracted from normal business
concerns by the need to integrate operations and systems and in retaining and
assimilating additional employees. Any of these or other similar risks could
lead to potential adverse short-term or long-term effects on our operating
results. Dependence On Transportation Facilities Owned by Others. Our business depends
on transportation facilities owned by others. The marketability of our oil and
gas production, and the net prices received for such production, depend in part
on the availability, proximity and capacity of pipeline systems or
processing facilities owned by third
parties. The unavailability of, or lack of available capacity on, these systems
and facilities could result in curtailment of production, the delay or
discontinuance of development plans for properties, and/or reduced price
realizations for production. Although we have some contractual control over the
transportation of our product, material changes in these business relationships
or market conditions could 22




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significantly affect our operations. Federal and
state regulation of oil and gas production and transportation, tax and energy
policies, changes in supply and demand, pipeline pressures, damage to or
destruction of pipelines and general economic conditions could adversely affect
our ability to produce, gather and transport oil and natural gas. Derivatives.Part of Primas business strategy is to periodically use
commodity futures contracts, including price and basis swaps, collars and
options, to mitigate the impact of the volatility of oil and natural gas prices
on a portion of our production and gas marketing activities. In certain
circumstances, significant reductions in production caused by unforeseen
events, or insufficient correlation between a derivative and the market prices
that we receive for our production, could require us to make payments under
such agreements even though such payments are not offset by revenues from
production. To reduce these risks, we generally enter into derivatives for only
a portion of our projected production and utilize derivatives closely
correlated with our price realizations unless we believe market conditions to
fix basis spreads are unfavorable. At times, however, we may decide to enter
into derivatives contracts for volumes that match or exceed our projected total
production, or contracts that increase, rather than decrease, our exposure to a
decline in oil and gas prices or expansion of basis differentials. We would
consider establishing such positions if our analyses lead us to believe that
prices are likely to move in a manner that would generate gains from the
positions. Derivative positions for volumes greater than our expected
production, or which would increase our exposure to a decline in oil and gas
prices or expansion of basis differentials, would be speculative and would be
limited in size to an amount that, in managements judgment would
not be material to our balance sheet taken as a whole, but they might have a
significant positive or negative impact on reported net earnings. Derivatives positions might also prevent Prima from receiving the full
advantage of increases in oil or natural gas prices, and could expose us to
risk of financial loss should a counterparty to one or more of our derivatives
contracts fail to perform. The terms of our hedging agreements may also require
that we furnish cash collateral, letters of credit or other forms of
performance assurance in the event that mark-to-market calculations result in
settlement obligations by us to the counterparties. Such performance assurance
could encumber our liquidity and capital resources. In accordance with
Statement of Financial Accounting Standards (SFAS) No. 133, we record the fair
market value of each derivative position as an asset or liability. Changes in
the fair market value of our derivatives positions could result in significant
fluctuations in net income and stockholders equity from period to period. Capital Requirements. We anticipate continuing to make substantial
expenditures to find, develop, acquire and produce oil and gas reserves. We
expect to have sufficient cash provided by operating activities and from
available net working capital to fund planned capital expenditures in 2004.
However, we have not established a line of credit to provide additional capital
to respond to new opportunities. While we believe that we could arrange for
borrowings or issuance of securities to fund such opportunities, should lower
oil and gas prices or operating difficulties result in our cash flow from
operations being less than expected or if capital markets were to deteriorate,
we may be unable to obtain additional funds to expand our business. Demand For Oilfield Services.Our oilfield services operations are dependent
on the level of demand in our operating markets. Both short- and long-term
trends in oil and gas prices affect demand. Because oil and gas prices are
volatile, the level of demand for our services can also be volatile. Although
we utilize our service companies in our oil and gas operations, the substantial
majority of the demand for their services is dependent on third parties. In
addition to oil and gas prices, other factors that can influence activity
levels for our oilfield service operations include competition, our reputation,
availability of labor, and weather. Further, activity levels in the areas in
which we operate can be impacted by the attractiveness of oil and gas
investment opportunities in the area relative to other oil and gas investment
opportunities. Competition.We compete with numerous other companies and individuals in
virtually all facets of our business, including many that have significantly
greater resources than we do. Such competitors may be able to pay more than
Prima for desirable assets and experienced personnel. Many competitors may also
have greater technical resources and increased staff to evaluate and develop
investment opportunities than do we. Domestic oil and gas companies must also
compete with imported oil and natural gas, coal, nuclear energy, hydroelectric
power and other forms of energy. Operating Hazards and Uninsured Risks.The oil and gas business involves a
variety of operating risks, including risks of fire, explosions and well
blow-outs, as well as risks associated with production, marketing, and general
economic conditions. We maintain insurance against some, but not all, of these
risks, any of which could result in substantial losses. There can be no
assurance that insurance carried would be adequate to cover any losses or
exposure to liabilities. There also can be no assurance that in the future
insurance will continue to be available at premium levels that justify its
purchase, or whether it will be available at all. 23




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Government Regulation.Federal, state and local governments extensively
regulate all aspects of the oil and gas industry. Regulations govern such
things as drilling permits, environmental protection and pollution control,
spacing of wells, the unitization and pooling of properties, water use and
disposal, production, royalty rates and various other matters including
taxation. As an example, our exploration and development plans for Powder River
Basin CBM properties are dependent to a significant degree upon receipt of
drilling permits from the federal Bureau of Land Management. On April 30, 2003,
the BLM issued a final Record of Decision in relation to its Environmental
Impact Statement regarding future CBM drilling in the Powder River Basin. We
have filed permit applications for approval by the BLM under the terms of the
new EIS, but cannot predict whether or when such permits will be granted.
Another instance of governmental regulatory oversight affecting Prima is the
Wyoming Department of Environmental Qualitys responsibility for considering
applications for water discharge permits.
Permits to discharge water on the surface had generally been attainable early
in development of CBM in the Powder River Basin, but it is expected that, in
the future, the Wyoming DEQ will generally require water management techniques
other than surface discharge, such as collection in containment reservoirs or
treating, which would increase development and operating costs. Additionally,
the Colorado Oil & Gas Conservation Commission has promulgated regulations to
protect ground water, conserve soil, provide for site reclamation, ensure
setbacks in urban areas, generally promote safety concerns and mandate
financial assurance for companies in the industry. Oil and gas industry
legislation and administrative regulations are periodically changed for a
variety of political, economic and other reasons. These regulations may
substantially increase the cost of doing business and sometimes prevent or
delay the commencement or continuance of any given exploration or development
project and may adversely affect the economics of capital projects. At the
present time, we cannot predict what effects current and future proposals or
changes in existing laws or regulations will have on operations, estimates of
oil and natural gas reserves, or future net revenues. The costs of complying,
monitoring compliance and dealing with the agencies that administer these
regulations can be significant. We could also be subject to substantial
penalties if we fail to comply with any regulation. Environmental Regulation.Our operations are subject to complex and frequently
changing environmental laws and regulations adopted by federal, state and local
governmental authorities. New laws or regulations, or changes to current
practices, could have a material adverse effect on our business. We will
continue to be subject to uncertainty associated with new regulatory
interpretations and inconsistent interpretations between state and federal
agencies. We could face significant liabilities to the government and third
parties for discharges of oil, natural gas or other pollutants into the air,
soil or water, and we might need to spend substantial amounts on
investigations, litigation and remediation. We could face material indemnity
claims with respect to properties we own or have owned. We cannot be sure that
existing environmental laws or regulations, as currently interpreted or
enforced, or as they may be interpreted, enforced or altered in the future,
will not materially adversely affect our results of operations and financial
condition. Key Personnel.We depend on the continued services of our executive officers
and other key employees. Loss of the services of any of these people could have
a material adverse effect on our operations. We currently do not have
employment agreements with any of our key employees, including Richard H.
Lewis, who serves as Primas Chief Executive Officer, President and Chairman of
the Board of Directors. 
 ITEM 3.     LEGAL PROCEEDINGS We are a party to various legal proceedings arising in the ordinary course of
its business. As of the date of the filing of this report, none of these is
expected to have a material adverse impact on our financial position or results
of operations. 
 ITEM 4.     SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of our security holders during the quarter
ended December 31, 2003. 24




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PART II 
 ITEM 5.     MARKET FOR THE REGISTRANTS COMMON STOCK AND RELATED STOCKHOLDER MATTERS (a) Market Information  Primas common stock trades on the Nasdaq National Market under the symbol
PENG. The following table sets forth the Nasdaq high and low sales prices
for our common stock for each quarterly period during the years ended December
31, 2003 and 2002. Year Ended December 31, 2003
    
    HIGH
    
    LOWQuarter Ended December 31, 2003
    
    $
    37.50
    
    
    $
    25.38Quarter Ended September 30, 2003
    
    
    27.01
    
    
    
    20.47Quarter Ended June 30, 2003
    
    
    24.30
    
    
    
    18.02Quarter Ended March 31, 2003
    
    
    24.00
    
    
    
    18.27Year
Ended December 31, 2002Quarter Ended December 31, 2002
    
    $
    24.49
    
    
    $
    20.38Quarter Ended September 30, 2002
    
    
    23.00
    
    
    
    15.70Quarter Ended June 30, 2002
    
    
    26.34
    
    
    
    20.23Quarter Ended March 31, 2002
    
    
    26.46
    
    
    
    19.10
 The above quotations are from sources believed to be reliable. They do not
include any retail mark-ups, mark-downs or commissions and may not represent
actual transactions. On February 27, 2004, the closing sale price for our
common stock was $33.79 per share. (b) Holders of Record  Our common stock holders of record at February 27, 2004 totaled 794. (c) Dividends  Holders of common stock are entitled to receive such dividends as may be
declared by our Board of Directors. No cash dividends were declared or paid in
2003, 2002 or 2001. Future cash dividends, if any, will be evaluated based,
among other things, on our operating results, capital requirements and
financial condition at the time. (d) Securities Authorized for Issuance Under Equity Compensation Plans 
The following table includes information regarding Primas equity compensation
plans as of the year ended December 31, 2003: (a)
    
    (b)
    
    (c)Number of securitiesremaining availablefor future issuanceNumber of securities
    
    Weighted-average
    
    under equityto be issued upon
    
    exercise price of
    
    compensation plansexercise of
    
    outstanding
    
    (excluding securitiesoutstanding options,
    
    options, warrants
    
    reflected inPlan Category
    
    warrants and rights
    
    and rights
    
    column (a))Equity compensation plans approved by
security holders
    
    
    979,075
    
    
    $
    17.51
    
    
    
    1,070,125Equity compensation plans not approved
by security holders
    
    
    
    
    
    
    
    
    
    
    Total
    
    
    979,075
    
    
    $
    17.51
    
    
    
    1,070,125
 25




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##### Table of Contents



ITEM 6.     SELECTED FINANCIAL DATA The following table sets forth a summary of selected consolidated
financial data. This data should be read in conjunction with Managements
Discussion and Analysis of Financial Condition and Results of Operations and
the Consolidated Financial Statements and notes thereto. Years Ended December 31,2003
    
    2002
    
    2001
    
    2000
    
    1999(in thousands, except per share amounts)Income Statement Data:Revenues:Oil and gas sales
    
    $
    58,622
    
    
    $
    25,785
    
    
    $
    44,548
    
    
    $
    44,437
    
    
    $
    20,644Gains (losses) on derivative
instruments, net
    
    
    2,320
    
    
    
    (2,918
    )
    
    
    6,435
    
    
    
    
    
    
    
    Oilfield services
    
    
    8,577
    
    
    
    8,326
    
    
    
    8,090
    
    
    
    6,278
    
    
    
    4,974Trading revenues
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,318Interest, dividend and other
    
    
    635
    
    
    
    597
    
    
    
    1,214
    
    
    
    1,464
    
    
    
    1,28670,154
    
    
    
    31,790
    
    
    
    60,287
    
    
    
    52,179
    
    
    
    29,222Expenses:Depletion of oil and gas properties
    
    
    14,956
    
    
    
    9,710
    
    
    
    9,190
    
    
    
    6,150
    
    
    
    4,650Depreciation of other property
    
    
    1,058
    
    
    
    1,088
    
    
    
    1,039
    
    
    
    1,054
    
    
    
    817Lease operating expense
    
    
    3,619
    
    
    
    3,076
    
    
    
    3,295
    
    
    
    2,623
    
    
    
    2,012Ad valorem and production taxes
    
    
    5,783
    
    
    
    2,116
    
    
    
    3,344
    
    
    
    3,421
    
    
    
    1,765Oilfield services
    
    
    6,510
    
    
    
    6,490
    
    
    
    5,812
    
    
    
    4,585
    
    
    
    3,377General and administrative
    
    
    3,321
    
    
    
    3,255
    
    
    
    3,559
    
    
    
    2,916
    
    
    
    1,712Impairment of natural gas swap
    
    
    
    
    
    
    
    
    
    
    241
    
    
    
    
    
    
    
    Trading costs
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,82735,247
    
    
    
    25,735
    
    
    
    26,480
    
    
    
    20,749
    
    
    
    17,160Income before income taxes and
cumulative effect of change in
accounting principle
    
    
    34,907
    
    
    
    6,055
    
    
    
    33,807
    
    
    
    31,430
    
    
    
    12,062Provision for income taxes
    
    
    11,515
    
    
    
    825
    
    
    
    10,650
    
    
    
    9,535
    
    
    
    3,035Net income before cumulative effect of
change in accounting principle
    
    
    23,392
    
    
    
    5,230
    
    
    
    23,157
    
    
    
    21,895
    
    
    
    9,027Cumulative effect of change in
accounting principle
    
    
    403
    
    
    
    
    
    
    
    611
    
    
    
    
    
    
    
    Net income
    
    $
    23,795
    
    
    $
    5,230
    
    
    $
    23,768
    
    
    $
    21,895
    
    
    $
    9,027Basic net income per share before
cumulative effect adjustment
    
    $
    1.82
    
    
    $
    0.41
    
    
    $
    1.82
    
    
    $
    1.72
    
    
    $
    0.70Cumulative effect adjustment
    
    
    0.03
    
    
    
    
    
    
    
    0.05
    
    
    
    
    
    
    
    Basic net income per share
    
    $
    1.85
    
    
    $
    0.41
    
    
    $
    1.87
    
    
    $
    1.72
    
    
    $
    0.70Diluted net income per share before
cumulative effect adjustment
    
    $
    1.79
    
    
    $
    0.40
    
    
    $
    1.75
    
    
    $
    1.65
    
    
    $
    0.69Cumulative effect adjustment
    
    
    0.03
    
    
    
    
    
    
    
    0.05
    
    
    
    
    
    
    
    Diluted net income per share
    
    $
    1.82
    
    
    $
    0.40
    
    
    $
    1.80
    
    
    $
    1.65
    
    
    $
    0.69Balance Sheet Data (end of period):Total assets
    
    $
    177,217
    
    
    $
    141,927
    
    
    $
    135,444
    
    
    $
    104,900
    
    
    $
    72,665Net property and equipment
    
    
    106,132
    
    
    
    93,377
    
    
    
    96,005
    
    
    
    70,597
    
    
    
    44,467Long-term debt
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Stockholders equity
    
    
    130,676
    
    
    
    107,266
    
    
    
    101,740
    
    
    
    80,298
    
    
    
    58,908Working capital
    
    
    56,148
    
    
    
    35,954
    
    
    
    28,122
    
    
    
    25,678
    
    
    
    21,408
 26




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ITEM 7.     MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS This Item 7 contains forward-looking statements which are made pursuant to
the safe harbor provisions of the Private Securities Litigation Reform Act of
1995. These statements include, without limitation, statements relating to
liquidity, financing of operations, continued volatility of oil and natural gas
prices, estimates of future production and net cash flows attributable to
proved reserves, future expenditures, and other such matters. The words
anticipates, believes, expects, intends or estimates and similar
expressions identify forward-looking statements. Prima does not undertake to
update, revise or correct any of the forward-looking information. Readers are
cautioned that such forward-looking statements should be read in connection
with Primas disclosures under the heading: Cautionary Statement for the
Purposes of the Safe Harbor Provisions of the Private Securities Litigation
Reform Act of 1995. The following discussion is intended to assist in understanding our financial
position and results of operations for the three-year period ended December 31,
2003. The Consolidated Financial Statements and notes thereto should be
referred to in conjunction with this discussion. 
 Critical Accounting Policies and Estimates Our discussion of financial condition and results of operation are based upon
the information reported in our consolidated financial statements. The
preparation of these financial statements requires us to make assumptions and
estimates that affect the reported amounts of assets, liabilities, revenues and
expenses as well as the disclosure of contingent assets and liabilities at the
date of our financial statements. We base our decisions on historical
experience and various other sources that are believed to be reasonable under
the circumstances, but actual results may differ from our estimates due to
changing business conditions or unexpected developments. Policies and estimates
that we believe are critical to understanding our business operations and
results of operations are detailed below. For additional information on our
significant accounting policies, see Notes to Consolidated Financial
Statements, particularly Note 1. Estimates of Proved Oil and Gas Reserves  Reserves evaluation is a subjective
process of estimating underground accumulations of oil and gas that cannot be
directly measured and the economic recoverability of such reserves. There are
significant uncertainties inherent in the process, and the accuracy of any
reserve estimate is a function of the quality of available data, and of the
engineering and geological interpretations and judgments made. Estimates of
economically recoverable oil and gas reserves and related future net cash flows
necessarily depend upon a number of variable factors and assumptions, such as
projected oil and gas prices, operating costs, severance taxes and development
costs, all of which may in fact vary considerably from actual future results.
Any significant change in these assumptions, or variances from projected well
performance, could materially affect the estimated quantity and value of proved
reserves, which could affect the carrying value of Primas oil and gas
properties and the amount of depletion expense recorded as reserves are
produced and sold. Estimated reserves attributed to undeveloped locations are
particularly sensitive to changes in assumptions based on new data from
analogous properties or adjustments to projected future prices or costs. Actual
production, revenues and expenditures with respect Primas reserves will likely
vary from estimates and such variances may be material. Full Cost Method  We use the full cost method of accounting for our oil and
gas activities. Under this method, all costs incurred in the acquisition,
development and exploration of oil and gas properties are capitalized into cost
centers that are established on a country-by-country basis (we have a single
cost center for the United States). Such amounts include the costs of drilling
and equipping productive wells, dry hole costs, lease acquisition costs, delay
rentals, and pre-production operating costs incurred while de-watering CBM
wells. Capitalized costs also include salaries, employee benefits, costs of
consulting services and other expenses that are directly related to
acquisition, development and exploration activities. Costs associated with
production and general corporate activities are expensed in the period
incurred. Full Cost Ceiling Limitation  Under the full cost method, we are subject to
quarterly calculations of a limitation, or ceiling, on the amount that can be
capitalized on our balance sheet for oil and gas properties. If net capitalized
costs 27




