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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM 10-K

|  |  |                                                                                                                                  
|- |  | ---------------------------------------------------------------------------------------------------------------------------------
|x |  | Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2002.
|  |  |                                                                                                                                  
|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

(Exact name of Registrant as specified in its charter)


|                                                                        |  |                                                
|----------------------------------------------------------------------- |  | -----------------------------------------------
|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 9,198,101 shares of voting stock held by
non-affiliates of the Registrant, based upon the closing price of the common
stock on June 28, 2002 of $22.79 per share as reported on the Nasdaq National
Market, was $209,624,722. 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 March 11, 2003, Registrant had outstanding 12,829,310 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, and 13 of Part III of the Form 10-K Report: Definitive Proxy Statement for
the Registrants 2003 Annual Meeting of Stockholders.



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TABLE OF CONTENTS



|                                                   |                                                                                               |                                             |  |  |  |  |  | 
|-------------------------------------------------- | --------------------------------------------------------------------------------------------- | ------------------------------------------- |  |  |  |  |  | 
|PART I                                            
|ITEMS 1 and 2. BUSINESS and PROPERTIES            
|                                                   |                                                                                               | General  The Company                      
|                                                   |                                                                                               | Strategy                                   
|                                                   |                                                                                               | Oil and Gas Production Operations          
|                                                   |                                                                                               | Oilfield Services                          
|                                                   |                                                                                               | Gas Gathering Services                     
|                                                   |                                                                                               | Other Properties, Equipment and Real Estate
|                                                   |                                                                                               | Competition.                               
|                                                   |                                                                                               | Regulation                                 
|                                                   |                                                                                               | Operating Hazards and Insurance            
|                                                   |                                                                                               | Employees and Offices                      
|                                                   |                                                                                               | Available Information                      
|                                                   | ITEM 3. LEGAL PROCEEDINGS                                                                    
|                                                   | ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS                                  
|PART II                                           
|                                                   | ITEM 5. MARKET FOR THE REGISTRANTS COMMON STOCK AND RELATED STOCKHOLDER MATTERS             
|                                                   | ITEM 6. SELECTED FINANCIAL DATA                                                              
|                                                   | ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|                                                   |                                                                                               | Critical Accounting Policies and Estimates 
|                                                   |                                                                                               | Liquidity and Capital Resources            
|                                                   |                                                                                               | Results of Operations                      
|                                                   |                                                                                               | New Accounting Pronouncements              
|                                                   | ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                          
|                                                   | ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA                                          
|                                                   | ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
|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                      
|                                                   | ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS                                      
|                                                   | ITEM 14. CONTROLS AND PROCEDURES                                                             
|                                                   | ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K                    
|SIGNATURES                                        
|CERTIFICATIONS                                    
|INDEX TO EXHIBITS                                 
|EX-21 Subsidiaries of the Registrant              
|EX-23.1 Consent of Independent Auditors           
|EX-23.2 Consent of Independent Reservoir Engineers



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TABLE OF CONTENTS

|          |     |                         |  |                                                                                       |                                             |  |    |    | 
|--------- | --- | ----------------------- |  | ------------------------------------------------------------------------------------- | ------------------------------------------- |  | -- | -- | 
|Item      |     |                         |  |                                                                                       | Page                                       
|          |     |                         |  |                                                                                       |                                            
|          |     |                         |  |                                                                                       | PART I                                      |  |    |    | 
|1. and 2. |     | BUSINESS and PROPERTIES |  |                                                                                       | 3                                           | 
|          |     |                         |  |                                                                                       | General  The Company                       |  |    | 3  | 
|          |     |                         |  |                                                                                       | Strategy                                    |  |    | 4  | 
|          |     |                         |  |                                                                                       | Oil and Gas Production Operations           |  |    | 5  | 
|          |     |                         |  |                                                                                       | Oilfield Services                           |  |    | 18 | 
|          |     |                         |  |                                                                                       | Gas Gathering Services                      |  |    | 19 | 
|          |     |                         |  |                                                                                       | Other Properties, Equipment and Real Estate |  |    | 19 | 
|          |     |                         |  |                                                                                       | Competition                                 |  |    | 20 | 
|          |     |                         |  |                                                                                       | Regulation                                  |  |    | 20 | 
|          |     |                         |  |                                                                                       | Operating Hazards and Insurance             |  |    | 22 | 
|          |     |                         |  |                                                                                       | Employees and Offices                       |  |    | 23 | 
|          |     |                         |  |                                                                                       | Available Information                       |  |    | 23 | 
|          | 3.  |                         |  | LEGAL PROCEEDINGS                                                                     |                                             |  | 23 |   
|          | 4.  |                         |  | SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS                                   |                                             |  | 23 |   
|          |     |                         |  | PART II                                                                               |                                             |  |    |   
|          | 5.  |                         |  | MARKET FOR THE REGISTRANTS COMMON STOCK AND RELATED
STOCKHOLDER MATTERS              |                                             |  | 27 |   
|          | 6.  |                         |  | SELECTED FINANCIAL DATA                                                               |                                             |  | 29 |   
|          | 7.  |                         |  | MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS |                                             |  | 30 |   
|          |     |                         |  |                                                                                       | Critical Accounting Policies and Estimates  |  |    | 30 | 
|          |     |                         |  |                                                                                       | Liquidity and Capital Resources             |  |    | 32 | 
|          |     |                         |  |                                                                                       | Results of Operations                       |  |    | 34 | 
|          |     |                         |  |                                                                                       | New Accounting Pronouncements               |  |    | 40 | 
|          | 7A. |                         |  | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                            |                                             |  | 40 |   
|          | 8.  |                         |  | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA                                           |                                             |  | 42 |   
|          | 9.  |                         |  | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE  |                                             |  | 42 |   
|          |     |                         |  | PART III                                                                              |                                             |  |    |   
|          | 10. |                         |  | DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT                                    |                                             |  | 42 |   
|          | 11. |                         |  | EXECUTIVE COMPENSATION                                                                |                                             |  | 42 |   
|          | 12. |                         |  | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT                        |                                             |  | 42 |   
|          | 13. |                         |  | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS                                        |                                             |  | 42 |   
|          | 14. |                         |  | CONTROLS AND PROCEDURES                                                               |                                             |  | 42 |   
|          |     |                         |  | PART IV                                                                               |                                             |  |    |   
|          | 15. |                         |  | EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K                      |                                             |  | 43 |   

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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 statements include, without limitation,
statements relating to the drilling and completion of wells, well operations,
utilization rates of oilfield service equipment, gathering and compression of
wells, reserve estimates (including estimates for future net revenues
associated with such reserves and the present value of such future net
revenues), production, future prices, cash flow, investments, 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 23
of this report.