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exceed the cost center ceiling, a writedown in the carrying value of the
properties must be recorded in the amount of the excess. If required, such a
non-cash charge would reduce earnings in the period of occurrence but would
result in lower depletion expense in future periods. The discounted present
value of our proved reserves is a major component of the ceiling calculation
and requires subjective judgments. Given the volatility of oil and gas prices,
it is likely that our estimate of discounted present value of future net cash
flows from proved reserves will change in the future. If oil and gas prices
decline, even if only for a short period of time, or if we have downward
revisions to our estimated proved reserves, it is possible that writedowns of
our oil and gas properties could occur. While the quantities of proved reserves
require substantial judgment, the assumptions for future prices of oil and gas
that are used to calculate the present value of future cash flows from proved
reserves do not require judgment. Rules generally prescribe that the ceiling
test calculation be based on oil and gas prices in effect as of the balance
date of the ceiling test, held constant in the future, and are not based on our
assessment of future prices. Under certain circumstances, however, improvements
in prices shortly after the balance sheet date of a ceiling test may be
utilized to avoid recording a writedown that would otherwise be required. Unevaluated Costs  Costs associated with unevaluated leasehold acreage and
wells that have not yet been determined to be economically productive or
non-productive are not initially included in our amortization base. Leasehold
and associated costs are either transferred to our amortization base with the
costs of drilling related wells or are assessed quarterly for possible
impairment or reduction in value, with costs transferred to the amortization
base if estimated fair value is below cost. The decision to withhold costs from
amortization and the timing of transferring such costs into the amortization
base involves a significant amount of judgment and may be subject to
changes over time based on several factors, including our drilling plans,
availability of capital, project economics, results of nearby drilling, and
recent transactions involving acreage in the area. Other Property and Equipment  Oilfield service equipment and other property
and equipment are carried at cost. Renewals and betterments are capitalized,
while repairs and maintenance are expensed. Capitalized costs are depreciated
using the straight-line method over the estimated useful lives of the assets.
The carrying value of property and equipment is reviewed for possible
impairment whenever events or changes in circumstances indicate that the
carrying amount may not be recoverable. Assets are determined to be impaired if
a forecast of undiscounted estimated future net operating cash flows directly
related to the asset, including disposal value if any, is less than the
carrying amount of the asset. If any asset is determined to be impaired, the
loss is measured as the amount by which the carrying amount of the asset
exceeds its fair value. An estimate of fair value is based on the best
information available, including prices for similar assets. Changes in such
estimates could result in a reduction in the carrying value of our property and
equipment. Asset Retirement Obligations  Our asset retirement obligations (ARO)
primarily represent the estimated present value of amounts we project will be
incurred to plug, abandon and remediate our oil and gas properties at the end
of their productive lives, in accordance with currently applicable laws and
regulations. Statement of Financial Accounting Standards No. 143, which we
adopted effective January 1, 2003, requires that an obligation to retire a
tangible long-lived asset be recognized as a liability in the period in which
it is incurred and becomes determinable, with an offsetting increase in the
carrying amount of the associated asset. The fair value of the ARO is measured
using expected future cash outflows discounted at an estimated credit-adjusted
risk-free interest rate applicable to Prima. The cost of the tangible asset,
including the initially recognized ARO, is reflected in the computation of
depletion expense relating to our oil and gas properties. In addition,
accretion expense is recognized over time, as the discounted ARO liability is
accreted to its expected settlement cost. Inherent in the present value
calculation of ARO are numerous assumptions and estimates, including ultimate
settlement amounts, settlement timing, inflation factors, and applicable
discount rates. To the extent future revisions to these assumptions impact the
present value of the existing ARO liability, a corresponding adjustment is made
to the oil and gas property balance. Recognition of Oil and Gas Sales Revenue  We derive a significant portion of
our revenue from the sale of produced natural gas and crude oil. We record
revenue in the month in which production is delivered to a purchaser, based on
estimates of sales volumes and the applicable unit prices. Purchaser
remittances are generally received between 20 and 40 days after the end of the
month in which production occurs, but can take longer for properties operated
by other operators or initially for new wells. We use our knowledge of our
properties, including historical performance, plus 28




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published spot market prices
and other data, as the basis for our estimates of oil and gas sales revenue.
Because we operate virtually all of our significant producing oil and gas
properties, we generally have certain gross production data available on a
timely basis for wells that account for most of our production. Such field data
generally provide reasonably reliable approximations of sales volumes, subject
to adjustments for fuel use, metering variances, and other factors. As such,
variances between our estimated sales volumes and actual amounts sold have
historically been modest. Estimated unit prices are frequently determinable, or
can be closely estimated, at the time production is delivered or shortly
thereafter. In instances where the price we receive for gas production is
determined by percentage-of-proceeds contracts (such as for our D-J Basin
wells), our realized prices are dependent on sales prices received for dry gas
and natural gas liquids by the operator of the liquid extraction plants and our
estimates are prone to increased error, but these have also generally been
modest in the past except during periods of exceptional short-term price
volatility. All adjustments for differences between estimated and actual sales
volumes or prices are recorded in the period in which such variances are
discovered through receipt of payment or other data. Fair Value of Derivative Instruments  We periodically enter into derivatives
contracts, primarily for the purpose of mitigating risks related to the prices
we will receive for future oil and gas production. The fair value of these
derivatives can be very volatile, primarily due to the high volatility of the
underlying commodity prices. The estimated fair values of derivative
instruments are recorded on our consolidated balance sheets. For derivatives
that dont qualify for hedge accounting treatment, changes in fair value are
recorded as gains or losses in the income statement as they occur. For
instruments that qualify for hedge accounting treatment, changes in fair value
net of related income taxes are recorded directly to stockholders equity until
the hedged production is sold, at which time realized gains or losses are
included in reported oil and gas sales revenue. In determining the amounts to
be recorded before derivatives positions are settled, we must estimate the fair
values of such contracts. Our estimates are based upon various factors,
including contract settlement dates, specified volumes and prices, quoted
closing prices on the NYMEX or over-the-counter and, where applicable,
volatility and the time value of options. For fixed-price contracts, such
prices are compared to futures prices estimated as of the valuation date, and
the resulting projected future cash inflows or outflows are discounted to
calculate the fair value of the derivative positions. The calculation of the
fair value of collars and floors may require the use of the Black-Scholes
option-pricing model, although market quotations are used to establish fair
value when available. We frequently validate our valuation estimates using
independent third party quotations. Depletion  The capitalized costs of our evaluated oil and gas properties,
plus estimated future capital costs related to our proved reserves, are
amortized on a unit-of-production method based on our estimate of total proved
reserves. The quantities of estimated proved oil and gas reserves and amounts
of future development costs are significant components of amortization, and
revisions in such estimates would alter the amount of depletion expense
recorded per unit of production. In the absence of offsetting changes to
estimates, if estimated reserve volumes increase or decrease, then the
amortization rate per unit of production will change inversely; however, when
estimated future capital costs change, the amortization rate moves in the same
direction. Income Taxes  We provide for deferred income taxes on the difference between
the tax basis of an asset or liability and its carrying amount in our financial
statements. This difference will result in taxable income or deductions in
future years when the reported amount of the asset or liability is recovered or
settled, respectively. Our federal and state income tax returns are generally
not filed before the consolidated financial statements are prepared. We,
therefore, estimate the tax basis of our assets and liabilities at the end of
each period as well as the effects of tax rate changes, tax credits and net
operating loss carryforwards. Any differences between estimates we initially
used and amounts subsequently determined to be appropriate are recorded in the
period in which our estimate is revised. 29




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Liquidity and Capital Resources Our principal sources of liquidity have been internal generation of cash flow
from operations, proceeds from occasional asset sales, and existing net working
capital. Additional potential sources of capital include borrowings and
issuances of common stock or other securities. Net cash provided by operating activities totaled $46,149,000 in 2003, compared
to $21,524,000 in 2002 and $43,008,000 in 2001. Our net working capital
increased from $35,954,000 at the end of 2002 to $56,148,000 on December 31,
2003. Our cash equivalents and short-term investments also increased in 2003,
from $38,007,000 at the beginning of the year to $57,192,000 at the end of
2003. Prima had no outstanding long-term debt, capital lease agreements or
guarantees at either date. Our operating lease agreements, and other
commitments and contingencies, are disclosed in
Note 8 of the Notes to Consolidated Financial Statements. Primas revenues and cash flows are substantially derived from oil and gas
sales, which are dependent on oil and gas sales prices and production volumes.
Historically, oil and gas sales prices have been volatile and our average price
realizations in 2003 were 56% higher, on an Mcfe basis, than in 2002. Combined
with a 46% increase in net production volumes, these improved prices led to a
127% growth in Primas oil and gas sales revenue from 2002 to 2003, from
$25,785,000 to $58,622,000, including hedging effects. The increase in our oil
and gas sales revenue was the primary factor accounting for higher earnings and
cash flow in 2003. Primas future revenues will continue to be significantly
affected by volatility in oil and gas prices. As further discussed below,
prices for oil and Rocky Mountain natural gas to-date in 2004 and as reflected
in futures markets for the balance of the year are modestly higher than in
2003, and we are projecting an increase of up to 5% in Primas net production
volumes. Our capital investments on oil and gas properties totaled $26,856,000 during
2003, compared to $22,252,000 in 2002 and $35,248,000 in 2001. During
2003, we expended $12,409,000 for exploitation and development of
properties in the D-J Basin, $8,506,000 for costs incurred on Powder
River Basin CBM properties, $3,016,000 for exploration and
development of other properties, $801,000 for acreage costs, and
$2,124,000 of capitalized overhead. Additional uses of funds in 2003 included $1,422,000 for other fixed assets,
predominantly oilfield service equipment and facilities, and $815,000 for
treasury stock repurchases net of proceeds from stock option exercises. Excluding acquisitions, Primas preliminary plans for 2004 provide for capital
investments of approximately $45 million. Our current projected allocation for
these capital investments is approximately as follows: $14 million for
development of properties in the D-J Basin; $24 million for exploitation of CBM
properties in the Powder River Basin; and $7 million for other costs, including
higher-risk exploration activities, acreage acquisitions, oilfield services
equipment, and capitalized overhead. This budget is preliminary and may be
adjusted upward or downward in response to new developments during the year. Expected 2004 activities include: drilling approximately 35 wells and
re-fracturing or re-completing approximately 50 wells in the D-J Basin;
drilling an estimated 150 CBM wells in the Powder River Basin and hooking up
most of these and 130 previously-drilled CBM wells; participation in up to six
wells in the Cave Gulch area; and continued exploratory operations on Primas
Coyote Flats Prospect in Utah and the Merna Prospect in the Green River Basin.
A test well may also be initiated this year on the Christmas Meadows prospect
in the Table Top Unit, along the Overthrust Belt in northeastern Utah. These
activities are dependent on securing drilling permits and other required
regulatory approvals, among other factors. The CBM activities planned for 2004 include additional drilling to further
develop the Porcupine-Tuit field, which currently produces from a relatively
shallow Wyodak coal, and operations to evaluate and develop deeper unproved
coals within our Kingsbury, Cedar Draw, North Shell Draw and Wild Turkey
project areas. We anticipate that these deeper coals will need to be
de-watered for a period of time, perhaps a year or more, before significant
gas production rates are established. As a result, these activities may not
generate significant additions to proved reserves in the current year, but 30




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if our expectations are met
they would be expected to result in additions to proved reserves and increased
production over the following two to three years. We intend to fund these planned capital investments with cash flow from
operations and available working capital. Our expectations as to cash provided by operating activities are
predicated on projections of oil and gas production volumes and oil and gas
prices, among other factors. Although not budgeted, we also continue to
seek acquisitions that we believe will enhance our existing businesses. An acquisition could be consummated
using cash reserves, bank borrowings, and/or through issuance of debt or
equity securities. Without contributions from new exploration or acquisitions, we are projecting
that our current year oil and gas production will total between 15.6 Bcfe and
16.1 Bcfe, which compares to 15.4 Bcfe in 2003. Approximately 40% of current
year production is projected to come from Powder River Basin CBM properties.
Most of this is expected to be derived from currently producing Porcupine-Tuit
wells that will exhibit depletion-related declines during the year.
Contributions from new wells in the Powder River Basin are expected to begin
during the third quarter and increase as de-watering occurs. Overall,
excluding acquisitions or discoveries, Primas net production is projected to
decline during 2004 until late in the year when production from new CBM wells
is expected to ramp up. Natural gas is currently expected to account for more than 80% of Primas total
oil and gas production in 2004. Gas prices have been strong during the past
several months in response to a number of factors, including recent declines in
North American natural gas production and relatively high prices for oil, which
can be substituted for natural gas in some applications if economically
advantageous. As of February 27, 2004, average prices for the 2004 CIG monthly index that
have been published (January through March) plus the average of the quoted
prices for the remainder of 2004 CIG contract months in over-the-counter
futures markets combine to average $4.76 per MMBtu of natural gas. These
compare to the average closing prices for the CIG monthly index during 2003 of
$4.04 per MMBtu of natural gas. There is no assurance, however, that prices
reflected in futures markets will actually be realized, except to the extent
that fixed price or hedging contracts are entered into. As of the close of business on February 27, 2004, we had open contracts for
forward sales of 700,000 MMBtu of natural gas per month for the months of April
2004 through October 2004, at an average NW Rockies (Opal location) price of
$4.41 per MMBtu. An additional 350,000 MMBtu of natural gas have been
forward-sold for November 2004, at an average CIG price of $4.00 per MMBtu.
Both of these indices are highly correlated with changes in Primas net
well-head price realizations and are expected to represent effective hedges.
With respect to
crude oil, as of February 27, 2004 we had entered into forward-sale NYMEX
contracts covering a total of 95,000 barrels applying to the contract months of
April through September 2004, at an average price of $31.27 per barrel. These
are also assessed as effective hedges. Combined, these positions total
approximately 5,820,000 Mcfe of volumes relating to the balance of 2004. Prima
has realized net losses totaling $442,000 on effective and ineffective hedging
contracts closed for the months of January through March 2004. In 2001, Primas Board of Directors approved a repurchase program of up to 5%
of our common stock then outstanding, or approximately 640,000 shares. As of
December 31, 2003, approximately 291,000 shares remained subject to repurchase
under this authorization. 31




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Results of Operations As noted, our primary source of revenues is the sale of oil and natural gas
production. Because of significant fluctuations in oil and natural gas prices
and variances in production volumes, our operating results for any period are
not necessarily indicative of future operating results. Oil and gas prices have
historically been volatile and are likely to continue to be volatile. Prices
are affected by, among other things, market supply and demand factors, market
uncertainty, and actions of the United States and foreign governments and
international cartels. These factors are beyond our control. Our revenues, cash
flows, earnings and operations are adversely affected when oil and gas prices
decline. Natural gas has typically represented approximately 80% of our total
oil and gas production mix. After reaching record high levels early in 2001,
gas prices declined significantly until early 2003 when prices again approached
record levels, and prices have generally remained at favorable levels into
2004. These price movements have significantly impacted our operating results,
as more fully described below. We cannot accurately predict future oil and
natural gas prices, but historically oil and gas supply and demand have
responded to changes in price levels to correct from short-lived extreme levels
of high or low prices. In addition to factors affecting global or national markets for oil and natural
gas, our business is subject to regional influences on natural gas markets. Gas
production in the Rocky Mountain area, where Primas producing properties are
located, generally exceeds regional consumption needs and the surplus is
transported via pipelines to other markets. Rocky Mountain gas has typically
sold for a lower price than gas produced in the Gulf Coast region or in areas
closer to major consumption markets that rely on gas delivered from outside the
region. The size of the discount has varied widely based on seasonal factors,
structural factors, and other supply and demand influences. From 1991 through
2003, CIG gas prices have averaged approximately $0.65 per MMBtu less than the
average for gas at Henry Hub, but the amount of this discount has ranged on an
annual basis between $0.26 (1999) and $1.40 (2003), and monthly variances in
index prices have ranged between an $0.11 premium (January 1993) and a $4.27
discount (March 2003). Basis differentials widened considerably beginning in
May 2002, resulting in depressed regional prices for Rocky Mountain gas for
several months despite relatively strong gas prices in other areas of the
country. In early 2003, Rocky Mountain gas prices improved but basis
differentials remained wide, as prices in other regions increased as much or
more. Beginning in May 2003, when significant expansions in pipeline capacity
were completed and placed in service, basis differentials began to
significantly narrow. NYMEX-versus-CIG differentials during the four calendar
quarters of 2003 averaged sequentially $2.82, $1.51, $0.81 and $0.47, and
recent forward market quotes indicate expectations of average differentials
during the next year of approximately $0.70 to $0.80. Future basis
differentials, which we expect to have an important impact on our operating
results, may vary substantially from the current indications on futures markets
due to a number of factors, including but not limited to, the timing, size and
location of pipeline expansions and the timing, size and location of changes in
regional gas deliverability. Since historically most of Primas revenues have been derived from oil and gas
sales, our profitability has been primarily determined by oil and gas
production volumes and average margins realized per unit of production. Oil and
gas prices, over which we have little control, can vary significantly from
period to period and are a key determinant of profitability. We also look at
all of our costs, other than those directly related to oilfield service
operations, on a per-Mcfe basis. Our average prices and costs per Mcfe for the
last three years are summarized in a table below. Generally, on a per unit
basis: ad valorem and production taxes have varied with the level of oil and
gas prices, at 8% to 10%; lease operating expenses have been relatively stable,
at $0.24 to $0.29 per Mcfe; and general and administrative expenses have varied
inversely with production volumes, ranging from $0.22 to $0.31 per Mcfe. The
remaining cost that we consider in measuring margins for oil and gas production
is depletion expense, which represents the average per-unit capital investment
for our proved oil and gas reserves, including net
costs incurred to-date plus estimated future development costs related to such
proved reserves. Depletion expense has increased during the past three years,
from an average $0.77 per Mcfe in 2001 to $0.96 per Mcfe in 2003, including
$1.05 per Mcfe in the fourth quarter of the year based on year-end estimated
proved oil and gas reserves. These increases reflect higher finding and
development costs than our earlier historical average, including higher
estimates of future development costs per Mcfe for proved undeveloped reserves.
These developments reflect a combination of factors including, among others: 32