General  The Company

Prima was incorporated in April 1980 for the purpose of engaging in the
exploration for, and the acquisition, development and production of, crude oil
and natural gas, and for other related business activities. In October 1980,
Prima became publicly owned with a $3.6 million common stock offering. In
subsequent years, our activities have been expanded to include oil and gas
property operations, oilfield services, and, at times, natural gas gathering,
marketing and trading. However, a substantial majority of Primas consolidated
assets and revenue continue to be related to its oil and gas production
operations.

Our principal activities are organized into two 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. Although 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, 2002.

We have conducted our activities principally in the Rocky Mountain region of
the United States. At the end of 2002, Prima controlled leasehold interests in,
or owned, over 575,000 gross, 404,000 net, acres, predominately in the Denver
Basin of Colorado, the Powder River, Wind River, Big Horn and Green River
Basins of Wyoming and within the Wasatch Plateau and Overthrust Belt of Utah.
For additional information about these areas and Primas oil and gas
properties, see Oil And Gas Production Operations below.

We have identified more than 1,400 potential exploitation and development
opportunities on our acreage as of the end of 2002, including drilling,
recompletion and refracturing projects. Of these, 344 were assigned proved oil
and gas reserves at year-end 2002. Most of the identified non-proved
opportunities represent potential drilling locations on our acreage in the
Powder River Basin coalbed methane (CBM) play. This set of identified
opportunities includes only those projects that we believe have the potential
to be economically viable using unescalated year-end 2002 oil and gas prices.

Our oil and gas exploration, development and production operations are
conducted predominantly 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; Arete Gathering Company, LLC for
natural gas gathering and compression; and Prima Natural Gas Marketing, Inc.
for natural gas marketing and trading. For additional information related to
our business segments, including revenues, operating earnings, and total
assets, see Segment Information in Note 6 within Notes to Consolidated
Financial Statements.

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At December 31, 2002, we reported the following:



| |  | $141,927,000 of assets.                                                                                                                                                                                                                                  
|- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| 
| |  | $35,954,000 of net working capital.                                                                                                                                                                                                                      
| 
| |  | Estimated net proved reserves of 111,104,000 Mcfe, with a pre-tax present value using a 10% discount
factor (PV10) of $128,843,000, based on constant year-end average price realizations of $2.64 per
Mcf of natural gas and $31.30 per barrel of oil.
| 
| |  | Approximately 543,000 gross, 378,000 net, undeveloped acres and 32,000 gross, 26,000 net, developed
acres.                                                                                                                                               
| 
| |  | Operations of 616 productive wells, representing approximately 91% of the productive wells in which
Prima owns a working interest.                                                                                                                       

For the year ended December 31, 2002, we reported the following:



| |  | Net income of $5,230,000.                                                                              
|- |  | -------------------------------------------------------------------------------------------------------
| 
| |  | Net cash provided by operating activities of $21,524,000.                                              
| 
| |  | Average daily net production of 22,858 Mcf of natural gas and 1,022 barrels of crude oil (28,989 Mcfe).
| 
| |  | Average price realizations of $1.97 per Mcf of natural gas and $25.14 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 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 producers of oil and gas, and to realize among the
highest cash flow margins for reinvestment, in the industry. Through our
related activities in oilfield services, gas gathering and processing, and oil
and gas marketing and trading, we seek to complement and reinforce the
achievement of goals in our exploration and production operations, and to
enhance overall total returns to shareholders.

Acreage.We seek to acquire oil and gas mineral rights under leasehold acreage
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 costs, the timing and quality of work performed, safety and other
factors that can affect the profitability of a property.

Exploitation.We intend to continue property exploitation activities in our
principal operating areas. In the Denver 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 in the Powder River Basin, for both coal seam and
conventional reservoirs, and in the Wind River Basin, depending upon the merit
of each activity and subject to regulatory considerations. We generally assess
these activities as low-to-moderate risk endeavors that would be undertaken
when projected to meet our economic criteria, and as permitted by 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

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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. Such transactions
are pursued and consummated, where possible, 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 natural 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 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 Production Operations

Denver Basin

Location, Operations and Acreage.Our activities in the Denver Basin are
conducted primarily in the Wattenberg Area, which encompasses more than 1,000
square miles, between 20 and 55 miles northeast of Denver, Colorado. We also
own leasehold interests and conduct operations on 4,480 acres near Denver
International Airport (DIA), where we have drilled and completed ten wells.
We have conducted operations in the Denver Basin for more than 20 years, and at
the end of 2002, operated 411 wells in the area, including those near DIA. Our
leasehold position in the Denver Basin at that date included 18,100 gross
(15,500 net) developed acres, and an additional 13,000 gross (12,000 net)
undeveloped acres.

Formations and Production.Our drilling and production activities to date in
the Denver Basin have been centered in a portion of the Wattenberg Field where
the primary productive reservoirs are found in the Codell and Niobrara
formations. The Codell and Niobrara formations blanket large areas of the field
at depths of approximately 7,000 to 7,300 feet and have moderate porosity and
low permeability. These formations 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 Denver 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, pentane) are
processed out of the well stream and sold separately by third-party
gatherer/purchasers but their value is reflected in our wellhead price for
natural gas. Generally, our average gas price realizations per Mcf in this area
have slightly exceeded

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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. Our crude oil in this area is sweet and
generally commands a premium to Northeast Colorado and West Texas Intermediate
postings. During 2002, Denver Basin properties accounted for approximately 73%
of our total Mcfe produced and 82% of our total oil and gas revenues excluding
hedging effects, with natural gas averaging 15,288 Mcf per day and crude oil
averaging 987 barrels per day net to our interests.

Reserves and Development Costs.The Denver Basin represented 66% of our proved
oil and gas reserves on an Mcfe basis at the end of 2002. Codell/Niobrara wells
that we recently drilled and completed in this area generally cost
approximately $285,000 and target approximately 200,000 to 250,000 Mcfe of
gross recoverable reserves per well. At year-end 2002, we controlled
approximately 230 potential drill sites in the Denver Basin, with 60 of these
attributed proved undeveloped reserves. Our strategy has been to selectively
drill wells utilizing advanced drilling and completion techniques, focusing on
cost controls, and varying activity levels based upon regional oil and gas
prices, to enhance economic returns. There is no assurance that the potential
locations that have been identified will be drilled or that such wells, if
drilled, will result in commercial production.

Codell/Niobrara Refracturing.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, which has been previously fractured at least once,
is stimulated by another fracture treatment. We generally target older wells
with declining deliverability for restimulation. Refracs completed by Prima in
2002 resulted in initial incremental production rates averaging 150 Mcfe of oil
and natural gas per day. The refracs cost an average of approximately $120,000
and targeted approximately 125,000 Mcfe of gross incremental recoverable
reserves.

2002 Activity.During 2002, we participated in the drilling of 14 gross (13.2
net) wells and the refracturing of 34 gross (30.5 net) wells in the Denver
Basin. All of these operations were successfully completed and all of the wells
have been placed on or returned to production. New wells, refracs and
recompletion operations in the Denver Basin are characterized by flush
production at relatively high rates for a few months, after which lower
production levels are established at relatively shallow decline rates. We
generally accelerate these operations when oil and gas prices are high and
defer them when prices are low, to enhance the impact on investment returns
from the flush production. In early 2002, we elected to maintain a
comparatively low level of drilling and refrac operations because of relatively
low oil and gas prices, and high line-pressure attributable to limited
processing capacity in the area. In response to subsequent improvements in oil
and gas prices, and the completion of an expansion of a third-party owned
gas-processing plant, we accelerated such operations in the fourth quarter of
2002.

Future Activity.We plan to continue our development and exploitation
activities in the Denver Basin. We are currently budgeting for capital
investments in the Denver Basin aggregating between $6 million and $8 million
in 2003. Planned activities include approximately 15 to 25 new Codell/Niobrara
wells (including two wells in progress at year end 2002) and 30 Codell/Niobrara
refracs. However, our plans are subject to revision based on economic
conditions, performance results, activities conducted in other areas, and other
factors.

Powder River Basin 
Coalbed Methane

Location, Operations, Acreage.The coalbed methane play in the Powder River
Basin is prospective over a vast geographic area encompassing approximately
three million acres in northeastern Wyoming. According to the Wyoming Oil &
Gas Commission, over 15,000 CBM wells have been drilled to date, and
approximately 10,700 wells were producing approximately 957 MMcf of natural gas
per day during December 2002. At times during the past four years, this has
been the most active drilling play in the United States. Although activity
levels moderated in 2002, in response to pending resolution of federal land use
issues (discussed below), depressed regional gas prices, and other factors,
significant estimated potential gas reserves remain unexploited in the area.

We began our Powder River Basin CBM activities in 1999, and our operations have
included leasehold acquisition, drilling and completion of 342 wells,
infrastructure development, production, oilfield services, and gas gathering
and compression. We assembled a significant leasehold position within the play,
much of which lies close to gathering and

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transportation infrastructure. Our acreage in the area has included parcels in
various portions of the play, from the southernmost part of the prospective
area to its known limits on the northern end. In March 2002, we sold much of
the CBM acreage that we had assembled in the northernmost portion of the play,
including our partially-developed Stones Throw project with 153 wells, for
approximately $13,514,000. This project area had been an early area of focus
for Prima in the CBM play because it was located near properties being
developed by other operators, close to existing gas transportation
infrastructure, and because the combination of fee leaseholds and the
availability of special drainage permits to drill on federal lands facilitated
activities. However, the coals at Stones Throw were relatively shallow and
thin, and we did not obtain the economic results that we had anticipated.

As a consequence of information and experience gained at Stones Throw and from
other activities that we have conducted, as well as through monitoring the
experience of other operators, we have concluded that the best remaining
opportunities in the Powder River Basin CBM play lie in development of deeper,
thicker coals (below 800 depth and greater than 35 thick). Although much of
our early drilling operations were targeted toward shallower coals that had
been more extensively developed by other operators on surrounding acreage, we
began focusing in 2002 on CBM projects with larger-reserve potential in coals
generally found at greater depths, but which are not yet established as proved.
Establishing proved CBM reserves and production from such coals will take time,
as they are untested in most of the basin and extensive de-watering will need
to occur before significant quantities of gas production are realized.

The pace of development of these coals by us and other operators will also be
influenced by water management requirements that will be more complex than for
earlier CBM development, and extensive state and federal regulatory conditions.
However, we believe that these unproved deeper, thicker coals, such as the Big
George and Wall coals, hold the potential for significant future growth in
Primas proved reserves and production, and initial results from several
early-stage pilot projects being conducted by other operators in the area are
encouraging. In addition, some attractive projects to develop relatively thick,
high-permeability coals at shallower depths are still available in this play,
as exemplified by our project in the Porcupine-Tuit area, which is discussed
below.

At December 31, 2002, we held 111,300 gross (99,800 net) acres in the Powder
River Basin CBM play, of which 9,900 gross (8,900 net) were developed and
101,400 gross (90,900 net) were undeveloped. This acreage is 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 has been under preparation. For convenience of managing
operations, we have organized our current Powder River Basin CBM acreage
holdings into 22 defined project areas.

Formation and Production.The primary target coals are located in the Fort
Union formation at depths ranging from 600 feet to 2,000 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, well location 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, and have
averaged approximately 100 Mcf per day to date. Most of the gas production to
date has been obtained from relatively shallow Wyodak coals where development
was initially focused. Future development activities in the play are expected
to focus largely on deeper coals with higher estimated potential reserves and
production rates.