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##### Table of Contents




    
    generally higher costs for leaseholds and oilfield
services in a high commodity price environment;
    
    elective development of locations on the periphery of the
established productive area in the D-J Basin, with smaller
reserve targets; and
    
    limited proved reserves additions to date in the Powder
River Basin CBM area, as work on federal acreage has been
deferred pending resolution of matters relating to the EIS, and
as CBM development has gradually moved from the primary areas
of initial development in the play toward the west where
Primas undeveloped lease holdings are concentrated. Primas margins generally remained strong, on average, during the three years
ended December 31, 2003, reflecting favorable oil and gas prices and combined
related costs at or below $1.80 per Mcfe (see table below). We expect our
future profitability to continue to be largely determined by commodity prices
and our success in growing reserves and production at reasonable average costs
per unit. There can be no assurance that future oil and gas prices will be
favorable or that we will be successful in adding reserves at an acceptable
cost and growing our production. Except in 2002, when we sold our Stones Throw CBM property two months into the
year while it was producing approximately 6,800 net Mcf per day, Primas net
production has grown each year since 1988, including a 46% improvement from
2002 to 2003. Proved reserves have not been increased during the past three
years though, as reserves were produced, properties were sold, estimates of
proved undeveloped CBM reserves were lowered pending accumulation of additional
data as industry activity in the area was slowed by regulatory matters, and
while Prima made limited investments in activities that would add new proved
reserves in the short term. During this three-year period, our net investments
in oil and gas properties represented approximately 76% of total cash provided
by operations and focused primarily on development of proved undeveloped
reserves and activities in the Powder River Basin CBM play and the Coyote Flats
prospect in Utah where operations are still ongoing to evaluate the properties.
We anticipate that these operations will continue to be among our most
important near-term activities undertaken for purposes of establishing new
proved reserves and expanding production, though favorable results cannot be
assured. The following table, which presents selected operating data, is followed by
further discussion of our results of operations for the periods indicated: 2003
    
    2002
    
    2001Proved reserves at end of year (Mcfe)
    
    
    125,796,000
    
    
    
    111,104,000
    
    
    
    135,586,000Production:Natural gas (Mcf)
    
    
    13,015,000
    
    
    
    8,343,000
    
    
    
    9,277,000Oil (barrels)
    
    
    401,000
    
    
    
    373,000
    
    
    
    431,000Total natural gas equivalents (Mcfe)
    
    
    15,421,000
    
    
    
    10,580,000
    
    
    
    11,863,000Revenue:Natural gas sales
    
    $
    45,911,000
    
    
    $
    16,413,000
    
    
    $
    33,392,000Oil sales
    
    $
    12,711,000
    
    
    $
    9,372,000
    
    
    $
    11,156,000Total oil and gas sales
    
    $
    58,622,000
    
    
    $
    25,785,000
    
    
    $
    44,548,000Avg. sales price (including hedging effects):Natural gas (per Mcf)
    
    $
    3.53
    
    
    $
    1.97
    
    
    $
    3.60Oil (per barrel)
    
    $
    31.71
    
    
    $
    25.14
    
    
    $
    25.88Total natural gas equivalents (per Mcfe)
    
    $
    3.80
    
    
    $
    2.44
    
    
    $
    3.76Expenses (per Mcfe):Depletion of
oil and gas properties
    
    $
    0.97
    
    
    $
    0.92
    
    
    $
    0.77Lease operating expense
    
    $
    0.23
    
    
    $
    0.29
    
    
    $
    0.28Ad valorem and production taxes
    
    $
    0.38
    
    
    $
    0.20
    
    
    $
    0.28General and administrative expense
    
    $
    0.22
    
    
    $
    0.31
    
    
    $
    0.30$
    1.80
    
    
    $
    1.72
    
    
    $
    1.63
 33




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2003 vs. 2002 For the year ended December 31, 2003, we reported net income of $23,795,000, or
$1.82 per diluted share, on revenues of $70,154,000. These amounts compare to
net income of $5,230,000, or $0.40 per diluted share, on revenues of
$31,790,000, for the year ended December 31, 2002. Total expenses, other than
income taxes, were $35,247,000 in 2003 compared to $25,735,000 in 2002.
Revenues increased $38,364,000 or 121%, expenses increased $9,512,000 or 37%,
and net income increased $18,565,000 or 355% in 2003. During 2003, we recognized $2,734,000 of total gains relating to oil and gas
derivatives, comprised of $414,000 of hedging gains that were included in our
reported oil and gas sales and $2,320,000 of separately reported gains on
derivative instruments that did not qualify for hedge accounting. The net gains
recognized on derivative instruments not qualifying for hedge accounting (which
consisted primarily of NYMEX gas swaps without corresponding swaps for Rocky
Mountain basis differentials) included related mark-to-market adjustments to
fair value during the year. Our revenues for 2002 included $3,376,000 of aggregate losses from oil and gas
derivatives, including hedging losses of $458,000 plus $2,918,000 of reported
losses on derivative instruments not qualifying for hedge
accounting. The $2,918,000 of losses on non-qualifying hedges included
$4,464,000 of net unrealized losses that primarily represented reversals of
unrealized mark-to-market gains recognized in the prior year. These reversals
occurred because mark-to-market gains on natural gas futures positions held at
December 31, 2001 were reduced as gas prices escalated in 2002 before the
contracts were settled. Oil and gas sales reported for 2003 totaled $58,622,000, compared to
$25,785,000 for 2002, an increase of 127%. The large improvement in such sales
was due to a 46% year-over-year increase in production volumes and a 56%
increase in the average price realized per equivalent unit of oil and gas
production. The following information excludes hedging effects (whereas the table above
includes hedging effects). Our oil and gas sales in 2003 were $58,208,000,
compared to $26,243,000 in 2002, an increase of $31,965,000 or 122%.The average
sales price received by us for natural gas production in 2003 was $3.51 per
Mcf, compared to $1.98 per Mcf in 2002, an increase of $1.53 per Mcf, or 77%.
The average price received per barrel of oil was $31.38 in 2003, compared to
$26.08 in 2002, representing an increase of $5.30 per barrel or 20%. On an Mcf
equivalent basis, the average price received was $3.77 per Mcfe in 2003
compared to $2.48 per Mcfe in the prior year, representing an overall 52%
increase in average prices. The portion of our total oil and gas revenues that
was derived from natural gas was 78% in 2003 compared to 63% in 2002. Our natural gas production totaled 13,015,000 Mcf in 2003 compared to 8,343,000
Mcf in 2002, representing an increase of 4,672,000 Mcf, or 56%. Our oil
production totaled 401,000 barrels and 373,000 barrels in 2003 and 2002,
respectively, representing an increase of 28,000 barrels, or 8%. Total
production was 84% natural gas and 16% oil in 2003, compared to 79% gas and 21%
oil in the prior year. This increase was due to Powder River Basin CBM
operations, which generated net gas production of 6,474,000 Mcf in 2003,
compared to 1,576,000 Mcf in 2002. Primas CBM production to date has largely
been attributable to the Stones Throw property, which was sold March 5, 2002,
and the Porcupine-Tuit property, which began producing from 27 wells during the
third quarter of 2002. Production from Porcupine-Tuit increased during the
second half of 2002 and in 2003 as de-watering occurred, new wells were drilled
and brought on-line, and additional compression capacity was installed by the
gathering company. At the end of 2003, Prima had 85 wells on-line at
Porcupine-Tuit producing at a combined net daily rate of approximately 19,500
Mcf. Our depletion expense for oil and gas properties in 2003 was $14,956,000 or
$0.97 per Mcfe, compared to $9,710,000, or $0.92 per Mcfe, in 2002, an increase
of $5,246,000 or 54%. The increase in the per-unit depletion rate primarily
reflects higher average costs per Mcfe for 2003 reserve additions than our
historical average and increased estimates for future development costs.
Depreciation of other fixed assets, which include service equipment, office
furniture and equipment, and buildings, was $1,058,000 and $1,088,000 for 2003
and 2002, respectively. 34




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##### Table of Contents



Lease operating expenses (LOE) totaled $3,619,000 for the year ended December
31, 2003 compared to $3,076,000 for the year ended December 31, 2002, an
increase of $543,000 or 18%. The increase was primarily associated with the
additional CBM production in 2003. On a per-unit-of-production basis, LOE
decreased from $0.29 in 2002 to $0.23 in 2003. Ad valorem and production taxes
were $2,116,000 and $5,783,000 in 2002 and 2003, respectively, an increase of
$3,667,000 or 173%. Production taxes fluctuate with revenues and changing mill
levy rates, and averaged 9.9% of total oil and gas sales excluding hedging
effects in 2003 compared to 8.1% in 2002, reflecting a greater portion of oil
and gas sales attributable to properties in Wyoming, which has higher
production tax rates than Colorado. Total lifting costs (LOE plus ad valorem
and production taxes) were $0.61 per Mcfe for 2003 compared to $0.49 per Mcfe
for 2002. Oilfield services revenues include well servicing fees from completion and swab
rigs, CBM drilling rigs, trucking, water hauling, equipment rentals, and other
related activities. Services are provided to both Prima and unaffiliated third
parties, but intercompany billings are eliminated in consolidation. Revenues
from third parties totaled $8,577,000 for the year ended December 31, 2003
compared to $8,326,000 for the year ended December 31, 2002, an increase of
$251,000, or 3%. Costs of oilfield services provided to third parties were
$6,510,000 in 2003 compared to $6,490,000 for 2002, an increase of $20,000 or
less than 1%. Approximately 24% of fees billed by the service companies in 2003
were for Prima managed properties, compared to 19% in 2002. A 10%
year-over-year increase in billings before intercompany eliminations, which was
attributable to stronger demand for services, was partially offset by the
increased portion of work performed on Prima-operated properties. General and administrative expenses (G&A), net of third party reimbursements
and amounts capitalized, were $3,321,000 for the year ended December 31, 2003
compared to $3,255,000 for the year ended December 31, 2002. Net G&A costs
increased by 2% or $66,000. Higher total costs were partially offset by
increased reimbursements of management and operator fees from third parties.
These fees increased from $405,000 in 2002 to $601,000 in 2003, due to having
more third party ownership in CBM wells drilled in 2003 than in prior years.
Capitalized G&A was $2,124,000 in both 2003 and 2002. Our provision for income taxes was $11,515,000 for the year ended December 31,
2003 compared to $825,000 for the year ended December 31, 2002. Our effective
tax rate increased to 33% in 2003 from 13.7% in 2002. The higher effective tax
rate in 2003 was primarily attributable to a $28,852,000, or 476%, increase in
pre-tax income without a proportionate change in permanent differences. The
effective tax rates in both years were less than statutory rates due to
permanent differences in book and tax basis income, consisting primarily of
statutory depletion deductions and, in 2002, Section 29 tax credits. The
statutory provision under which Section 29 tax credits were generated by
production from certain wells expired at the end of 2002. Proved oil and gas reserves: From the end of 2002 to the end of 2003, our
proved oil and gas reserves increased by 14,692 MMcfe, from 111,104 MMcfe to
125,796 MMcfe. The 13% year-over-year increase in proved reserves was due to
additions of 15,482 MMcfe from extensions, discoveries and acquisitions, and
19,382 MMcfe of net positive revisions, partially offset by 15,421 MMcfe of net
production and 4,751 MMcfe of net proved reserves sold or swapped for other
assets. The extensions, discoveries and acquisitions were primarily
attributable to activities in the D-J Basin and revisions were largely due to
the effect of higher gas prices. Other activities during 2003, including
operations in the Powder River Basin CBM play and Primas Coyote Flats prospect
in Utah, were primarily associated with development of proved undeveloped
reserves or related to properties still being evaluated for proved oil and gas
reserves. 2002 vs. 2001 For the year ended December 31, 2002, we reported net income of $5,230,000, or
$0.40 per diluted share, on revenues of $31,790,000. These amounts compared to
net income of $23,768,000, or $1.80 per diluted share, on revenues of
$60,287,000, for the year ended December 31, 2001. Total expenses, other than
income taxes, were $25,735,000 in 2002 compared to $26,480,000 in 2001.
Revenues decreased $28,497,000 or 47%, expenses decreased $745,000 or 3%, and
net income decreased $18,538,000 or 78% in 2002. 35




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##### Table of Contents



Our revenues for 2002 included $3,376,000 of aggregate losses from oil and gas
derivatives, comprised of hedging losses of $458,000 included in our oil and
gas sales, plus $2,918,000 of separately reported losses on derivative
instruments that did not qualify for hedge accounting. The derivative
instruments that didnt qualify for hedge accounting were principally NYMEX gas
swaps for which we did not elect to enter into corresponding swaps for Rocky
Mountain basis differentials. The related $2,918,000 of losses consisted of
$1,546,000 of net amounts
received on positions closed in 2002, offset by $4,464,000 of net unrealized
losses recorded primarily to reverse unrealized mark-to-market gains recognized
in the prior year, as mark-to-market gains on positions held at December 31,
2001 declined when gas prices escalated in 2002 before the contracts were
settled. During 2001, we recognized $9,816,000 of gains from oil and gas
derivatives, consisting of hedging gains of $3,381,000, realized ineffective
hedging gains of $2,057,000, and unrealized mark-to-market gains of $4,378,000. Oil and gas sales reported for 2002 totaled $25,785,000, compared to
$44,548,000 for 2001, a decrease of 42%. The lower revenues were due to an 11%
year-over-year decrease in production volumes and a 35% decrease in the average
price realized per equivalent unit of natural gas and oil production. Excluding
hedging effects, our oil and gas sales reported for 2002 were $26,243,000,
compared to $41,167,000 for 2001, a decrease of $14,924,000 or 36%. Primas natural gas production totaled 8,343,000 Mcf in 2002 compared to
9,277,000 Mcf in 2001, representing a decrease of 934,000 Mcf, or 10%. Our oil
production totaled 373,000 barrels and 431,000 barrels in 2002 and 2001,
respectively, representing a decrease of 58,000 barrels, or 13%. On an
equivalent unit basis, production declined from 11,863,000 Mcfe in 2001 to
10,580,000 Mcfe in 2002. Total production was 79% natural gas and 21% oil in
2002, compared to 78% gas and 22% oil in the prior year. Our Stones Throw CBM
property, which was sold in March 2002, contributed 298,000 net Mcf during the
two months the property was owned in 2002, compared to 1,321,000 Mcf in 2001,
largely accounting for the declines in gas volumes and net equivalent units.
Gas production from the Porcupine-Tuit CBM property, which was initiated at the
end of July 2002, roughly offset oil and gas production declines on other
properties. Such declines were attributable to a high level of drilling and
well recompletion activity in the first half of 2001, in response to a strong
commodity price environment, followed by reduced activity levels in the second
half of 2001 and in 2002 in response to a significant decline in Rocky Mountain
gas prices. The following information excludes hedging effects (whereas the table above
includes hedging effects). The average sales price received by us for natural
gas production in 2002 was $1.98 per Mcf, compared to $3.24 per Mcf in 2001, a
decrease of $1.26 per Mcf, or 39%. The average price received per barrel of oil
was $26.08 in 2002, compared to $25.68 in 2001, representing an increase of
$0.40 per barrel or 2%. On an Mcf equivalent basis, the average price received
was $2.48 per Mcfe in 2002 compared to $3.47 per Mcfe in the prior year,
representing an overall 29% decline in average prices. The portion of our total
oil and gas revenues that was derived from natural gas was 63% in 2002 compared
to 73% in 2001. Our depletion expense for oil and gas properties in 2002 was $9,710,000, or
$0.92 per Mcfe, compared to $9,190,000, or $0.77 per Mcfe, in 2001, an increase
of $520,000 or 6%. The increase in the per-unit depletion rate primarily
reflects a decline in estimated proved reserve quantities related to Powder
River Basin CBM properties. These adjustments are discussed below. Depreciation
of other fixed assets, which include service equipment, office furniture and
equipment, and buildings, was $1,088,000 and $1,039,000 for 2002 and 2001,
respectively. Lease operating expenses totaled $3,076,000 for the year ended December 31,
2002 compared to $3,295,000 for the year ended December 31, 2001, a decrease of
$219,000 or 7%. The decrease was primarily attributable to the sale of the
Stones Throw CBM wells in March 2002. On a per-unit-of-production basis, LOE
increased slightly, from $0.28 in 2001 to $0.29 in 2002. Ad valorem and
production taxes were $2,116,000 and $3,344,000 for the same periods, a
decrease of $1,228,000 or 37%. Production taxes fluctuate with revenues and
changing mill levy rates, and averaged 8.1% of total oil and gas sales
excluding hedging effects in both 2002 and 2001. Total lifting
costs (LOE plus ad valorem and production taxes) were $0.49 per Mcfe for 2002
compared to $0.56 per Mcfe for 2001. 36




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Oilfield services revenues from third parties totaled $8,326,000 in 2002
compared to $8,090,000 in 2001, an increase of $236,000, or 3%. Costs of
oilfield services provided to third parties were $6,490,000 in 2002 compared to
$5,812,000 for 2001, an increase of $678,000 or 12%. Approximately 19% of fees
billed by the service companies in 2002 were for Prima managed properties,
compared to 34% in 2001. Lower total billings in 2002, caused by the effects
on demand of relatively low Rocky Mountain gas prices and pending regulatory
decisions relating to Powder River Basin CBM development, were offset by the
reduced portion of services performed on behalf of Prima. The disproportionate
increase in costs associated with services provided third parties primarily
reflects a change in the mix of activities conducted for both Prima and other
operators, including a greater weighting of high margin services provided to
Prima in 2002 which were eliminated in consolidation. General and administrative expenses, net of third party reimbursements and
amounts capitalized, were $3,255,000 for the year ended December 31, 2002
compared to $3,559,000 for the year ended December 31, 2001. Net G&A costs
decreased by $304,000 or 9% due to increased third party reimbursements and
greater amounts capitalized. Third party reimbursements of management and
operator fees increased from $371,000 in 2001 to $405,000 in 2002, due to
having increased third party ownership in properties drilled or refractured in
the current year. Capitalized G&A increased from $1,753,000 in 2001 to
$2,124,000 in 2002, reflecting increased costs associated with exploration,
exploitation and development activities. Our provision for income taxes was $825,000 for the year ended December 31,
2002 compared to $10,650,000 for the year ended December 31, 2001, a decrease
of $9,825,000 or 92%. Our effective tax rate decreased to 13.7% in 2002 from
31.5% in 2001. The effective tax rates in both years were less than statutory
rates due to permanent differences in book and tax basis income, consisting
primarily of statutory depletion deductions and Section 29 tax credits. The
lower effective tax rate in 2002 was primarily attributable to a $27,752,000,
or 82%, decrease in pre-tax income without a proportionate change in permanent
differences. Proved oil and gas reserves: From the end of 2001 to the end of 2002, our
proved oil and gas reserves declined by 24,482 MMcfe, from 135,586 MMcfe to
111,104 MMcfe. The year-over-year decline primarily reflected 8,259 MMcfe of
property sales and exchanges, most of which was accounted for by the Stones
Throw property disposition, and net revisions aggregating 16,614 MMcfe.
Estimated additions to proved reserves from extensions, discoveries and
acquisitions in 2002 totaled 10,971 MMcfe, slightly greater than total
production during the year of 10,580 MMcfe. Most of Primas investments in
2002 were directed toward activities that did not add, nor were expected to
add, significant incremental proved reserves during the year, including:  
    
    development of previously-established proved reserves in the D-J
Basin and at the Porcupine-Tuit CBM property;
    
    pilot projects in the Powder River Basin designed to evaluate and
develop deeper coal seams, which will generate proved reserves
additions in future periods if our expectations are met;
    
    exploration on the Coyote Flats prospect in Utah, where the
initial test well had not yet been completed and determination of
commerciality was still pending; and
    
    exploratory acreage acquisitions. Net revisions to proved reserves during the year were primarily attributable to
Primas Powder River Basin CBM properties and reflected incorporation of
additional data from activities conducted by Prima and other operators, as well
as certain regulatory developments. The revisions reflected the following
adjustments to previous estimates:  
    
    we increased estimated future development and operating costs, to
reflect rising costs for certain services and arrangements with
surface owners;
    
    we increased projected costs for water disposal due to
anticipated regulatory actions;
    
    we incorporated expectations of longer lead times for property
development, due primarily to anticipated regulatory constraints;
    
    we modified the projected production profile, to provide for
longer de-watering times; and,
    
    we excluded all undrilled locations for which economic runs
indicated expected returns above 10%, but less than 20%, to more
closely approximate our internal hurdle rate. 37




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As a result, our estimated reserves at the end of 2002 generally excluded
properties with thinner, shallower coals that we did not anticipate developing
at that time, as we focused planned activities on reserve targets assessed as
being larger with higher potential economic returns. At December 31, 2002,
these higher-potential reserve targets were not proved. Generally, such targets
are deeper and thicker coals than the Wyodak coals that were extensively
developed in the initial phases of the industrys exploitation of CBM potential
in the Powder River Basin. At the end of 2002, these deeper coals were in the
early stages of evaluation and development by Prima and other operators in the
area. 
 New Accounting Pronouncements In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity to improve the
accounting for certain financial instruments that, under previous guidance,
issuers could account for as equity. SFAS No. 150 requires that those
instruments be classified as liabilities in statements of financial position.
SFAS No. 150 does not apply to features embedded in a financial instrument that
is not a derivative in its entirety. In addition to its requirements for the
classification and measurement of financial instruments within its scope, SFAS
No. 150 also requires disclosures about alternative ways of settling the
instruments and the capital structure of entities, all of whose shares are
mandatorily redeemable. Most of the guidance in Statement 150 is effective for
all financial instruments entered into or modified after May 31, 2003, and
otherwise is effective at the beginning of the first interim period beginning
after June 15, 2003. As we have no such financial instruments, we do not
anticipate any impact on our financial position or results of operations upon
adoption. A reporting issue has arisen regarding the application of certain provisions of
SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other
Intangible Assets, to companies in the extractive industries, including oil
and gas companies. The issue is whether the Financial Accounting Standards
Board (FASB) intended to require companies to classify the costs of mineral
rights held under lease or other contractual arrangements associated with
extracting oil and gas as intangible assets in balance sheets, apart from other
capitalized oil and gas property costs, and provide specific footnote
disclosures. Historically, we have included the costs of such mineral rights
associated with extracting oil and gas as a component of our investments in oil
and gas properties. If it is ultimately determined that SFAS No. 142 requires
oil and gas companies to classify the costs associated with mineral rights as a
separate category of intangible assets on balance sheets, we would be required
to reclassify approximately $27 million at December 31, 2003 and $26 million at December 31,
2002 out of oil and gas properties and into a separate intangible assets line
item. Our results of operations and cash flows would not be affected since such
intangible assets would continue to be depleted and assessed for impairment in
accordance with full-cost accounting rules. 
 ITEM 7A.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Our primary market risks relate to changes in prices received on sales of
natural gas and oil production. We periodically enter into derivative contracts
to mitigate a portion of this commodity price risk, or in an effort to enhance
profitability. Such derivatives consist of commodity futures or price swaps
(agreements with
counterparties to exchange floating prices for fixed prices), and options on
such futures or price swaps. Generally, these instruments reduce our exposure
to decreases in gas and oil prices, or increases in differentials between NYMEX
and Rocky Mountain gas prices, but they also typically limit the benefits we
realize from increases in prices or narrowing of basis differentials. When
hedging only a portion of our exposure to changes in prices, we are able to
partially benefit from increases in gas and oil prices or improvements in basis
differentials, but we remain exposed to market risk on the portion of our
production not covered by such derivatives. We also retain risks related to the
ineffective portion of such derivatives instruments, when applicable. We may enter into derivatives positions intended to offset risks associated
with downward price movements in benchmark NYMEX oil and gas prices, as well as
basis swaps to protect us from increases in the differential between NYMEX and
Rocky Mountain gas prices. Our derivatives contracts generally represent cash
flow hedges that are determined to be qualifying or non-qualifying for hedge
accounting treatment in accordance with the provisions of SFAS 133. At times,
however, we may consider establishing derivative positions that do not
represent cash flow hedges. See 38




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Note 1 and Note 5 of Notes to Consolidated
Financial Statements for additional information with respect to derivatives and
related accounting policies. Personnel who we believe have appropriate skills and experience execute all
derivatives transactions. The personnel involved in these activities must
follow prescribed trading limits and parameters that are regularly reviewed by
our Chief Executive Officer. Our Chief Executive Officer approves all
derivatives transactions before being entered into and our Board of Directors
regularly reviews outstanding positions and hedging strategy. We use only
conventional derivatives instruments and attempt to manage our credit risk by
entering into derivatives contracts only with financial institutions that we
believe to be reputable and which carry an investment grade rating. Following are disclosures regarding our market risk instruments. Investors and
other users are cautioned to avoid simplistic use of these disclosures. Users
should realize that the actual impact of future commodity price movements will
likely differ from the amounts disclosed below due to ongoing changes in risk
exposure levels and concurrent adjustments to positions. It is not possible to
accurately predict future movements in natural gas and oil prices. During 2003, we sold 401,000 barrels of produced oil. A hypothetical decrease
of $3.14 per barrel (10% of average prices for the period exclusive of hedging
transactions) would have decreased our revenues by $1,259,000 for the period.
We sold 13,015,000 Mcf of produced natural gas during the same period. A
hypothetical decrease of $0.35 per Mcf (10% of average prices for the period
exclusive of hedging transactions) would have decreased our revenues by
$4,555,000 for the period. We have realized net losses totaling $442,000 on positions closed out in 2004
relating to contract months of January through March 2004. At the close of
business on February 27, 2004, the fair value of our
remaining oil and gas derivatives instruments reflected a net loss of $2,474,000, as shown
below: AverageMarket
    
    Total Volumes
    
    Contract
    
    FairTime Period
    
    Index
    
    (MMBtu or Bbls)
    
    Price
    
    ValueNatural Gas FuturesApril  October 2004
    
    NW Rockies
    
    
    4,900,000
    
    
    $
    4.41
    
    
    $
    (1,818,000
    )November 2004
    
    CIG
    
    
    350,000
    
    
    
    4.00
    
    
    
    (343,000
    )Crude Oil FuturesApril  September 2004
    
    NYMEX
    
    
    95,000
    
    
    
    31.27
    
    
    
    (313,000
    )Total Net
Fair Value
    
    
    
    
    
    
    
    
    
    
    
    $
    (2,474,000
    )
 All of the derivative positions scheduled above are considered to be effective
hedges. Combined, these positions total approximately 5,820,000 Mcfe of
volumes. 39




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##### Table of Contents



ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Our Consolidated Financial Statements are attached at the end of this Annual
Report on Form 10-K. An index to these Consolidated Financial Statements is
also included in Item 15(a) of this Annual Report on Form 10-K. 
 ITEM 9.     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Since our inception, there has not been any Form 8-K filed under the Securities
Exchange Act of 1934 reporting a change in accountants in which there was a
reported disagreement on any matter of accounting principles or practices or
financial statement disclosure. 
 ITEM 9A.     CONTROLS AND PROCEDURES Primas principal executive officer and principal financial officer have
evaluated the effectiveness of our disclosure controls and procedures, as
such term is defined in Rule 13a-15(e) and 15d-15(e) of the Securities Exchange
Act of 1934, as amended, within 90 days of the filing date of this Annual
Report on Form 10-K. Based upon their evaluation, our principal executive
officer and principal financial officer concluded that Primas disclosure
controls and procedures are effective as of the end of the period covered by
this report. There were no significant changes in our internal controls or in
other factors that could significantly affect these controls, since the date
the controls were evaluated. 
 PART III 
 ITEM 10.     DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 
 ITEM 11.     EXECUTIVE COMPENSATION 
 ITEM 12.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
 ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
 ITEM 14.     PRINCIPAL ACCOUNTANT FEES AND SERVICES Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12, 13 and 14 are
omitted because we intend to file a definitive proxy statement pursuant to
Regulation 14A under the Securities Exchange Act of 1934 not later than 120
days after the close of the fiscal year. The information required by such
Items will be included in the definitive proxy statement to be filed for our
annual meeting of stockholders and is hereby incorporated by reference. 40




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PART IV 
 ITEM 15.     EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a)(1) Financial Statements INDEX TO CONSOLIDATED FINANCIAL STATEMENTS PageIndependent Auditors Report
    
    
    43Consolidated Balance Sheets at December 31, 2003 and 2002
    
    
    44Consolidated Statements of Income for the years ended
December 31, 2003, 2002 and 2001
    
    
    46Consolidated Statements of Cash Flows for the years ended
December 31, 2003, 2002 and 2001
    
    
    47Consolidated Statements of Stockholders Equity for the years ended
December 31, 2003, 2002 and 2001
    
    
    48Consolidated Statements of Comprehensive Income for the years ended
December 31, 2003, 2002 and 2001
    
    
    49Notes to Consolidated Financial Statements for the years ended
December 31, 2003, 2002 and 2001
    
    
    50
 (a)(2) Financial Statement Schedules Financial statement schedules have been omitted because they are not applicable
or the information required therein is included elsewhere in the financial
statements or notes thereto. (b) Reports on Form 8-K During the quarter ended December 31, 2003, Prima filed the following current
report on Form 8-K: Report dated November 6, 2003, reporting earnings for the quarter and nine
months ended September 30, 2003, and providing an update of commodity
hedging transactions, operating activities and 2003 production forecasts. (c) Exhibits The following exhibits are filed with or are incorporated by reference into
this report on Form 10-K. Exhibit No.
    
    Document3.1
    
    Certificate of Incorporation of Prima Energy Corporation,
Delaware, as filed August 18, 1988. (Incorporated by reference to
Registration of Securities of Certain Successor Issuers on Form 8-B
dated January 20, 1989.)3.2
    
    Certificate of Amendment of Certificate of Incorporation of
Prima Energy Corporation filed May 1, 1989. (Incorporated by
reference to Annual Report on Form 10-K for Prima Energy
Corporation for the year ended June 30, 1989.)3.3
    
    Bylaws of Prima Energy Corporation. (Incorporated by reference
to Registration of Securities of Certain Successor Issuers on Form
8-B dated January 20, 1989.)3.4
    
    Certificate of Amendment of the Certificate of Incorporation of
Prima Energy Corporation. (Incorporated by reference to Quarterly
Report on Form 10-Q for Prima Energy Corporation for the quarter
ended June 30, 1997.)
 41




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##### Table of Contents



Exhibit No.
    
    Document3.5
    
    Certificate of Amendment of the Certificate of Incorporation of
Prima Energy Corporation. (Incorporated by reference to Quarterly
Report on Form 10-Q for Prima Energy Corporation for the quarter
ended September 30, 2000.)3.6
    
    Certificate of Amendment of the Certificate of Incorporation of
Prima Energy Corporation. (Incorporated by reference to Quarterly
Report on Form 10-Q for Prima Energy Corporation for the quarter
ended June 30, 2001.)4.1
    
    Rights Agreement dated as of May 23, 2001, between Prima Energy
Corporation and Computershare Trust Company, Inc., as Rights Agent,
including the form of Certificate of Designation, Powers,
Preferences and Rights of Series A Participating Preferred Stock
dated May 29, 2001, the Form of Right Certificate, and the Summary
of Rights to Purchase Preferred Shares. (Incorporated by reference
to Current Report on Form 8-K for Prima Energy Corporation dated May
23, 2001.)10.1
    
    Prima Energy Corporation Employee Stock Ownership Plan
(Incorporated by reference to Annual Report on Form 10-K for Prima
Energy Corporation for the year ended June 30, 1989.)10.2
    
    Prima Energy Corporation 1993 Stock Incentive Plan.
(Incorporated by reference to Annual Report on Form 10-K for Prima
Energy Corporation for the year ended December 31, 1993.)10.3
    
    Agreement of Lease between Denver-Stellar Associates LP,
Landlord and Prima Energy Corporation, Tenant, effective December 1,
2001. (Incorporated by reference to Annual Report on Form 10-K for
Prima Energy Corporation for the year ended December 31, 2000.)10.4
    
    Prima Energy Corporation Non-Employee Directors Stock Option
Plan. (Incorporated by reference to Quarterly Report on Form 10-Q
for Prima Energy Corporation for quarter ended March 31, 2002.)10.5
    
    Prima Energy Corporation 2001 Stock Incentive Plan.
(Incorporated by reference to Quarterly Report on Form 10-Q for
Prima Energy Corporation for the quarter ended March 31, 2002.)14.1
    
    Prima Energy Corporation Code of Ethics for Senior Financial Officers21.1
    
    Subsidiaries of the Registrant23.1
    
    Independent Auditors Consent23.2
    
    Independent Reservoir Engineers and Geologists Consent31.1
    
    Certification of Chief Executive Officer pursuant to Rule
13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as
amended31.2
    
    Certification of Chief Financial Officer pursuant to Rule
13(a)-14(a) /15d-14(a) of the Securities Exchange Act of 1934, as
amended32.1
    
    Certification of Chief Executive Officer and Chief Financial
Officer pursuant to 18 USC Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
 42




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INDEPENDENT AUDITORS REPORT Prima Energy Corporation: We have audited the accompanying consolidated balance sheets of Prima
Energy Corporation (the Company) and subsidiaries as of December 31, 2003 and
2002, and the related consolidated statements of income, cash flows,
stockholders equity, and comprehensive income for each of the three years in
the period ended December 31, 2003. These financial statements are the
responsibility of the Companys management. Our responsibility is to express
an opinion on these 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, such consolidated financial statements present fairly, in
all material respects, the financial position of the Company and its
subsidiaries at December 31, 2003 and 2002, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2003 in conformity with accounting principles generally accepted in the
United States of America. As discussed in Note 1 to the consolidated financial statements, in 2001
the Company adopted Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging Activities and in 2003 the Company adopted Statement of Financial Accounting
Standards No. 143, Accounting for Asset Retirement Obligations. DELOITTE & TOUCHE LLP March 11, 2004
Denver, Colorado 43




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PRIMA ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2003 and 2002 ASSETS 2003
    
    2002CURRENT ASSETSCash and cash equivalents
    
    $
    55,918,000
    
    
    $
    36,263,000Available for sale securities, at market
    
    
    1,274,000
    
    
    
    1,744,000Receivables (net of allowance for doubtful accounts:$281,000 and $304,000)
    
    
    10,759,000
    
    
    
    7,492,000Inventory
    
    
    1,012,000
    
    
    
    940,000Other
    
    
    938,000
    
    
    
    818,000Total current assets
    
    
    69,901,000
    
    
    
    47,257,000OIL AND GAS PROPERTIES, at cost, accounted for
using the full cost method:Proved
    
    
    150,575,000
    
    
    
    130,948,000Unproved
    
    
    27,317,000
    
    
    
    20,570,000Less accumulated depreciation, depletion and amortization
    
    
    (76,478,000
    )
    
    
    (62,980,000
    )Oil and gas properties  net
    
    
    101,414,000
    
    
    
    88,538,000OTHER PROPERTY AND EQUIPMENT, at costOilfield service equipment
    
    
    9,737,000
    
    
    