To produce gas in this CBM play, wells must generally be hooked-up to a
low-pressure gathering system and compression, commonly referred to as screw
compression, which holds wellhead pressures to approximately five pounds per
square inch gauged (psig). The gas must then move through a gathering system
where, at its terminus, gas needs to be 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

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to relatively high compression and transportation costs, net price realizations
for this gas are below Rocky Mountain indices. The amount of this discount
varies with the nominal level of the indices, Btu content of the gas, location
of the property, and other factors, but averaged approximately $0.87 per Mcf in
2002.

We established our first significant Powder River Basin CBM production in 2001
from the Stones Throw property, where production rates increased over several
months to a level in excess of 8,000 Mcf per day gross at the time the property
was sold in March 2002. In late July 2002, we initiated production at our
Porcupine-Tuit CBM property, from 27 wells. Production from this property
increased over the balance of the year, as wells de-watered, more wells were
hooked up, and additional third-party-owned compression capacity was installed.
During December 2002, the Porcupine-Tuit property produced an average 13,500
Mcf per day gross (approximately 10,400 Mcf per day net) from 48 wells. Overall
in 2002, Powder River Basin CBM properties accounted for approximately 15% of
our total Mcfe produced and 7% of our total oil and gas revenues excluding
hedging effects, with net gas production averaging 4,318 Mcf per day for the
full year and 8,582 Mcf per day in the final quarter of the year.

Reserves and Development Costs.Powder River Basin CBM properties accounted
for 28% of our year-end proved oil and gas reserves on an Mcfe basis at the end
of 2002. CBM wells generally cost from $50,000 to $100,000 to drill, equip and
complete, depending on location and depth, and a similar amount for supporting
infrastructure, including surface equipment, water management facilities, and
connections to sales meters. A typical well is expected to establish gross
recoverable reserves of 250,000 to 500,000 Mcf. At year-end 2002, Primas
reserve report for the CBM area included 91 proved developed producing wells,
23 wells classified as proved developed non-producing and 115 locations
assigned proved undeveloped reserves. Based on engineering estimates prepared
as of December 31, 2002, we estimate that we have a potential inventory of over
950 additional non-proved drill sites in this play, subject to economic
viability that will be dependent upon projected regional gas prices, estimated
development and operating costs, drilling results from activities by Prima and
other operators and other factors. We caution, however, that the play is not
uniform, and estimated potential reserves and production capabilities vary
considerably depending on location, thickness and depths of coals, number of
coals present, permeability, gas content, and a number of other factors. There
is no assurance that these potential wells will be drilled or that any that are
drilled will ultimately establish economic reserves.

Permits  Drilling, Water Discharge and Air Quality.Operations in this area,
which includes significant amounts of land controlled by federal or state
governments, are extensively regulated. Drilling permits are issued by the
Wyoming Oil & Gas Commission. In order to conduct operations on federal
leaseholds, drilling permits must also be approved by the Bureau of Land
Management (BLM), subject to environmental regulations. The Wyodak
environmental impact statement (EIS) was completed in 1999 to facilitate
early development in the Powder River Basin CBM play, and provided for the
drilling of approximately 5,900 wells. These permits have all been issued, and
there has essentially been a moratorium on issuing drilling permits for federal
leaseholds pending issuance of another EIS, unless the location qualified under
an environmental assessment that provided for issuance of approximately 2,500
special drainage permits.

The pending EIS, which is expected to consider the environmental impact of
drilling approximately 50,000 CBM wells in the area, inclusive of wells drilled
to date, is currently in process and a record of decision is expected in the
second quarter of 2003. We anticipate much greater accessibility to our federal
acreage after this EIS is issued. However, if a final record of decision for
the EIS is delayed or we encounter significant delays in the issuance of
additional drilling permits on our federal acreage for any other reason, our
development plans for the area would be significantly impacted.

Water produced from CBM wells is generally potable (drinking water quality) and
can be discharged on the surface. The Wyoming Department of Environmental
Quality (DEQ) is responsible for considering applications for water discharge
permits. During the past year, issuance of water discharge permits was slowed
in order to address the sodium absorption ratio and mineral content of water
discharged in the basin and its potential impact on agriculture. This issue is
most acute for producers in the northwestern portion of the play and Primas
operations are focused primarily on the eastern side of the basin. A principal
alternative to surface drainage discharge for water management is containment,
or impoundment, which increases development and operating costs. Air discharge
permits, which are required to operate natural gas fired compressors, are also
issued by the DEQ, and take approximately six months to be issued. We have not
encountered significant difficulties to date in acquiring air permits for our
CBM operations.

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Natural Gas Transportation Infrastructure.The transportation infrastructure
in this basin is currently capable of moving approximately 1.4 Bcf per day of
natural gas. High-pressure header systems, including Bighorn Gas Gathering
LLC, Fort Union Gas Gathering LLC, and Thunder Creek Gas Services LLC, feed
downstream into interstate pipeline capacity provided by Colorado Interstate
Gas Company, Wyoming Interstate Pipeline, KM Interstate, Williston Basin
Interstate Pipeline, and MIGC Inc. Downstream of these interstate pipelines,
the pipeline grid is being enhanced by three projects. Kern River Pipeline is
expected to be on line in May 2003 with an additional 900,000 Mcf per day of
capacity that will move gas from southwest Wyoming to Nevada and California
markets. Williston Basin Interstate Pipelines Grasslands project is scheduled
to move an additional 80,000 Mcf per day north out of the basin to
mid-continent markets beginning in November of 2003. In the summer of 2005, El
Paso Corporations Cheyenne Plains project is anticipated to establish new
capacity to move 540,000 Mcf per day from Cheyenne, Wyoming to mid-continent
markets. Northern Border Partners L.P. and Kinder Morgan pipelines have also
announced potential projects to move gas from the basin, but firm commitments
and dates are pending. We estimate that at year-end 2002, about 950,000 Mcf per
day of CBM gas was flowing. We caution that Prima does not own firm
transportation for its own account, and could have difficulty moving gas from
the basin if pipelines fill to capacity. Under the terms of an agreement with a
third party that controls firm header and pipeline capacity from the basin,
Prima does retain the right, at certain junctures, to enter into a firm
gathering arrangement for up to 5,000 Mcf per day of its Powder River Basin CBM
gas production.