    9,457,000Furniture and equipment
    
    
    713,000
    
    
    
    712,000Field office, shop and land
    
    
    451,000
    
    
    
    478,00010,901,000
    
    
    
    10,647,000Less accumulated depreciation
    
    
    (6,183,000
    )
    
    
    (5,808,000
    )Other property and equipment  net
    
    
    4,718,000
    
    
    
    4,839,000OTHER ASSETS
    
    
    1,184,000
    
    
    
    1,293,000$
    177,217,000
    
    
    $
    141,927,000
 See accompanying notes to consolidated financial statements. 44




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PRIMA ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS (contd.)
DECEMBER 31, 2003 and 2002 LIABILITIES AND STOCKHOLDERS EQUITY 2003
    
    2002CURRENT LIABILITIESAccounts payable
    
    $
    3,722,000
    
    
    $
    3,129,000Amounts payable to oil and gas property owners
    
    
    2,620,000
    
    
    
    3,192,000Ad valorem and production taxes payable
    
    
    3,477,000
    
    
    
    3,864,000Accrued and other liabilities
    
    
    1,951,000
    
    
    
    893,000Derivatives, at fair value
    
    
    1,983,000
    
    
    
    225,000Total current liabilities
    
    
    13,753,000
    
    
    
    11,303,000AD VALOREM TAXES, non-current
    
    
    3,634,000
    
    
    
    2,077,000ASSET RETIREMENT OBLIGATIONS
    
    
    1,903,000
    
    
    
    DEFERRED INCOME TAX LIABILITY
    
    
    27,251,000
    
    
    
    21,281,000Total liabilities
    
    
    46,541,000
    
    
    
    34,661,000STOCKHOLDERS EQUITYPreferred stock, $0.001 par value, 2,000,000 shares
authorized; no shares issued
    
    
    
    
    
    
    Common stock, $0.015 par value, 35,000,000 shares
authorized; 13,312,548 and 13,064,048 shares
issued
    
    
    200,000
    
    
    
    196,000Additional paid-in capital
    
    
    8,455,000
    
    
    
    5,250,000Retained earnings
    
    
    131,265,000
    
    
    
    107,470,000Accumulated other comprehensive loss
    
    
    (1,598,000
    )
    
    
    (115,000
    )Treasury stock, 348,406 and 236,538 shares, at cost
    
    
    (7,646,000
    )
    
    
    (5,535,000
    )Stockholders equity  net
    
    
    130,676,000
    
    
    
    107,266,000$
    177,217,000
    
    
    $
    141,927,000
 See accompanying notes to consolidated financial statements. 45




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PRIMA ENERGY CORPORATION CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 and 2001 2003
    
    2002
    
    2001REVENUESOil and gas sales
    
    $
    58,622,000
    
    
    $
    25,785,000
    
    
    $
    44,548,000Gains (losses) on derivative instruments, net
    
    
    2,320,000
    
    
    
    (2,918,000
    )
    
    
    6,435,000Oilfield services
    
    
    8,577,000
    
    
    
    8,326,000
    
    
    
    8,090,000Interest, dividend and other income
    
    
    635,000
    
    
    
    597,000
    
    
    
    1,214,00070,154,000
    
    
    
    31,790,000
    
    
    
    60,287,000EXPENSESDepreciation, depletion and amortization:Depletion of oil and gas properties
    
    
    14,956,000
    
    
    
    9,710,000
    
    
    
    9,190,000Depreciation of property and equipment
    
    
    1,058,000
    
    
    
    1,088,000
    
    
    
    1,039,000Lease operating expense
    
    
    3,619,000
    
    
    
    3,076,000
    
    
    
    3,295,000Ad valorem and production taxes
    
    
    5,783,000
    
    
    
    2,116,000
    
    
    
    3,344,000Oilfield services
    
    
    6,510,000
    
    
    
    6,490,000
    
    
    
    5,812,000General and administrative
    
    
    3,321,000
    
    
    
    3,255,000
    
    
    
    3,559,000Impairment of natural gas swap
    
    
    
    
    
    
    
    
    
    
    241,00035,247,000
    
    
    
    25,735,000
    
    
    
    26,480,000Income before income taxes and cumulative effect
of change in accounting principle
    
    
    34,907,000
    
    
    
    6,055,000
    
    
    
    33,807,000Provision for income taxes
    
    
    11,515,000
    
    
    
    825,000
    
    
    
    10,650,000Net income before cumulative effect of change in
accounting principle
    
    
    23,392,000
    
    
    
    5,230,000
    
    
    
    23,157,000Cumulative effect of change in accounting principle
(net of income taxes of $217,000 and $265,000)
    
    
    403,000
    
    
    
    
    
    
    
    611,000NET INCOME
    
    $
    23,795,000
    
    
    $
    5,230,000
    
    
    $
    23,768,000Basic net income per share before cumulative effect
of change in accounting principle
    
    $
    1.82
    
    
    $
    0.41
    
    
    $
    1.82Cumulative effect of change in accounting principle
    
    
    0.03
    
    
    
    
    
    
    
    0.05BASIC NET INCOME PER SHARE
    
    $
    1.85
    
    
    $
    0.41
    
    
    $
    1.87Diluted net income per share before cumulative effect
of change in accounting principle
    
    $
    1.79
    
    
    $
    0.40
    
    
    $
    1.75Cumulative effect of change in accounting principle
    
    
    0.03
    
    
    
    
    
    
    
    0.05DILUTED NET INCOME PER SHARE
    
    $
    1.82
    
    
    $
    0.40
    
    
    $
    1.80
 See accompanying notes to consolidated financial statements. 46




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PRIMA ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 and 2001 2003
    
    2002
    
    2001OPERATING ACTIVITIESNet income
    
    $
    23,795,000
    
    
    $
    5,230,000
    
    
    $
    23,768,000Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation, depletion and amortization
    
    
    16,014,000
    
    
    
    10,798,000
    
    
    
    10,229,000Deferred income taxes
    
    
    6,416,000
    
    
    
    (977,000
    )
    
    
    9,123,000Cumulative effect of change in accounting principle
    
    
    (403,000
    )
    
    
    
    
    
    
    Unrealized derivative activities
    
    
    (685,000
    )
    
    
    4,464,000
    
    
    
    (4,378,000
    )Tax benefits from stock option plans
    
    
    1,913,000
    
    
    
    1,250,000
    
    
    
    732,000Other
    
    
    108,000
    
    
    
    298,000
    
    
    
    224,000Changes in operating assets and liabilities:Receivables
    
    
    (3,275,000
    )
    
    
    (1,698,000
    )
    
    
    3,096,000Inventory
    
    
    (72,000
    )
    
    
    475,000
    
    
    
    (6,000
    )Other current assets
    
    
    89,000
    
    
    
    89,000
    
    
    
    241,000Accounts payable and payables to owners
    
    
    21,000
    
    
    
    2,743,000
    
    
    
    (2,130,000
    )Production taxes payable
    
    
    1,170,000
    
    
    
    (633,000
    )
    
    
    1,504,000Accrued and other liabilities
    
    
    1,058,000
    
    
    
    (515,000
    )
    
    
    605,000Net cash provided by operating activities
    
    
    46,149,000
    
    
    
    21,524,000
    
    
    
    43,008,000INVESTING ACTIVITIESAdditions to oil and gas properties
    
    
    (26,856,000
    )
    
    
    (22,252,000
    )
    
    
    (35,248,000
    )Purchases of other properties
    
    
    (1,422,000
    )
    
    
    (1,142,000
    )
    
    
    (1,958,000
    )Purchases of available-for-sale securities
    
    
    (552,000
    )
    
    
    (272,000
    )
    
    
    (125,000
    )Proceeds from sales of oil and gas property
    
    
    1,765,000
    
    
    
    14,577,000
    
    
    
    57,000Proceeds from sales of securities
    
    
    1,177,000
    
    
    
    929,000
    
    
    
    166,000Proceeds from sales of other property and equipment
    
    
    209,000
    
    
    
    375,000
    
    
    
    212,000Net cash used in investing activities
    
    
    (25,679,000
    )
    
    
    (7,785,000
    )
    
    
    (36,896,000
    )FINANCING ACTIVITIESTreasury stock purchased
    
    
    (2,111,000
    )
    
    
    (1,669,000
    )
    
    
    (3,866,000
    )Proceeds from exercise of stock options
    
    
    1,296,000
    
    
    
    856,000
    
    
    
    526,000Other
    
    
    
    
    
    
    
    
    
    
    183,000Net cash used in financing activities
    
    
    (815,000
    )
    
    
    (813,000
    )
    
    
    (3,157,000
    )Increase in cash and cash equivalents
    
    
    19,655,000
    
    
    
    12,926,000
    
    
    
    2,955,000Cash and cash equivalents, beginning of year
    
    
    36,263,000
    
    
    
    23,337,000
    
    
    
    20,382,000CASH AND CASH EQUIVALENTS, end of year
    
    $
    55,918,000
    
    
    $
    36,263,000
    
    
    $
    23,337,000
 See accompanying notes to consolidated financial statements. 47




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##### Table of Contents



PRIMA ENERGY CORPORATION CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 and 2001 AccumulatedCommon Stock
    
    Additional
    
    
    
    
    
    Other
    
    Treasury StockPaid-In
    
    Retained
    
    ComprehensiveShares
    
    Amount
    
    Capital
    
    Earnings
    
    Income (Loss)
    
    Shares
    
    Amount
    
    TotalBALANCES, January 1, 2001
    
    
    12,793,373
    
    
    $
    192,000
    
    
    $
    1,760,000
    
    
    $
    78,472,000
    
    
    $
    (126,000
    )
    
    
    
    
    
    $
    
    
    
    $
    80,298,000Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    23,768,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    23,768,000Exercise of stock options
    
    
    96,550
    
    
    
    1,000
    
    
    
    525,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    526,000Tax benefit from exercise of non-
qualified stock options
    
    
    
    
    
    
    
    
    
    
    732,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    732,000Other comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    152,000
    
    
    
    
    
    
    
    
    
    
    
    152,000Treasury stock purchased
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    155,351
    
    
    
    (3,866,000
    )
    
    
    (3,866,000
    )Other
    
    
    
    
    
    
    
    
    
    
    130,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    130,000BALANCES, December 31, 2001
    
    
    12,889,923
    
    
    
    193,000
    
    
    
    3,147,000
    
    
    
    102,240,000
    
    
    
    26,000
    
    
    
    155,351
    
    
    
    (3,866,000
    )
    
    
    101,740,000Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5,230,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5,230,000Exercise of stock options
    
    
    174,125
    
    
    
    3,000
    
    
    
    853,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    856,000Tax benefit from exercise of non-
qualified stock options
    
    
    
    
    
    
    
    
    
    
    1,250,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,250,000Other comprehensive loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (141,000
    )
    
    
    
    
    
    
    
    
    
    
    (141,000
    )Treasury stock purchased
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    81,187
    
    
    
    (1,669,000
    )
    
    
    (1,669,000
    )BALANCES, December 31, 2002
    
    
    13,064,048
    
    
    
    196,000
    
    
    
    5,250,000
    
    
    
    107,470,000
    
    
    
    (115,000
    )
    
    
    236,538
    
    
    
    (5,535,000
    )
    
    
    107,266,000Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    23,795,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    23,795,000Exercise of stock options
    
    
    248,500
    
    
    
    4,000
    
    
    
    1,292,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,296,000Tax benefit from exercise of non-
qualified stock options
    
    
    
    
    
    
    
    
    
    
    1,913,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,913,000Other comprehensive loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (1,483,000
    )
    
    
    
    
    
    
    
    
    
    
    (1,483,000
    )Treasury stock purchased
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    111,868
    
    
    
    (2,111,000
    )
    
    
    (2,111,000
    )BALANCES, December 31, 2003
    
    
    13,312,548
    
    
    $
    200,000
    
    
    $
    8,455,000
    
    
    $
    131,265,000
    
    
    $
    (1,598,000
    )
    
    
    348,406
    
    
    $
    (7,646,000
    )
    
    $
    130,676,000
 See accompanying notes to consolidated financial statements. 48




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##### Table of Contents



PRIMA ENERGY CORPORATION CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 and 2001 2003
    
    2002
    
    2001Net income
    
    $
    23,795,000
    
    
    $
    5,230,000
    
    
    $
    23,768,000Other comprehensive income (loss):Change in fair value of hedges
    
    
    (2,029,000
    )
    
    
    (690,000
    )
    
    
    3,475,000Reclassification adjustment for realized (gains) losses
on hedges included in net income
    
    
    (414,000
    )
    
    
    458,000
    
    
    
    (3,381,000
    )Deferred income tax benefit (expense) related to change
in fair value of hedges
    
    
    904,000
    
    
    
    86,000
    
    
    
    (35,000
    )Change in fair value of available-for-sale securities
    
    
    155,000
    
    
    
    (16,000
    )
    
    
    147,000Reclassification adjustment for realized (gains) losses
included in net income
    
    
    (66,000
    )
    
    
    25,000
    
    
    
    1,000Deferred income tax expense related to change in
fair value of available-for-sale securities
    
    
    (33,000
    )
    
    
    (4,000
    )
    
    
    (55,000
    )(1,483,000
    )
    
    
    (141,000
    )
    
    
    152,000COMPREHENSIVE INCOME
    
    $
    22,312,000
    
    
    $
    5,089,000
    
    
    $
    23,920,000
 See accompanying notes to consolidated financial statements. 49




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##### Table of Contents



PRIMA ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 and 2001 1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES Business and Basis of Presentation The accompanying consolidated financial statements include the accounts of
Prima Energy Corporation and its wholly owned subsidiaries, herein collectively
referred to as Prima or the Company. Primas primary business is the
exploration for, and the acquisition, development and production of, crude oil
and natural gas. The Company is also engaged in oil and gas property operations
and oilfield services, and, at times, has engaged in natural gas gathering,
marketing and trading. Primas activities have been conducted predominantly in
the Rocky Mountain region of the United States. The Companys proportionate share of capital expenditures, production
revenue and operating expenses from working interests in oil and gas properties
is included in the consolidated financial statements. All significant
intercompany transactions have been eliminated. Certain amounts in prior years
have been reclassified to conform to the classifications at December 31, 2003. Use of Estimates The preparation of the Companys 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 these estimates. Comprehensive Income Comprehensive income consists of net income, unrealized gains and losses
on marketable equity securities held for sale, and the effective component of
derivative instruments classified as cash flow hedges, net of income tax
effects. Comprehensive income is presented in the Consolidated Statements of
Comprehensive Income. The balances of after-tax components comprising accumulated other
comprehensive income (loss) as of December 31 are presented in the following
table: 2003
    
    2002
    
    2001Unrealized gain (loss) on effective component of
derivative instruments
    
    $
    (1,626,000
    )
    
    $
    (87,000
    )
    
    $
    59,000Unrealized gain (loss) on marketable equity securities
    
    
    28,000
    
    
    
    (28,000
    )
    
    
    (33,000
    )Accumulated other comprehensive income (loss)
    
    $
    (1,598,000
    )
    
    $
    (115,000
    )
    
    $
    26,000
 Consolidated Statements of Cash Flows Cash in excess of daily requirements has generally been invested in money
market accounts and other cash equivalents with maturities of three months or
less. Such investments are deemed to be cash equivalents for purposes of the
consolidated financial statements. Cash paid for income taxes was $2,153,000, $1,187,000 and $905,000 for the
years ended December 31, 2003, 2002 and 2001, respectively. No interest was
paid in 2003, 2002 or 2001. 50




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Estimated Fair Value of Financial Instruments and Available for Sale Securities The carrying amount of cash equivalents approximates fair value because of
the short maturity and high credit quality of those investments. Marketable securities are classified as available for sale, and are
carried on the balance sheet at market value. Unrealized gains and losses, net
of deferred income taxes, are generally reported as other comprehensive income
and as an adjustment to stockholders equity. If a decline in market value
below cost is assessed as being other than temporary, such impairment is
included in the determination of net income. Available-for-sale securities are
readily marketable and available for use in Primas operations should the need
arise. Therefore, the Company has classified such securities as current assets.
Realized gains and losses are determined on the specific identification method. Commencing with its adoption of Statement of Financial Accounting
Standards (SFAS) No. 133 on January 1, 2001, Prima has recognized all
derivatives on its balance sheet at their estimated fair values. The fair
values of these contracts are determined based on various factors, including
contract volumes and prices, contract settlement dates, quoted closing prices
on the NYMEX or over-the-counter and, where applicable, volatility and the time
value of options. The calculation of the fair value of collars and floors
requires the use of the Black-Scholes option-pricing model, but market
quotations are generally available. Substantially all of the Companys
derivatives positions are valued based upon reported settlement prices on the
NYMEX or as quoted in relatively liquid over-the-counter markets by a number of
market makers. Inventory Inventory consists of various tubular goods and surface production
facility equipment intended to be used in Primas oil and gas operations, and
is stated at the lower of cost or market value using the first-in, first-out
valuation method. Oil and Gas Properties Prima utilizes the full cost method of accounting for oil and gas
producing activities. Under this method, all costs associated with property
acquisition, exploration and development, including costs of unsuccessful
exploration and asset retirement obligations, are capitalized within a cost
center. Primas oil and gas properties are all located within the United
States, which constitutes a single cost center. No gain or loss is recognized
upon the sale or abandonment of undeveloped or producing oil and gas properties
unless the sale represents a significant portion of oil and gas properties and
the gain significantly alters the relationship between capitalized costs and
proved oil and gas reserves of the cost center. Depreciation, depletion and
amortization of oil and gas properties is computed on the units-of-production
method based on proved reserves. Amortizable costs include estimates of future
development costs of proved reserves. Prima invests in unevaluated oil and gas
properties for the purpose of exploration for proved reserves. The costs of
such assets, including exploration costs on properties where a determination of
whether proved oil and gas reserves will be established is still pending, are
included in unproved oil and gas properties at the lower of cost or estimated
fair market value and are not subject to amortization. Capitalized costs of oil and gas properties may not exceed an amount equal
to the present value, discounted at 10%, of the estimated future net cash flows
from proved oil and gas reserves plus the cost, or estimated fair market value
if lower, of unproved properties. Should capitalized costs exceed this
ceiling, an impairment is recognized. The present value of estimated future
net cash flows is computed based on revenues derived using oil and natural gas
prices and projected future production of proved reserves as of the balance
sheet date, less estimated future expenditures to be incurred in developing and
producing the proved reserves, assuming continuation of existing economic
conditions. Prima did not recognize any impairment loss during the three-year
period ended December 31, 2003. A reporting issue has arisen regarding the application of certain
provisions of SFAS No. 141, Business Combinations, and SFAS No. 142,
Goodwill and Other Intangible Assets, to companies in the extractive
industries, including oil and gas companies. The issue is whether the Financial
Accounting Standards Board (FASB) intended to require companies to classify
the costs of mineral rights held under lease or other contractual arrangements
associated with extracting oil and gas as intangible assets in balance sheets,
apart from other 51




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capitalized oil and gas property costs, and provide specific footnote
disclosures. Historically, we have included the costs of such mineral rights
associated with extracting oil and gas as a component of our investments in oil
and gas properties. If it is ultimately determined that SFAS No. 142 requires
oil and gas companies to classify the costs associated with mineral rights as a
separate category of intangible assets on balance sheets, we would be required
to reclassify approximately $27 million at December 31, 2003 and $26 million at December 31,
2002 out of oil and gas properties and into a separate intangible assets line
item. Our results of operations and cash flows would not be affected since such
intangible assets would continue to be depleted and assessed for impairment in
accordance with full-cost accounting rules. Other Property and Equipment Other (non-oil and gas) property and equipment is recorded at cost.
Renewals and betterments that substantially extend the useful lives of the
assets are capitalized. Maintenance and repairs are expensed when incurred.
Depreciation is provided using the straight-line method over the estimated
useful lives of the assets, ranging from three to 15 years. Such long-lived
assets are evaluated for impairment to determine if current circumstances and
market conditions indicate that the carrying amount of an asset may not be
recoverable. Prima did not recognize any impairment loss during the three-year
period ended December 31, 2003. Asset Retirement Obligations Effective January 1, 2003, we adopted SFAS No. 143, Accounting for Asset
Retirement Obligations. SFAS No. 143 provides that, if the fair value for an
asset retirement obligation can be reasonably estimated, the liability should
be recognized in the period in which it is incurred. Oil and gas producing
companies typically incur such liabilities upon drilling or acquiring wells.
Under the method prescribed by SFAS No. 143, an asset retirement obligation is
recorded as a liability at its estimated present value at the assets
inception, with an offsetting charge to property cost. The corresponding
property cost, less the estimated undiscounted salvage value, is then included
in the calculation of depletion cost for oil and gas properties. Periodic
accretion of discount of the estimated liability is also recorded in the income
statement. Prior to adoption of SFAS No. 143, we accrued for any estimated
asset retirement obligation, net of estimated salvage value, as part of our
calculation of depletion, depreciation and amortization. Under this method,
the estimated net cost of the obligation would be recognized over the life of
the property on a unit-of-production basis, with the estimated obligation
netted in property cost as part of the accumulated depreciation, depletion and
amortization balance. Based on our experience that salvage values have
generally equaled or exceeded abandonment costs for the types of properties
that Prima has owned to date, such net costs have been negligible. Natural Gas Imbalances Prima utilizes the accrual method of accounting for natural gas revenues
whereby revenues are recognized as the Companys entitlement share of gas is
produced and sold based on its net revenue interests in the properties. The
Company records a receivable (payable) to the extent it receives less (more)
than its proportionate share of gas revenues. Imbalance positions were not
significant at the end of 2003 or 2002. Oilfield Services and Operator Fees Fees earned from providing oilfield services and operating wells for third
parties are recorded when the services are performed. Fees charged
non-affiliates for oilfield services are recognized as income. Fees charged
non-affiliates for operating oil and gas properties are recorded as a reduction
of general and administrative expenses, unless fees exceed total costs, in which case any excess is recorded as revenue. Income Taxes Income taxes are provided for the tax effects of transactions reported in
the financial statements and consist of taxes currently payable plus deferred
income taxes related to certain income and expenses recognized in different
periods for financial and income tax reporting purposes. Deferred income tax
assets and liabilities represent the estimated future tax return consequences
of those differences, which will either be taxable or
deductible when the assets and liabilities are recovered or settled.
Deferred income taxes are also recognized for tax credits that are available to
offset future federal income taxes. Deferred income taxes are measured by
applying currently-enacted tax rates. 52




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Derivative Instruments and Hedging Activities Prima periodically enters into derivative contracts to mitigate risks
associated with downward price movements in benchmark NYMEX gas and oil prices
or, in the case of basis swaps, to protect the Company from increases in the
differential between NYMEX and Rocky Mountain gas prices. These derivatives
contracts generally represent cash flow hedges that are determined to be
qualifying or non-qualifying for hedge accounting treatment in accordance with
the provisions of SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities. Derivatives may be entered into in an effort to enhance
profitability, as well as mitigate risks. SFAS 133 prescribes that the fair value of all derivatives should be
recognized as either assets or liabilities on the balance sheet. SFAS 133 also
establishes requirements for designation and documentation of hedging
relationships and ongoing effectiveness assessments. Hedge effectiveness is
measured based on the relative changes over time in the fair values of a
derivative and the related hedged item. If a cash flow hedge qualifies for
hedge accounting under SFAS 133, and is so designated by the Company, changes
in the fair value of the derivative are recorded initially in other
comprehensive income and then recognized in the income statement when the
hedged item affects earnings. If a derivatives position does not qualify for
hedge accounting under SFAS 133, or if the Company so elects, changes in the
fair value of the derivative are immediately recognized in earnings. Prima
generally elects to use hedge accounting when conditions to do so are
satisfied. The Company has determined that pursuant to SFAS 133 requirements, and
based on its current sources of oil and gas production, that swaps, collars,
puts or floors that are based on NYMEX oil prices or Rocky Mountain gas prices
qualify for hedge accounting. Derivatives based on NYMEX gas prices will not so
qualify unless corresponding transactions are entered into to hedge basis
differentials between NYMEX and Rocky Mountain indices. In addition,
stand-alone basis differential swaps, sales of call options, and positions that
do not mitigate risk do not qualify for hedge accounting. The adoption of SFAS 133 as of January 1, 2001 resulted in the recognition
of a current asset of $1,241,000, a current liability of $549,000, net-of-tax
cumulative effect adjustments reducing other comprehensive income by $129,000,
and an increase in net income by $611,000. The $611,000 is reflected as the
cumulative effect of a change in accounting principle in the December 31, 2001
financial statements. Stock-Based Compensation At December 31, 2003, Prima had stock-based compensation plans in effect,
which are more fully described in Note 9. The Company accounts for stock-based
compensation using the intrinsic value recognition and measurement principles
prescribed in Accounting Principles Board Opinion No. 25, Accounting for Stock
Issued to Employees (APB No. 25) and related interpretations. No
stock-based compensation expense for employees or non-employee directors is
reflected in net income, as all options granted under those plans had an
exercise price equal to the market value of the underlying common stock on the
date of grant. For disclosure purposes, the fair value of options is measured at the date
of grant using the Black-Scholes option valuation model, which was developed
for use in estimating the fair value of traded options that have no vesting
restrictions and are fully transferable. Such option valuation models also
require the input of highly subjective assumptions, including the projected
life of the options and expected stock price volatility. Because options issued
under Primas stock-based compensation plans have characteristics significantly
different from those of traded options, and because changes in the subjective
input assumptions can materially affect the estimated fair value, these
valuation models do not necessarily provide a reliable measure of the fair
value of such stock options. 53




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The following assumptions were utilized to estimate the fair values of
options granted during the three years ended December 31, 2003, using the
Black-Scholes Valuation Model: 2003
    
    2002
    
    2001Expected dividend yield
    
    
    0
    %
    
    
    0
    %
    
    
    0
    %Expected price volatility
    
    
    48
    %
    
    
    41
    %
    
    
    43
    %Risk free interest rate
    
    
    3.5
    %
    
    
    2.9
    %
    
    
    5.1
    %Expected life of options (in years)
    
    
    6
    
    
    
    6
    
    
    
    6
 Based on the above, the estimated weighted average fair values of employee
stock options granted during 2003, 2002 and 2001 were $12.05, $11.52 and $16.04
respectively. The weighted average fair values of non-employee directors
options granted during 2003, 2002 and 2001 were $11.81, $9.04 and $12.49,
respectively. For purposes of pro forma disclosures, the estimated fair values of option
grants are amortized to expense over the options vesting periods. The
following table illustrates the effects on net income and earnings per share if
the Company had applied the fair value recognition provisions of SFAS No. 123. 2003
    
    2002
    
    2001Net IncomeAs reported
    
    $
    23,795,000
    
    
    $
    5,230,000
    
    
    $
    23,768,000Add stock-based employee compensation expense
included in reported net income, net of related tax
effects
    
    
    
    
    
    
    
    
    
    
    Less stock-based employee compensation expense
determined under fair value based method for all
awards, net of related income tax effects
    
    
    1,004,000
    
    
    
    888,000
    
    
    
    409,000Pro forma
    
    $
    22,791,000
    
    
    $
    4,342,000
    
    
    $
    23,359,000Basic Net Income per ShareAs reported
    
    $
    1.85
    
    
    $
    0.41
    
    
    $
    1.87Pro forma
    
    $
    1.78
    
    
    $
    0.34
    
    
    $
    1.83Diluted Net Income per ShareAs reported
    
    $
    1.82
    
    
    $
    0.40
    
    
    $
    1.80Pro forma
    
    $
    1.74
    
    
    $
    0.33
    
    
    $
    1.77
 Earnings Per Share Basic net income per share is computed by dividing net income by the
weighted average common shares outstanding during the period. Diluted net
income per share includes the potential dilution that could occur upon exercise
of the options to acquire common stock described in Note 9, computed using the
treasury stock method. The treasury stock method assumes that the increase in
the number of shares issued is reduced by the number of shares that could have
been repurchased by the Company with the proceeds from exercise of the options
(assuming an acquisition cost equal to the average market price of the common
shares during the reporting period). New Accounting Pronouncements In May 2003, the FASB issued SFAS No. 150, Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity to
improve the accounting for certain financial instruments that, under previous
guidance, issuers could account for as equity. SFAS No. 150 requires that
those instruments be classified as liabilities in statements of financial
position. SFAS No. 150 does not apply to features embedded in a financial
instrument that is not a derivative in its entirety. In addition to its
requirements for the classification and measurement of financial instruments
within its scope, SFAS No. 150 also requires disclosures about alternative ways
of settling the instruments and the capital structure of entities, all of whose
shares are mandatorily redeemable. Most of the guidance in Statement 150 is
effective for all financial instruments entered into or modified after May 31,
2003, and otherwise is effective at the beginning of the first interim period
beginning after June 15, 2003. As we have no such financial instruments, we do
not anticipate any impact on our financial position or results of operations
upon adoption. 54




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2. AVAILABLE-FOR-SALE SECURITIES Primas available-for-sale securities are comprised of marketable equity
securities, including closed-end bond funds. During the years ended December
31, 2003 and 2002, the Company sold securities with a market value of
$1,177,000 and $929,000, which resulted in realized gains of $66,000 in both
years. The Company determined that there was an other-than-temporary decline
in the fair market value of an individual security in its portfolio at the end
of 2002 and, accordingly, an impairment loss of $91,000 was recognized that
year. Other net unrealized losses on securities are included in accumulated
other comprehensive income, net of deferred income taxes of $17,000 and
$(16,000), respectively, at December 31, 2003 and 2002. The changes in net
unrealized losses on securities for the years ended December 31, 2003 and 2002
were as follows: 2003
    
    2002Net unrealized gain (loss), end of year
    
    $
    45,000
    
    
    $
    (44,000
    )Net unrealized (loss), beginning of year
    
    
    (44,000
    )
    
    
    (53,000
    )Net change in unrealized gain (loss)
    
    $
    89,000
    
    
    $
    9,000
 The components of fair value as of December 31, 2003 and 2002 were as follows: 2003
    
    2002Cost (including reinvested distributions)
    
    $
    1,229,000
    
    
    $
    1,788,000Gross unrealized gains
    
    
    61,000
    
    
    
    46,000Gross unrealized losses
    
    
    (16,000
    )
    
    
    (90,000
    )Fair value
    
    $
    1,274,000
    
    
    $
    1,744,000
 3. ASSET RETIREMENT OBLIGATIONS Our asset retirement obligations primarily represent the estimated present
value of the amounts we project will be incurred to plug, abandon and remediate
our oil and gas properties at the end of their productive lives, in accordance
with applicable laws and regulations. Our adoption of SFAS No. 143 as of
January 1, 2003 resulted in the recognition of an increase in the carrying
value of our oil and gas properties of $2,252,000, an increase in our
deferred tax liability of $217,000, an increase in other non-current
liabilities of $1,632,000, and a net-of-tax adjustment increasing net income by
$403,000, which was recorded as the cumulative effect of a change in accounting
principle. The estimated pro forma effects on periods prior to 2003 were not
material. A reconciliation of Primas recorded liability at the end of 2003
for asset retirement obligations is as follows: Upon adoption at January 1, 2003
    
    $
    1,632,000Liabilities incurred
    
    
    235,000Liabilities settled
    
    
    Accretion expense
    
    
    149,000Revision to estimate
    
    
    (113,000
    )$
    1,903,000
 55




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4. EARNINGS PER SHARE AND COMMON STOCK The following table reconciles the numerator and denominator used in the
calculation of basic and diluted net income per share. Income
    
    Shares
    
    Per Share(Numerator)
    
    (Denominator)
    
    AmountYear Ended December 31, 2003:Basic Net Income per Share
    
    $
    23,795,000
    
    
    
    12,824,123
    
    
    $
    1.85Effect of Stock Options
    
    
    
    
    
    
    237,497Diluted Net Income per Share
    
    $
    23,795,000
    
    
    
    13,061,620
    
    
    $
    1.82Year Ended December 31, 2002:Basic Net Income per Share
    
    $
    5,230,000
    
    
    
    12,770,716
    
    
    $
    0.41Effect of Stock Options
    
    
    
    
    
    
    450,660Diluted Net Income per Share
    
    $
    5,230,000
    
    
    
    13,221,376
    
    
    $
    0.40Year Ended December 31, 2001:Basic Net Income per Share
    
    $
    23,768,000
    
    
    
    12,731,181
    
    
    $
    1.87Effect of Stock Options
    
    
    
    
    
    
    487,970Diluted Net Income per Share
    
    $
    23,768,000
    
    
    
    13,219,151
    
    
    $
    1.80
 In January 2001, Primas Board of Directors approved a repurchase program
of up to 5% of the Companys common stock then outstanding or approximately
640,000 shares. In 2003, the Company purchased 111,868 treasury shares for
$2,111,000. The total of 348,406 shares repurchased to date represents
approximately 2.7% of the shares then outstanding, or 54% of the shares
authorized for repurchase under the program. As of December 31, 2003,
approximately 291,000 shares remained subject to repurchase under this
authorization. 5. DERIVATIVES CONTRACTS Prima periodically enters into derivative contracts to mitigate risks
associated with downward price movements in benchmark NYMEX oil and gas prices
or, in the case of basis swaps, to protect the Company from increases in the
differential between NYMEX and Rocky Mountain gas prices. While such hedges can
reduce the adverse effects of oil and gas price declines, they may also limit
the benefits of price increases. These derivatives contracts generally
represent cash flow hedges that are determined to be qualifying or
non-qualifying for hedge accounting treatment in accordance with the provisions
of SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities. Derivatives may be entered into in an effort to enhance
profitability, as well as mitigate risks. The Company has entered into various cash flow hedges related to its oil
and gas production. Some of these derivatives have qualified for hedge
accounting, while others have been non-qualifying. The derivative instruments
not qualifying for hedge accounting have principally been NYMEX gas swaps for
which we did not enter into
corresponding swaps for Rocky Mountain basis differentials. The following
table summarizes the income statement effects of these transactions for the
years shown: 2003
    
    2002
    
    2001Realized gains (losses) on derivatives qualifying for
hedge accounting, included in oil and gas sales
    
    $
    414,000
    
    
    $
    (458,000
    )
    
    $
    3,381,000Realized gains on non-qualifying hedges
    
    
    1,636,000
    
    
    
    1,546,000
    
    
    
    2,057,000Unrealized gains (losses) on non-qualifying hedges
    
    
    684,000
    
    
    
    (4,464,000
    )
    
    
    4,378,000Aggregate amounts reported on consolidated
statements of income
    
    $
    2,734,000
    
    
    $
    (3,376,000
    )
    
    $
    9,816,000
 56




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##### Table of Contents



In addition, $427,000 of realized losses on closed derivatives positions
that qualified for hedge accounting were included in other comprehensive income
at December 31, 2003 and will be included as a reduction of oil and gas sales
in 2004, as the related production months occur. As of December 31, 2003, Prima reported a net current liability of
$1,983,000, representing the fair value of its open derivatives contracts at
that date. These positions are summarized below: Market
    
    Total Volumes
    
    ContractTime Period
    
    Index
    
    (MMBtu or Bbls)
    
    Price
    
    Fair ValueNatural Gas:February  March 2004
    
    NYMEX
    
    
    600,000
    
    
    $
    6.38
    
    
    $
    172,000February  November 2004
    
    CIG
    
    
    3,500,000
    
    
    
    4.00
    
    
    
    (2,030,000
    )Oil:February  June 2004
    
    NYMEX
    
    
    75,000
    
    
    
    30.08
    
    
    
    (125,000
    )Total Net Fair Value
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    (1,983,000
    )
 Oil and gas prices are volatile and the market value of these derivatives
changes as the underlying commodity futures prices change. Actual gains or
losses realized will depend on the applicable futures prices in effect at the
time such positions are closed. Mark-to-market adjustments could result in
significant earnings volatility. 6. INCOME TAXES The provision for income taxes consists of the following components: 2003
    