2002 Activity.During 2002, we drilled 56 gross (47.8 net) CBM wells in this
play. From 1999, when we commenced our CBM operations, through the end of 2002,
we drilled a total of 342 gross (331.6 net) wells and acquired an interest in
five additional wells in the play. All but a few of these wells are located
within five of the 22 project areas that we have identified on our current
acreage holdings, or in the Stones Throw project area, which was sold in March
2002. The concentration of Primas development activities to-date within these
project areas, and on the specific coals targeted so far, reflects a number of
considerations other than estimated recoverable reserves and projected
production rates. Our CBM activities have been limited to fee lands, state
lands, and certain coals underlying federal lands for which drilling permits
have been obtainable. These activities have largely been focused on relatively
shallow coals, near development activities of other operators. The
higher-potential coals identified on Primas lands have not yet been
extensively developed, and have not been attributed any proved reserves as of
December 31, 2002. Other operators in the area are also in the early stages of
developing these deeper, thicker coal sequences, which are expected to
initially take longer to de-water than coals that have been under development
and production in the region for a period of time. The following is a brief
description of activities in the six project areas where most of Primas CBM
operations have been conducted to-date (including the Stones Throw property
that was sold), and our Wild Turkey project area, where we expect to commence
drilling operations later this year.

Porcupine-Tuit. The 11,000-acre Porcupine-Tuit project area is located
approximately 50 miles south of Gillette, Wyoming. We have drilled 62
Wyodak-coal wells, including 39 in 2002, in this project area, which exhibits
favorable coal quality and thickness at relatively shallow depths. During 2002,
we commenced production from 58 of these wells, including 27 wells in the third
quarter and 31 wells in the fourth quarter of the year. Well production rates
have generally met or exceeded our expectations to date. At the end of the
year these wells were averaging a combined 14,000 Mcf per day, gross
(approximately 10,800 Mcf net), with several wells still de-watering. By
late-February 2003, gross production had ramped up further, to a level of
approximately 18,000 Mcf per day. We expect gross production to increase to
approximately 21,000 Mcf per day in the second quarter, when the third-party
contracted to gather this gas is planning to install additional compression.

We intend to hook-up the four shut-in wells during the second half of 2003,
along with wells drilled during the next phase of development, which will
commence as soon as practicable after approvals are received for 26 drilling
permits for which applications have been submitted. We have been delayed in
obtaining permits to drill these wells due to regulatory review and an appeal
of the Forest Services decision to approve our requested permits. We
anticipate a favorable resolution of this appeal and are currently planning to
drill these wells beginning in the third quarter of 2003. However, this
scheduled drilling is dependent upon receiving permit approvals from both the
Forest Service and the Bureau of Land Management, and further delays could be
encountered. Primas net working and revenue interests in the 88 Porcupine-Tuit
wells that have either been drilled or are expected to be drilled in 2003
average approximately 93% and 78%, respectively.

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Kingsbury. Our Kingsbury project area is located approximately 15 miles west
of Gillette, Wyoming. In November 2002, we contributed approximately 5,900 of
the 10,300 acres that we controlled in the Kingsbury area to a new joint
venture formed with a private company to develop coal bed methane resources
within an area comprising an aggregate 11,600 gross acres (9,800 net acres, to
the joint-venture interests). The joint-venture area encompasses our Kingsbury
deep-coal pilot project, which we designed to begin testing two coals found at
depths between 1,500 feet and 2,000 feet that have not yet been extensively
developed in the area. Our acreage contribution to, and ownership stake in, the
joint venture are approximately 60%, and Prima is the operator of the project.
Late in 2002, we completed and placed on pump the 16 wells that comprise the
initial-stage pilot in this area. These wells are not expected to produce gas
for several months, as the initial de-watering process occurs, and they have
not yet been tied into a gas gathering system. In addition to these 16 wells,
the JV holds interests in 22 wells, most of which were drilled to shallower
coals, which have either not yet been hooked up or are producing at marginal
rates. Through formation of this joint venture, Prima maintained its overall
exposure to deep-coal potential in this area, which is projected to be
significant, while reducing its net risk capital to evaluate these probable
reserves. We also expect to realize improved cost efficiencies in developing
and operating the property. We anticipate arranging for a third party to
install or expand a gathering system and compression facilities at Kingsbury by
late 2003. Within the Kingsbury area, but outside of the JV, we closed 2002
with 17 shallow-coal wells that were drilled in prior years, on 4,400 gross and
net acres. In January 2003, we sold 1,120 of these acres, with 8 wells that
were producing an aggregate of approximately 150 Mcf per day net, for
$1,200,000.

Cedar Draw and North Shell Draw. We have drilled 53 wells within these two
adjacent project areas, in which we control an aggregate 15,300 gross acres,
approximately 20 to 25 miles northwest of Gillette, Wyoming. Seventeen of the
wells have been drilled within the 3,800-acre Echeta federal unit, which
comprises a portion of the Cedar Draw and North Shell Draw project areas. Of
the total wells drilled within these projects, 42 targeted the Lower Anderson
coal at a depth of approximately 500 feet, seven were drilled for the Upper
Canyon coal at a depth of approximately 800 feet, and four were drilled to the
Wall coal at approximately a 1,200-foot depth. The Cedar Draw and North Shell
Draw project areas are located in reasonably close proximity to the Kingsbury
project, and we expect to coordinate development of these areas, including
installation of gas gathering and compression facilities. We also anticipate
that our near-term drilling activities in the Cedar Draw and North Shell Draw
area will focus primarily on the Wall coal.

Hensley. The 4,800-acre Hensley project area is located approximately 20 miles
northwest of Gillette, Wyoming. Prima has drilled and completed 18 wells in
the project area. These wells, which were drilled prior to 2002, targeted three
separate coals between 600 feet and 1,200 feet deep. We have deferred further
development in this area, including installation of surface facilities, and
arranging for gas gathering, in order to focus our resources on project areas
that are believed to have higher potential. We do not plan additional near-term
activities at Hensley, but will likely pool our acreage with another operator,
sell the property, or resume activities at a later date.