    2002
    
    2001Current:Federal
    
    $
    4,713,000
    
    
    $
    1,636,000
    
    
    $
    2,067,000State
    
    
    386,000
    
    
    
    166,000
    
    
    
    (275,000
    )5,099,000
    
    
    
    1,802,000
    
    
    
    1,792,000Deferred:Federal
    
    
    4,090,000
    
    
    
    (429,000
    )
    
    
    8,732,000State
    
    
    412,000
    
    
    
    (35,000
    )
    
    
    782,0004,502,000
    
    
    
    (464,000
    )
    
    
    9,514,000Tax credits
    
    
    2,131,000
    
    
    
    (513,000
    )
    
    
    (391,000
    )Provision for income taxes
    
    $
    11,732,000
    
    
    $
    825,000
    
    
    $
    10,915,000
 During 2003, 2002 and 2001, the Company recognized income tax deductions
of $5,171,000, $3,375,000 and $1,979,000, respectively, from the exercise of
nonqualified stock options. Stockholders equity has been credited in the
amount of $1,913,000, $1,250,000 and $732,000 for the income tax benefit of
these deductions. The provisions for income taxes in 2003 and 2001 included
$217,000 and $265,000, respectively, of expense that was netted in the
cumulative effects of changes in accounting principle. During 2001, Prima
recognized taxable income of $207,000 from short-swing profits and
stockholders equity was reduced in the amount of $77,000 for the current
income tax expense associated with this income. 57




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The significant components of deferred tax assets and liabilities included
on the balance sheet are as follows: 2003
    
    2002Deferred Tax Assets:Minimum tax credit carryforwards
    
    $
    110,000
    
    
    $
    2,241,000State income taxes
    
    
    764,000
    
    
    
    648,000Derivatives
    
    
    734,000
    
    
    
    83,000Asset retirement obligations
    
    
    704,000
    
    
    
    Other
    
    
    247,000
    
    
    
    310,000Total Deferred Tax Assets
    
    
    2,559,000
    
    
    
    3,282,000Deferred Tax Liabilities:Intangible drilling costs
    
    
    28,192,000
    
    
    
    22,666,000Depreciation
    
    
    843,000
    
    
    
    742,000Land held for investment
    
    
    370,000
    
    
    
    370,000Other
    
    
    1,000
    
    
    
    589,000Total Deferred Tax Liabilities
    
    
    29,406,000
    
    
    
    24,367,000Net Deferred Tax Liabilities
    
    $
    26,847,000
    
    
    $
    21,085,000
 A reconciliation of income tax computed at the federal statutory tax rate to
the Companys effective tax rate follows: 2003
    
    2002
    
    2001Federal statutory income tax rate
    
    
    34.0
    %
    
    
    34.0
    %
    
    
    34.0
    %Percentage depletion
    
    
    (1.4
    )
    
    
    (6.3
    )
    
    
    (1.2
    )Section 29 credits
    
    
    
    
    
    
    (15.8
    )
    
    
    (3.0
    )State taxes, net of federal benefits
    
    
    1.4
    
    
    
    1.5
    
    
    
    1.0Other
    
    
    (1.0
    )
    
    
    0.3
    
    
    
    0.7Effective tax rate
    
    
    33.0
    %
    
    
    13.7
    %
    
    
    31.5
    %
 At December 31, 2003, Prima had minimum tax credit carryforwards of
approximately $110,000, which may be carried forward indefinitely. 7. SEGMENT INFORMATION The Company organizes its activities in operating segments that consist of
1) the acquisition, exploration, development and operation of oil and gas
properties and the development, production and sale of oil
and natural gas and 2) providing oilfield services for wells which it
operates and for third parties. The Companys activities have been conducted
primarily in the Rocky Mountain region of the United States, which is one
geographic area. The information below presents the operating segment data for the Company
on the basis used by management in deciding how to allocate resources and in
assessing performance. The following table sets forth revenues, operating
earnings before income taxes, identifiable assets, depreciation, depletion and
amortization expense and capital expenditures for the years ended December 31,
2003, 2002 and 2001. This information is presented on the basis used by
management, which is the same basis used in the preparation of the Companys
consolidated financial statements. 58




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##### Table of Contents



2003
    
    2002
    
    2001RevenuesOil & gas (including derivative effects)
    
    $
    60,942,000
    
    
    $
    22,867,000
    
    
    $
    50,983,000Oilfield services
    
    
    11,333,000
    
    
    
    10,325,000
    
    
    
    12,207,00072,275,000
    
    
    
    33,192,000
    
    
    
    63,190,000Corporate
    
    
    635,000
    
    
    
    597,000
    
    
    
    1,214,000Intersegment eliminations
    
    
    (2,756,000
    )
    
    
    (1,999,000
    )
    
    
    (4,117,000
    )Per financial statements
    
    $
    70,154,000
    
    
    $
    31,790,000
    
    
    $
    60,287,000Operating EarningsOil & gas (including derivative effects)
    
    $
    36,584,000
    
    
    $
    7,965,000
    
    
    $
    34,913,000Oilfield services
    
    
    1,746,000
    
    
    
    1,094,000
    
    
    
    2,083,00038,330,000
    
    
    
    9,059,000
    
    
    
    36,996,000Corporate
    
    
    (2,932,000
    )
    
    
    (2,906,000
    )
    
    
    (2,624,000
    )Intersegment eliminations
    
    
    (491,000
    )
    
    
    (98,000
    )
    
    
    (565,000
    )Per financial statements
    
    $
    34,907,000
    
    
    $
    6,055,000
    
    
    $
    33,807,000Identifiable AssetsOil & gas
    
    $
    112,267,000
    
    
    $
    95,300,000
    
    
    $
    100,200,000Oilfield services
    
    
    5,942,000
    
    
    
    6,322,000
    
    
    
    7,218,000118,209,000
    
    
    
    101,622,000
    
    
    
    107,418,000Corporate
    
    
    59,008,000
    
    
    
    40,305,000
    
    
    
    28,026,000Per financial statements
    
    $
    177,217,000
    
    
    $
    141,927,000
    
    
    $
    135,444,000Depreciation, Depletion and AmortizationOil & gas
    
    $
    14,956,000
    
    
    $
    9,710,000
    
    
    $
    9,190,000Oilfield services
    
    
    977,000
    
    
    
    832,000
    
    
    
    767,00015,933,000
    
    
    
    10,542,000
    
    
    
    9,957,000Corporate
    
    
    81,000
    
    
    
    256,000
    
    
    
    272,000Per financial statements
    
    $
    16,014,000
    
    
    $
    10,798,000
    
    
    $
    10,229,000Capital ExpendituresOil & gas
    
    $
    26,856,000
    
    
    $
    22,252,000
    
    
    $
    35,248,000Oilfield services
    
    
    1,358,000
    
    
    
    868,000
    
    
    
    1,539,00028,214,000
    
    
    
    23,120,000
    
    
    
    36,787,000Corporate
    
    
    65,000
    
    
    
    274,000
    
    
    
    419,000Per financial statements
    
    $
    28,279,000
    
    
    $
    23,394,000
    
    
    $
    37,206,000
 Total revenue by operating segment includes both sales to unaffiliated
customers, as reported in the Companys consolidated income statement, and
intersegment sales that are eliminated in consolidation, which represent
oilfield services provided for Company-operated wells. Oilfield services
revenue is priced and accounted for consistently for both unaffiliated and
intersegment sales. Identifiable assets by operating segment are those assets that are used in
the Companys operations in each segment. Corporate assets are principally
cash, cash equivalents and available-for-sale securities. Following is a table summarizing the percentage of sales made to each
customer that accounted for over 10% of the Companys consolidated revenues.
Although the loss of any of these customers could have a material adverse
effect on Prima, the Company believes it would be able to locate other
customers to purchase its production. 2003
    
    2002
    
    2001Duke Energy Field Services, LLC
    
    
    27
    %
    
    
    33
    %
    
    
    31
    %Western Gas Resources, Inc.
    
    
    27
    
    
    
    *
    
    
    
    *Valero Energy Corporation
    
    
    17
    
    
    
    29
    
    
    
    16
 * Less than 10% 59




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8. COMMITMENTS AND CONTINGENCIES Prima entered into a seven-year office space lease for its Denver
headquarters effective December 1, 2000. Related office lease expense totaled
$316,000, $295,000 and $282,000 for the years ended December 31, 2003, 2002 and
2001, respectively. Future minimum annual rentals under this non-cancelable
operating lease are as follows: Year ending December 31, 2004
    
    $
    317,000Year ending December 31, 2005
    
    
    317,000Year ending December 31, 2006
    
    
    317,000Year ending December 31, 2007
    
    
    290,000$
    1,241,000
 The Company is aware of various legal and regulatory
proceedings in several states, including Colorado and Wyoming, concerning calculation of royalties and production taxes payable by oil and gas producers. Prima
is not a named party in any such proceeding, but could potentially be impacted by the outcome of one or more of them. No assessment can be made at the present
time as to the likelihood or magnitude of any such impact. From time to time, the Company may be involved in litigation that arises
in the ordinary course of business operations. As of the date of this report,
the Company is not a party to any litigation that it believes could reasonably
be expected to have a material adverse effect on its business or results of
operations. 9. BENEFIT PLANS Employee Stock Option Plans Under Primas 1993 Stock Incentive Plan and 2001 Stock Incentive Plan,
2,650,000 shares of the Companys common stock were reserved for issuance
pursuant to options granted to key employees at exercise prices no less than
fair market value on the dates of grant. The 1993 Plan terminated in
September of 2003.
Options granted to date under the plans vest ratably over three to five
years, and expire ten years from the date of grant. A summary of options
granted, exercised and outstanding during the three years ended December 31,
2003 is as follows: Number
    
    Weighted Averageof Shares
    
    Exercise PricesBalance at December 31, 2000
    
    
    911,975
    
    
    $
    5.49Granted during 2001
    
    
    216,000
    
    
    
    32.53Exercised in 2001
    
    
    (86,425
    )
    
    
    5.01Forfeited in 2001
    
    
    (3,600
    )
    
    
    9.39Outstanding at December 31, 2001
    
    
    1,037,950
    
    
    
    11.14Granted during 2002
    
    
    171,500
    
    
    
    25.36Exercised in 2002
    
    
    (174,125
    )
    
    
    4.79Forfeited in 2002
    
    
    (109,000
    )
    
    
    25.91Outstanding at December 31, 2002
    
    
    926,325
    
    
    
    13.20Granted during 2003
    
    
    130,750
    
    
    
    23.92Exercised in 2003
    
    
    (226,000
    )
    
    
    4.84Forfeited in 2003
    
    
    (9,500
    )
    
    
    28.92Outstanding at December 31, 2003
    
    
    821,575
    
    
    
    16.96Exercisable at December 31, 2001
    
    
    648,625
    
    
    
    5.01Exercisable at December 31, 2002
    
    
    601,092
    
    
    
    7.37Exercisable at December 31, 2003
    
    
    519,583
    
    
    
    11.26
 At the end of 2003, the number of shares of common stock remaining available
for future option grants under these plans totaled 1,039,750. 60




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Non-Employee Directors Stock Option Plan Under Primas Non-Employee Directors Stock Option Plan, 225,000 shares of
Primas common stock were reserved for issuance pursuant to options granted to
non-employee directors at exercise prices no less than fair market value on the
dates of grant. This plan provides for each non-employee director to receive a
grant of 22,500 options on the effective date of the plan, or upon election as
a non-employee director if later. On each anniversary date of the initial
grant, an additional 5,625 options are granted to each non-employee director.
Options vest ratably over five years and expire ten years from the date of
grant. A summary of options granted, exercised and outstanding during the
three years ended December 31, 2003 is as follows: Number
    
    Weighted Averageof Shares
    
    Exercise PricesBalance at December 31, 2000
    
    
    146,250
    
    
    $
    14.94Granted during 2001
    
    
    22,500
    
    
    
    25.49Exercised during 2001
    
    
    (10,125
    )
    
    
    7.02Forfeited during 2001
    
    
    (23,625
    )
    
    
    10.86Outstanding at December 31, 2001
    
    
    135,000
    
    
    
    17.57Granted during 2002
    
    
    22,500
    
    
    
    20.52Exercised during 2002
    
    
    
    
    
    
    Forfeited during 2002
    
    
    
    
    
    
    Outstanding at December 31, 2002
    
    
    157,500
    
    
    
    17.99Granted during 2003
    
    
    22,500
    
    
    
    23.49Exercised during 2003
    
    
    (22,500
    )
    
    
    6.67Forfeited during 2003
    
    
    
    
    
    
    Outstanding at December 31, 2003
    
    
    157,500
    
    
    
    20.39Exercisable at December 31, 2001
    
    
    42,750
    
    
    
    11.74Exercisable at December 31, 2002
    
    
    69,750
    
    
    
    13.99Exercisable at December 31, 2003
    
    
    78,750
    
    
    
    17.69
 At the end of 2003, the number of shares of common stock remaining available
for future option grants under this plan was 30,375. Summary of Outstanding Options The following table summarizes information about stock options outstanding
at December 31, 2003 on a combined basis for the employee and non-employee
directors plans: Stock Options Outstanding
    
    Stock Options ExercisableWeighted-Number
    
    Average
    
    Weighted-
    
    Number
    
    Weighted-Range of
    
    Outstanding at
    
    Remaining
    
    Average
    
    Exercisable at
    
    AverageExercise Prices
    
    12/31/03
    
    Contractual Life
    
    Exercise Price
    
    12/31/03
    
    Exercise Price$4.41     9.83
    
    
    455,575
    
    
    
    3.5
    
    
    $
    6.00
    
    
    
    447,250
    
    
    $
    5.9416.18
    
    
    5,625
    
    
    
    8.6
    
    
    
    16.18
    
    
    
    1,125
    
    
    
    16.1820.19  25.83
    
    
    199,000
    
    
    
    8.1
    
    
    
    22.88
    
    
    
    37,525
    
    
    
    22.9026.38  33.25
    
    
    318,875
    
    
    
    7.7
    
    
    
    30.63
    
    
    
    112,433
    
    
    
    31.58979,075
    
    
    
    
    
    
    
    17.51
    
    
    
    598,333
    
    
    
    11.84
 61




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Employee Stock Ownership Plan The Company has an Employee Stock Ownership Plan (ESOP), which is
administered pursuant to a Trust Agreement. The ESOP is qualified under
Section 401(a) of the Internal Revenue Code of 1986, as amended, and is for the
benefit of all eligible employees of the Company. Company contributions are
payable at a minimum rate of 5% of eligible salaries during the ESOPs fiscal
year ending September 30, and are generally made quarterly. Through September
30, 1993, the ESOP provided for contributions to be used to purchase Prima
common stock on the open market. Effective October 1, 1993, the ESOP was
amended to allow fully-vested employees the option to direct the Trustees to
diversify a portion of their investments by selling a limited portion of Prima
common stock held in their account and investing the proceeds, as well as new
contributions, in various diversified investment options. The ESOP benefits
all full-time employees and provides for vesting in increments over six years.
For the years ended December 31, 2003, 2002 and 2001, Prima expensed $363,000,
$339,000 and $316,000, respectively, for its contributions to the ESOP. 10. TRANSACTIONS WITH RELATED PARTIES The Company acquired oil and gas leases covering 26,680 net undeveloped
acres in June 2000 from a company controlled by a director of Prima for a
negotiated price of $12 per net acre, or a total of approximately $320,000.
Additional acreage in the same general area was subsequently acquired from this
director at cost. The aggregate amounts paid for these property interests,
including the initial acquisition, totaled $3,000 in 2002, $290,000 in 2001 and
$376,000 in 2000. The director, or entities controlled by him, reserved an
overriding royalty interest in all acquired leases of 3% or less, depending on
the net revenue interest of the leases, proportionately reduced to the working
interest acquired. The disinterested members of the Board of Directors approved
the transactions. One of the Companys directors and one officer has participated,
individually or through controlled entities, in oil and gas properties in which
Prima has an interest. These working interest participations have been in
prospects or properties originated or acquired by the Company. In some cases,
the interests sold to affiliated and non-affiliated participants were sold on a
promoted basis requiring these participants to pay a disproportionate share of
well costs. All participations by directors and officers have been on terms no
less favorable to the Company than believed to be obtainable from
non-affiliated participants. Such joint participations may occur again from
time to time in the future. All participations by officers or directors have
been and will continue to be approved by the disinterested members of the
Companys Board of Directors. At any point in time, there may be receivables
or payables with officers and directors that arise in the ordinary course of
business, as a result of participations in jointly held oil and gas properties.
Amounts due to or from officers and directors resulting from billings of joint
interest costs or receipts of production revenues on these properties are
handled on terms pursuant to standard industry joint operating agreements which
are no more or less favorable than similar transactions with unrelated parties. Prima is a 6% limited partner in a real estate limited partnership that
owns approximately 22 acres of undeveloped land in Phoenix, Arizona for
investment. One of the general partners of the partnership is a company
controlled by a brother of the Companys president. Prima participated on the
same basis as the other limited partners. The disinterested members of the
Companys Board of Directors approved the transaction. During the three years
ended December 31, 2003, Prima did not make any capital contributions to the
partnership, nor did it receive any distributions therefrom. During 2003, the
Company recorded a $116,000 valuation impairment to reduce the carrying value
of the asset from $257,000 to $141,000, to reflect expected net proceeds from a
pending sales agreement with an unrelated third party. 11. SALE OF ASSETS On March 5, 2002, Prima sold all of its producing wells in the Stones
Throw coalbed methane project in the northern Powder River Basin, along with
associated gathering system facilities and approximately 35,000 net
undeveloped acres in the immediate vicinity. Net proceeds from the
transaction totaled $13,514,000 after normal closing adjustments and were
credited to the carrying value of oil and gas properties. These properties
accounted for 62