Stones Throw (sold March 2002). The 9,900-acre Stones Throw project area,
located approximately 30 miles north of Gillette, Wyoming, was the first chosen
by Prima for extensive CBM development. Its selection was due to our control of
a significant portion of fee acreage within the project area and its proximity
to both an existing CBM field and related infrastructure. We drilled a total of
153 wells at Stones Throw to develop three coals at depths between 500 feet and
850 feet, and we also installed a gas gathering system with leased compression
facilities. Gross production from the field reached approximately 8 MMcf of gas
per day and averaged 5.4 MMcf per day net to Prima during the first two months
of 2002, from 106 wells that were hooked up and producing during the period.
This field, the associated gathering system, and certain surrounding acreage
with three shut-in wells were sold in March 2002 for $13,514,000, following our
decision to focus future CBM exploitation and development activities on other
lease holdings in the play where we believe the presence of thicker, and
generally deeper, coals will enable us to realize superior investment returns.

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Wild Turkey. The 6,300-acre Wild Turkey project area is located approximately
25 miles southwest of Gillette, Wyoming. This project will target the
development of the Big George coal, which is found at a depth from 1,200 feet
to 1,400 feet, and which we anticipate will vary in thickness from 100 feet to
potentially over 160 feet based upon nearby subsurface well control. The
closest established production from the Big George coal is coming from another
operators project located six miles to the southwest of Wild Turkey. That
property was currently producing approximately 20,000 Mcf of gas per day from
70 wells as of December 2002. The Big George coal in our Wild Turkey project is
expected to have similar thickness at a comparable depth, as this property six
miles to the southwest. Prima has not yet drilled any wells on the Wild Turkey
acreage block. Our current plans call for the drilling of 26 wells in 2003 to
initiate evaluation and development. Further drilling is planned for 2004 and
2005, subject to governmental and regulatory approvals.

Future Activity.We plan to actively develop our CBM acreage over a multi-year
period, focusing primarily on the Porcupine-Tuit area and areas, such as
Kingsbury and Wild Turkey, where we have identified deeper, thicker coal seams
that we believe hold potential for significant reserve additions. The pace of
our activities will reflect a number of considerations, including the levels of
gas prices and oilfield service costs, regulatory actions, infrastructure
development, activities by other operators, and performance results. Currently,
we anticipate drilling between 75 and 90 CBM wells in 2003, the majority of
which are scheduled for the second half of the year due, in part, to expected
time required to secure drilling permits. Among the project areas with planned
drilling activities in 2003 are Porcupine-Tuit, Kingsbury, Cedar Draw, and Wild
Turkey. Our capital investments in this CBM play during 2003 are currently
expected to total between $12 million and $15 million, but these plans could
change based on availability of required permits and other factors.

Powder River Basin 
Conventional

Location, Operations, Acreage.We have conducted operations related to
conventional reservoirs in the Powder River Basin since 1994. At the end of
2002, we controlled deep rights (below the coals) under approximately 162,000
gross (149,000 net) acres in the basin, and we operated 13 of the 17
conventional-reservoir Powder River Basin wells in which we owned an interest.
We have conducted a modest amount of exploration in the area, in addition to
acquiring proved properties, and discovered the Cedar Draw Field approximately
21 miles northwest of Gillette, Wyoming in 1997 as an extension to the Amos
Draw Field. At the end of 2002, Prima operated six wells and had a non-operated
working interest in two other wells in the Cedar Draw Field.

Formations and Production.Our production from conventional reservoirs in the
Powder River Basin has been derived primarily from the Muddy and Turner
formations, found at depths between approximately 9,500 feet and 10,000 feet.
Both of these formations are localized in nature, have moderate porosity and
permeability, and typically require fracture stimulation to establish economic
production. The production stream from these two formations includes natural
gas, extracted natural gas liquids, and sweet crude oil. Natural gas averages
approximately 1,280 Btu per Mcf and is sold at a slight premium to Rocky
Mountain indices, or spot prices per Mcf. The crude oil sells for a premium to
postings for Wyoming crude oil in this area. During 2002, production from
conventional Powder River Basin properties accounted for approximately 6% of
our Mcfe produced and 6% of our total oil and gas revenues excluding hedging
effects, with natural gas averaging 1,621 Mcf per day and crude oil averaging
31 barrels per day net to our interests.

Reserves and Development Costs.Powder River Basin conventional properties
accounted for approximately 3% of Primas proved oil and gas reserves at the
end of 2002, on an Mcfe basis. At the end of 2002, we carried only proved
developed reserves in our reserve report for conventional reservoirs in this
area, but additional drilling locations may be viable at higher gas prices. We
have also identified several conventional exploratory prospects on our Powder
River Basin acreage. The identified exploratory and exploitation locations are
primarily prospective in the Muddy formation, for which estimated costs to
drill and complete a well are approximately $800,000, with average gross
reserve targets of 1.2 Bcfe to 1.5 Bcfe per well.

2002 and Future Activity.We did not drill any conventional wells in the Powder
River Basin in 2002. We also do not have any specific plans to drill wells
targeting conventional reservoirs in the Powder River Basin in 2003, but we do

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intend to continue our evaluations of prospects and leads in the conventional
play, and these plans may change as a result.

Cave Gulch (Wind River
Basin)

Location, Operations and Acreage.Prima has been active in the Wind River
Basin, located in central Wyoming, since 1987. Our Wind River Basin acreage
position is comprised of 1,200 gross (150 net) developed acres and 41,000 gross
(25,000 net) undeveloped acres. Our oil and gas production in the basin is
primarily attributable to ownership of non-operated working interests in the
Cave Gulch Field, but we also operate one well and own small overriding royalty
interests in a number of wells. At the end of 2002, we owned working interests
averaging approximately 7%, in 34 producing wells at Cave Gulch Field.

Formations and Production.Several formations produce in the Cave Gulch Field,
including the Fort Union at approximately 4,500 feet, the Lance between 4,900
and 9,200 feet, and the Frontier and Muddy formations between 17,000 and 18,200
feet. The Fort Union and Lance formations are both thick fluvial deposits with
multiple, stacked lenticular sandstones that are laterally discontinuous. The
Frontier and Muddy formations are a series of shallow marine channel, delta and
offshore bars with locally enhanced porosity and permeability. Production from
Cave Gulch Field includes natural gas, natural gas liquids and sweet crude oil.
The natural gas averages 1,150 Btu per Mcf and is sold at a slight premium per
Mcf to Rocky Mountain indices, or spot prices. The crude oil sells for a
premium to postings for Wyoming crude oil in this area. During 2002, net
production from Primas Wind River properties accounted for approximately 6% of
our total Mcfe produced and 5% of our total oil and gas revenues excluding
hedging effects, with natural gas averaging 1,631 Mcf per day and crude oil
averaging 4 barrels per day net to our interests.

Reserves and Development Costs.The Wind River Basin represented approximately
3% of Primas proved oil and gas reserves at the end of 2002, on an Mcfe basis.
The year-end 2002 reserve report for this area includes six proved developed
non-producing re-completion opportunities, but no proved undeveloped locations.
There are, however, identified opportunities to drill for unproved reserves
within or near the Cave Gulch Field. Generally, these opportunities target the
Lance formation. Lance formation wells typically cost approximately $1.3
million to drill and complete, and target gross reserves of approximately 2
Bcfe.

2002 And Future Activity.Prima participated in the drilling of five gross
(0.5 net) wells at Cave Gulch Field during 2002, including two wells in
progress at year-end. All five wells were drilled to develop reserves in the
Lance formation. Four were apparent successes, and the other well may be
abandoned due to mechanical problems. Our activities at Cave Gulch Field are
determined to a large extent by the operator of the property, who proposes
drilling or re-completion operations pursuant to standard industry operating
agreements. We review each proposed operation and elect whether or not to
participate based on our assessment of the economic and geologic merit. We
anticipate additional activity in the field during 2003. Although the level of
such activity has not been established yet, we anticipate receiving proposals
to drill as many as 10 wells and to recomplete up to another 10 wells, with
Prima working interests in such operations ranging up to 18% and averaging
approximately 7%. We anticipate net investments in this area aggregating
between $1 million and $2 million in 2003.

Other  Exploratory
Prospects and Acreage

Prima holds the following undeveloped acreage positions where recent activities
have occurred, or where we anticipate that near-term activities conducted by
Prima or third parties may benefit us. There is no assurance that any of the
anticipated activities will occur or, if undertaken, that they will result in
favorable outcomes.

Utah.Primas assets in Utah primarily consist of exploratory acreage holdings
and a related well in progress. At the end of 2002, we held approximately
105,000 gross (102,000 net) undeveloped acres in Utah, on which we had
identified four prospects that have conventional oil and gas potential, as well
as coal bed methane potential.

Coyote Flats Prospect. We control approximately 75,000 gross (72,000 net)
undeveloped acres within our Coyote Flats Prospect area. The prospect is
located 15 to 25 miles northwest of Price, Utah, and is approximately 15 miles
northwest

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of the Drunkards Wash Field. Drunkards Wash Field is expected to ultimately
produce in excess of 1.2 Tcf of natural gas from the Cretaceous Ferron coals
and sandstones. Data from drilling operations conducted on the Coyote Flats
acreage during the 1950s indicated gas shows from the Blackhawk and Emery coal
seam intervals, and from the Ferron sand, the Mancos shales, and the Dakota
sand. Our primary exploratory objectives at Coyote Flats are coal bed sequences
in the Emery formation, and the Ferron sandstone. Emery coals are found across
the majority of the lease position at depths from 2,000 to 5,000 feet, with
estimated net coal thickness ranging from 20 to 130 feet. The Ferron sandstone
is found at depths ranging from 5,000 to 6,500 feet on the acreage.

During the fourth quarter of 2002, we completed drilling a 100%-owned
exploration well on the Coyote Flats Prospect. The well was designed 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. During drilling, the well encountered 122 feet
of Emery coal, in aggregate, from numerous coal seams. Eight of these coal
seams have a thickness exceeding five feet, and the thickest coal seam is 22
feet. The Ferron section was drilled between 5,991 and 6,247 feet. Encouraging
gas shows were encountered while drilling from several Emery coal seams and
from fractured shales and sandstones in the Ferron section. Prima currently
plans to seek a partner to undertake a nine-well Emery coal bed pilot project,
immediately south of the Scofield-Thorpe #22-41 well, and is also presently
working with various service companies to develop a completion plan for the
Ferron section.

East Clear Creek Prospect. We own approximately 9,000 gross and net acres in
the East Clear Creek Prospect, which is located approximately 15 miles west of
Price, Utah. This prospect is one mile east of Clear Creek Field, which has
produced 136 Bcf of natural gas from 16 wells drilled to the Cretaceous Ferron
sandstone. Two miles east of Primas prospect, at Gordon Creek Field, a third
party recently completed six Ferron sandstone wells, three of which have been
placed on line with initial production rates of 1.0 to 2.5 MMcf of gas per day.
Our planned initial exploration well at East Clear Creek will target the Ferron
sandstone at a depth of approximately 6,000 feet on a seismically defined
structure. We are continuing to work with the U.S. Forest Service and the
Bureau of Land Management on an EIS that is required before drilling permits
will be issued on this prospect. We plan to drill a test well at East Clear
Creek as soon as practicable after such permits are obtained, which we
anticipate will be in late 2003 or in 2004.

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 at depths between 6,500 and 7,500
feet on the prospect. A secondary objective at Flat Canyon is the Cretaceous
Blackhawk coals, which are 10 to 30 feet thick, at depths of 1,100 to 2,500
feet. Prima is currently working with the U.S. Forest Service and the Bureau of
Land Management to permit a well on this prospect. We anticipate drilling our
first well on this prospect during 2003 or 2004.

Christmas Meadows Prospect. Prima owns or controls via farmout an aggregate 50%
working interest in the Table Top Federal Unit, which consists of approximately
23,000 acres. The unit is located in Summit County, Utah, approximately 30
miles south of Evanston, Wyoming. The prospect objective is a seismically
defined structural feature. The project has been delayed for several years
while the U.S. Forest Service has been preparing an EIS and considering a
revision of the forest plan for the area. Prima and its partners intend to
cause a well to be drilled on the prospect shortly after the Forest Service
completes this work, but no drilling activity is expected to take place during
2003.

Wyoming.Prima controls 407,000 gross, 249,000 net, undeveloped acres in the
Powder River, Wind River, Green River, and Big Horn Basins in Wyoming. The more
significant properties among these leaseholds are described below.