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approximately 6.1% of Primas total estimated proved oil and gas
reserves and 4.5% of the related estimated present value of future net cash
flows before income taxes, as of the end of 2001. The producing wells sold
accounted for approximately 17% of Primas net oil and gas production and 8% of
its total oil and gas sales revenue before hedging effects during the first two
months of 2002, and approximately 11% of net oil and gas production and 5% of
total oil and gas sales revenue before hedging effects for the year 2001. 12. SUPPLEMENTARY OIL AND GAS INFORMATION Primas oil and gas operations are conducted entirely in the United
States, primarily in the Rocky Mountain region. Certain information concerning
these activities follows: Costs Incurred Costs incurred in oil and gas property acquisition,
exploration and development activities, and related depletion per equivalent
units of production were as follows: 2003
    
    2002
    
    2001Development costs
    
    $
    19,776,000
    
    
    $
    15,157,000
    
    
    $
    31,114,000Exploration costs
    
    
    6,730,000
    
    
    
    5,685,000
    
    
    
    1,620,000Acquisition costs:Unproved properties
    
    
    326,000
    
    
    
    876,000
    
    
    
    2,114,000Proved properties
    
    
    24,000
    
    
    
    534,000
    
    
    
    400,000Total before asset retirement obligations
    
    
    26,856,000
    
    
    
    22,252,000
    
    
    
    35,248,000Asset retirement obligations
    
    
    122,000
    
    
    
    
    
    
    
    Total
    
    $
    26,978,000
    
    
    $
    22,252,000
    
    
    $
    35,248,000Depletion cost per equivalent Mcf of production
    
    $
    0.97
    
    
    $
    0.92
    
    
    $
    0.77
 Costs Not Being Amortized Oil and gas property costs not being
amortized at December 31, 2003 consisted of $27,317,000 of leasehold costs and
well costs for wells under evaluation. The Company anticipates that
substantially all unevaluated costs will be classified as evaluated costs
within three years. Results of Operations Results of operations for oil and gas producing
activities were as follows: 2003
    
    2002
    
    2001RevenuesOil and gas sales
    
    $
    58,622,000
    
    
    $
    25,785,000
    
    
    $
    44,548,000Gains (losses) on derivative instruments, net
    
    
    2,320,000
    
    
    
    (2,918,000
    )
    
    
    6,435,00060,942,000
    
    
    
    22,867,000
    
    
    
    50,983,000ExpensesDepletion of oil and gas properties
    
    
    14,956,000
    
    
    
    9,710,000
    
    
    
    9,190,000Lease operating expense
    
    
    3,619,000
    
    
    
    3,076,000
    
    
    
    3,295,000Ad valorem and production taxes
    
    
    5,783,000
    
    
    
    2,116,000
    
    
    
    3,344,000Impairment of natural gas swap
    
    
    
    
    
    
    
    
    
    
    241,00024,358,000
    
    
    
    14,902,000
    
    
    
    16,070,000Income before income taxes
    
    
    36,584,000
    
    
    
    7,965,000
    
    
    
    34,913,000Income tax expense
    
    
    12,073,000
    
    
    
    1,083,000
    
    
    
    10,998,000Income from oil and gas producing activities
    
    $
    24,511,000
    
    
    $
    6,882,000
    
    
    $
    23,915,000
 Supplemental Oil and Gas Reserve Information (Unaudited) The reserve information presented below is based on estimates of net
proved reserves as of December 31, 2003, 2002 and 2001 that were prepared by
Primas engineers and audited by Netherland, Sewell and Associates, Inc., 63




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independent petroleum engineers. There are numerous uncertainties inherent in
estimating quantities of proved reserves and in projecting future rates of
production and timing of development expenditures. Oil and gas reserve
engineering should be recognized as a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured in an
exact way. The accuracy of any reserve estimates is a function of the quality
of available data and engineering and geological interpretation and judgment.
Results of drilling, testing and production after the date of the estimate may
require revisions. Accordingly, reserve estimates are often materially
different from the quantities of oil and natural gas that are ultimately
produced. Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed oil and gas reserves are those proved reserves expected to be
recovered through existing wells with existing equipment and operating methods. Analyses of Changes in Proved Reserves The following table sets forth
information regarding the Companys estimated net total proved and proved
developed oil and gas reserve quantities: 2003
    
    2002
    
    2001Oil
    
    Gas
    
    Oil
    
    Gas
    
    Oil
    
    Gas(Mbbls)
    
    (MMcf)
    
    (Mbbls)
    
    (MMcf)
    
    (Mbbls)
    
    (MMcf)Proved reserves:Beginning of year
    
    
    3,944
    
    
    
    87,440
    
    
    
    3,394
    
    
    
    115,222
    
    
    
    3,729
    
    
    
    154,172Purchases of oil and
gas reserves in place
    
    
    44
    
    
    
    355
    
    
    
    5
    
    
    
    899
    
    
    
    
    
    
    
    2,388Net exchanges of oil and gas
reserves in place
    
    
    
    
    
    
    (3,686
    )
    
    
    
    
    
    
    (331
    )
    
    
    10
    
    
    
    (2,051
    )Revisions of previous
estimates
    
    
    370
    
    
    
    17,162
    
    
    
    188
    
    
    
    (17,744
    )
    
    
    (611
    )
    
    
    (44,495
    )Extensions, discoveries
and other additions
    
    
    1,009
    
    
    
    8,809
    
    
    
    730
    
    
    
    5,665
    
    
    
    697
    
    
    
    14,485Production
    
    
    (401
    )
    
    
    (13,015
    )
    
    
    (373
    )
    
    
    (8,343
    )
    
    
    (431
    )
    
    
    (9,277
    )Sales of oil and gas
reserves in place
    
    
    
    
    
    
    (1,065
    )
    
    
    
    
    
    
    (7,928
    )
    
    
    
    
    
    
    End of year
    
    
    4,966
    
    
    
    96,000
    
    
    
    3,944
    
    
    
    87,440
    
    
    
    3,394
    
    
    
    115,222Proved developed reserves:Beginning of year
    
    
    3,115
    
    
    
    66,245
    
    
    
    2,949
    
    
    
    69,168
    
    
    
    2,945
    
    
    
    77,385End of year
    
    
    3,306
    
    
    
    67,983
    
    
    
    3,115
    
    
    
    66,245
    
    
    
    2,949
    
    
    
    69,168
 SFAS No. 69, Disclosures about Oil and Gas Producing Activities,
prescribes guidelines for computing a standardized measure of future net cash
flows and changes therein relating to estimated proved reserves. The Company
has followed these guidelines, which are briefly discussed below. Future cash inflows and future production and development costs are
determined by applying benchmark prices and costs, adjusted for applicable
transportation, quality and other basis differential variances for the
Companys properties that were in effect at year-end to the year-end estimated
quantities of oil and gas to be produced in the future. Each property operated
is also charged with overhead in the estimated reserve calculation. Estimated
future income taxes are computed using current statutory income tax rates,
including consideration for estimated future statutory depletion. The resulting
future net cash flows are reduced to present value amounts by applying a 10%
annual discount factor. Future operating costs are determined based on estimates of expenditures
to be incurred in developing and producing the proved oil and gas reserves in
place at the end of the period, using year-end costs and assuming 64




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continuation of existing economic conditions, plus Company overhead incurred by the central
administrative office attributable to operating activities. The assumptions used to compute the standardized measure are those
prescribed by the FASB and the Securities and Exchange Commission. These
assumptions do not necessarily reflect the Companys expectations of actual
revenues to be derived from those reserves, nor their present worth. The
limitations inherent in the reserve quantity estimation process, as discussed
previously, are equally applicable to the standardized measure computations
since these estimates are the basis for the valuation process. The following
average prices, which reflect all appropriate adjustments for transportation,
quality and other basis differential factors, were used in the calculation of
the standardized measure at the end of each year shown: 2003
    
    2002
    
    2001Natural gas (per Mcf)
    
    $
    4.95
    
    
    $
    2.64
    
    
    $
    1.94Oil (per barrel)
    
    
    32.88
    
    
    
    31.30
    
    
    
    19.71
 Standardized Measure The following table presents the standardized
measure of discounted future net cash flows related to proved oil and gas
reserves. 2003
    
    2002
    
    2001Future cash inflows
    
    $
    638,404,000
    
    
    $
    354,617,000
    
    
    $
    290,303,000Future production costs
    
    
    (162,617,000
    )
    
    
    (93,357,000
    )
    
    
    (90,816,000
    )Future development costs
    
    
    (65,486,000
    )
    
    
    (39,484,000
    )
    
    
    (42,863,000
    )Future net cash flows
    
    
    410,301,000
    
    
    
    221,776,000
    
    
    
    156,624,00010% discount factor
    
    
    (170,501,000
    )
    
    
    (92,933,000
    )
    
    
    (64,719,000
    )Discounted future income taxes
    
    
    (80,821,000
    )
    
    
    (37,564,000
    )
    
    
    (25,104,000
    )Standardized measure of discounted future
net cash flows
    
    $
    158,979,000
    
    
    $
    91,279,000
    
    
    $
    66,801,000
 A summary of changes in the standardized measure of discounted future net cash flows is as follows: 2003
    
    2002
    
    2001Standardized measure of discounted future net
cash flows, beginning of year
    
    $
    91,279,000
    
    
    $
    66,801,000
    
    
    $
    371,121,000Sales of oil and gas, net of production costs and
production taxes
    
    
    (48,806,000
    )
    
    
    (21,136,000
    )
    
    
    (34,057,000
    )Net changes in prices and production costs
    
    
    88,726,000
    
    
    
    42,497,000
    
    
    
    (469,638,000
    )Extensions, discoveries, and improved recovery,
less related costs
    
    
    19,951,000
    
    
    
    9,728,000
    
    
    
    8,680,000Development costs incurred during the year
    
    
    10,490,000
    
    
    
    7,518,000
    
    
    
    19,920,000Changes in estimated future development costs
    
    
    (11,620,000
    )
    
    
    (3,313,000
    )
    
    
    11,381,000Revisions of previous quantity estimates
    
    
    41,531,000
    
    
    
    (5,089,000
    )
    
    
    (46,997,000
    )Purchases of reserves in place
    
    
    904,000
    
    
    
    640,000
    
    
    
    1,088,000Net exchanges of reserves in place
    
    
    (1,215,000
    )
    
    
    (403,000
    )
    
    
    (7,429,000
    )Sales of reserves in place
    
    
    (551,000
    )
    
    
    (4,056,000
    )
    
    
    Other
    
    
    (1,337,000
    )
    
    
    1,360,000
    
    
    
    (4,207,000
    )Accretion of discount
    
    
    12,884,000
    
    
    
    9,191,000
    
    
    
    37,112,000Net changes in future income taxes
    
    
    (43,257,000
    )
    
    
    (12,459,000
    )
    
    
    179,827,000Standardized measure of discounted future net
cash flows, end of year
    
    $
    158,979,000
    
    
    $
    91,279,000
    
    
    $
    66,801,000
 65




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13. QUARTERLY FINANCIAL DATA (UNAUDITED) The following is a summary of the unaudited financial data for each
quarter for the years ended December 31, 2003 and 2002. Three Months Ended12/31/03
    
    9/30/03
    
    6/30/03
    
    3/31/03Year Ended December 31, 2003Revenues
    
    $
    19,875,000
    
    
    $
    18,229,000
    
    
    $
    16,440,000
    
    
    $
    15,610,000Gross profit (1)
    
    
    15,208,000
    
    
    
    14,427,000
    
    
    
    12,381,000
    
    
    
    11,591,000Income before income tax
    
    
    9,782,000
    
    
    
    9,838,000
    
    
    
    7,858,000
    
    
    
    7,429,000Net income
    
    
    6,557,000
    
    
    
    6,593,000
    
    
    
    5,263,000
    
    
    
    5,382,000Basic net income per share (2)
    
    
    0.51
    
    
    
    0.51
    
    
    
    0.41
    
    
    
    0.42Diluted net income per share (2)
    
    
    0.50
    
    
    
    0.50
    
    
    
    0.40
    
    
    
    0.41
 Three Months Ended12/31/02
    
    9/30/02
    
    6/30/02
    
    3/31/02Year Ended December 31, 2002Revenues
    
    $
    10,233,000
    
    
    $
    7,432,000
    
    
    $
    8,718,000
    
    
    $
    5,407,000Gross profit (1)
    
    
    7,412,000
    
    
    
    4,364,000
    
    
    
    5,490,000
    
    
    
    2,245,000Income before income tax
    
    
    3,421,000
    
    
    
    1,226,000
    
    
    
    2,470,000
    
    
    
    (1,062,000
    )Net income
    
    
    2,936,000
    
    
    
    1,026,000
    
    
    
    1,990,000
    
    
    
    (722,000
    )Basic net income per share (2)
    
    
    0.23
    
    
    
    0.08
    
    
    
    0.16
    
    
    
    (0.06
    )Diluted net income per share (2)
    
    
    0.22
    
    
    
    0.08
    
    
    
    0.15
    
    
    
    (0.06
    )
   (1)
    
    Gross profit is computed as the excess of oil and gas sales, gains or
losses on derivatives instruments, and revenues from oilfield services
over operating expenses. Operating expenses include lease operating
expense, ad valorem and production taxes, and oilfield services expenses.(2)
    
    The sum of the individual quarterly net income (loss) per share may not
agree with year-to-date net income (loss) per share as each periods
computation is based on the weighted average number of common shares
outstanding during the period. 66




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SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, Prima Energy Corporation has duly caused this Annual
Report on Form 10-K to be signed on its behalf by the undersigned, thereunto
duly authorized, in Denver, Colorado on the 12th day of March, 2004. PRIMA ENERGY CORPORATIONBy:
    /s/ Richard H. LewisRichard H. Lewis, President Pursuant to the requirements of the Securities Exchange Act of 1934, this
Annual Report on Form 10-K has been signed below by the following persons in
the capacities indicated and on the dates indicated. Signature
    
    Title
    
    Date/s/ Richard H. Lewis

Richard H. Lewis
    
    Chairman of the Board and
President
(Principal Executive Officer)
    
    March 12, 2004/s/ Neil L. Stenbuck
Neil L. Stenbuck
    
    Executive Vice President - Finance,
Treasurer and Director
(Principal Financial Officer)
    
    March 12, 2004/s/ Sandra J. Irlando
Sandra J. Irlando
    
    Vice President - Accounting
(Principal Accounting Officer)
    
    March 12, 2004/s/ James R. Cummings
James R. Cummings
    
    Director
    
    March 12, 2004/s/ Douglas J. Guion
Douglas J. Guion
    
    Director
    
    March 12, 2004/s/ Catherine J. Paglia
Catherine J. Paglia
    
    Director
    
    March 12, 2004/s/ George L. Seward
George L. Seward
    
    Director
    
    March 12, 2004
 67




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Exhibit No.
    
    Document3.1
    
    Certificate of Incorporation of Prima Energy Corporation,
Delaware, as filed August 18, 1988. (Incorporated by reference to
Registration of Securities of Certain Successor Issuers on Form 8-B
dated January 20, 1989.)3.2
    
    Certificate of Amendment of Certificate of Incorporation of
Prima Energy Corporation filed May 1, 1989. (Incorporated by
reference to Annual Report on Form 10-K for Prima Energy
Corporation for the year ended June 30, 1989.)3.3
    
    Bylaws of Prima Energy Corporation. (Incorporated by reference
to Registration of Securities of Certain Successor Issuers on Form
8-B dated January 20, 1989.)3.4
    
    Certificate of Amendment of the Certificate of Incorporation of
Prima Energy Corporation. (Incorporated by reference to Quarterly
Report on Form 10-Q for Prima Energy Corporation for the quarter
ended June 30, 1997.)3.5
    
    Certificate of Amendment of the Certificate of Incorporation of
Prima Energy Corporation. (Incorporated by reference to Quarterly
Report on Form 10-Q for Prima Energy Corporation for the quarter
ended September 30, 2000.)3.6
    
    Certificate of Amendment of the Certificate of Incorporation of
Prima Energy Corporation. (Incorporated by reference to Quarterly
Report on Form 10-Q for Prima Energy Corporation for the quarter
ended June 30, 2001.)4.1
    
    Rights Agreement dated as of May 23, 2001, between Prima Energy
Corporation and Computershare Trust Company, Inc., as Rights Agent,
including the form of Certificate of Designation, Powers,
Preferences and Rights of Series A Participating Preferred Stock
dated May 29, 2001, the Form of Right Certificate, and the Summary
of Rights to Purchase Preferred Shares. (Incorporated by reference
to Current Report on Form 8-K for Prima Energy Corporation dated May
23, 2001.)10.1
    
    Prima Energy Corporation Employee Stock Ownership Plan
(Incorporated by reference to Annual Report on Form 10-K for Prima
Energy Corporation for the year ended June 30, 1989.)10.2
    
    Prima Energy Corporation 1993 Stock Incentive Plan.
(Incorporated by reference to Annual Report on Form 10-K for Prima
Energy Corporation for the year ended December 31, 1993.)10.3
    
    Agreement of Lease between Denver-Stellar Associates LP,
Landlord and Prima Energy Corporation, Tenant, effective December 1,
2001. (Incorporated by reference to Annual Report on Form 10-K for
Prima Energy Corporation for the year ended December 31, 2000.)10.4
    
    Prima Energy Corporation Non-Employee Directors Stock Option
Plan. (Incorporated by reference to Quarterly Report on Form 10-Q
for Prima Energy Corporation for quarter ended March 31, 2002.)10.5
    
    Prima Energy Corporation 2001 Stock Incentive Plan.
(Incorporated by reference to Quarterly Report on Form 10-Q for
Prima Energy Corporation for the quarter ended March 31, 2002.)14.1
    
    Prima Energy Corporation Code of Ethics for Senior Financial Officers21.1
    
    Subsidiaries of the Registrant23.1
    
    Independent Auditors Consent23.2
    
    Independent Reservoir Engineers and Geologists Consent31.1
    
    Certification of Chief Executive Officer pursuant to Rule
13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as
amended31.2
    
    Certification of Chief Financial Officer pursuant to Rule13(a)-14(a) /15d-14(a) of the Securities Exchange Act of 1934, as
amended32.1
    
    Certification of Chief Executive Officer and Chief Financial
Officer pursuant to 18 USC Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002