Merna Prospect. On the Merna Prospect, located in the Green River Basin in
Sublette County, Wyoming, another operator drilled and set pipe at 13,900 feet
on the Miller Federal #7-4 well during the second half of 2002. This well
targeted the over-pressured Cretaceous Lance and Mesaverde formations, which
are under extensive development on the Pinedale Anticline, located
approximately 20 miles to the southeast. An affiliate of the operator installed
a 36-mile natural gas pipeline to facilitate extended production testing of
this well and future wells that might be drilled in the Merna area. The
production testing of the Miller Federal #7-4 well was commenced but not
completed during 2002.

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Planned completion operations on the well include fracture stimulations of ten
prospective intervals, of which eight have been conducted through March 11,
2003. Establishment of commercial production in the Miller well is expected to
be dependent upon results from the last two intervals to be tested. Project
success may require encountering naturally fractured reservoirs or employing
advanced completion techniques. The operator has indicated intentions of
completing operations on the well during the first half of 2003, and has
initiated activities to form an approximate 40,000-acre federal unit in the
Merna area. Federal approval of a unit would likely require that two obligation
wells be drilled over the ensuing twelve to eighteen months. In addition, a
large regional 3-D seismic survey that was recently completed in the area
encompassed a large portion of the Merna Prospect acreage. Prima owns a 3%
overriding royalty and a 12.5% after-payout reversionary interest in this
exploratory well, and retains working interests ranging from 12.5% to 50% in
approximately 72,000 gross undeveloped acres in the Merna Prospect area.

Teakettle Prospect. We own working interests in 4,440 gross (2,220 net) acres
in the Teakettle Prospect. This prospect is located in Sublette County,
Wyoming, in the northern portion of the Green River Basin, approximately ten
miles south of the large Jonah Field, which produces primarily from the
over-pressured Upper Cretaceous Lance formation. During 2002, an extensive 3-D
seismic survey was completed in the prospect area. We have not acquired this
data, but anticipate that the seismic survey will stimulate exploration
activities in the area during the coming year. At the present time, however, no
drilling on the Teakettle Prospect is planned for 2003.

Hells Half Acre Prospect. We own approximately 17,200 gross (5,500 net),
undeveloped acres in the Hells Half Acre Prospect, which is located in the
eastern Wind River Basin, Natrona County, Wyoming. This prospect is a
seismically defined structure located approximately ten miles southeast of Cave
Gulch field. Prospective targets include the Fort Union, Lance, and deeper
Frontier and Muddy formations. Several operators with leasehold interests in
the prospect area have held discussions regarding the possibility of jointly
drilling a deep test well. Although no such well has yet been proposed, we are
hopeful that this project can commence by the end of 2003.

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, 2002 and 2001 were estimated by Primas engineers
and audited by Netherland, Sewell and Associates, Inc., independent petroleum
engineers. Estimates as of December 31, 2000 were prepared or audited in part
by Netherland, Sewell and Associates, Inc. and in part by Ryder Scott Company,
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 reserve quantities
at the end of 2002, 2001, and 2000, respectively, were as follows: $2.64,
$1.94, and $7.51 per Mcf for natural gas; and $31.30, $19.71, and $26.48 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 11 within the Notes to
Consolidated Financial Statements.

|                                                                                   |  |      |             |      |  |      |             |  |  |   |             | 
|---------------------------------------------------------------------------------- |  | ---- | ----------- | ---- |  | ---- | ----------- |  |  | - | ----------- | 
|                                                                                   |  | 2002 |             | 2001 |  | 2000
|                                                                                   |  |      |             |      |  |     
|Estimated proved natural gas reserves (Mcf)                                        |  |      | 87,440,000  |      |  |      | 115,222,000 |  |  |   | 154,172,000 | 
|Estimated proved oil reserves (barrels)                                            |  |      | 3,944,000   |      |  |      | 3,394,000   |  |  |   | 3,729,000   | 
|Present value of estimated future net cash
flows, before future income tax
expense |  | $    | 128,843,000 |      |  | $    | 91,905,000  |  |  | $ | 576,052,000 | 
|Standardized measure of discounted
future net cash flows                           |  | $    | 91,279,000  |      |  | $    | 66,801,000  |  |  | $ | 371,121,000 | 

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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, 2002 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, 2002, 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.

Production

Our net natural gas production averaged 22,858 Mcf per day for the year ended
December 31, 2002, compared to 25,416 Mcf per day for the year ended December
31, 2001 and 23,724 Mcf per day during the year ended December 31, 2000. Our
net oil production averaged 1,022 barrels per day for the year ended December
31, 2002, compared to 1,181 barrels per day during the year ended December 31,
2001 and 1,202 barrels per day during the year ended December 31, 2000. The
following table summarizes information with respect to our producing oil and
gas properties for each of these periods.

|                                                                             |                       |   |      |           |      |   |      |           |  |   |      |           | 
|---------------------------------------------------------------------------- | --------------------- | - | ---- | --------- | ---- | - | ---- | --------- |  | - | ---- | --------- | 
|                                                                             |                       |   | 2002 |           | 2001 |   | 2000
|                                                                             |                       |   |      |           |      |   |     
|Quantities sold:                                                             |                       |   |      |           |      |   |      |           |  |   |      |          
|                                                                             | Natural gas (Mcf)     |   |      | 8,343,000 |      |   |      | 9,277,000 |  |   |      | 8,683,000 | 
|                                                                             | Oil (barrels)         |   |      | 373,000   |      |   |      | 431,000   |  |   |      | 440,000   | 
|Average sales price (including hedging effects):                             |                       |   |      |           |      |   |      |           |  |   |      |          
|                                                                             | Natural gas (per Mcf) |   | $    | 1.97      |      |   | $    | 3.60      |  |   | $    | 3.63      | 
|                                                                             | Oil (per barrel)      |   | $    | 25.14     |      |   | $    | 25.88     |  |   | $    | 29.29     | 
|Average production costs, including production
taxes, per equivalent Mcf (1) |                       | $ | 0.49 |           |      | $ | 0.56 |           |  | $ | 0.53 |          



---

|(1) |  | Oil production has been converted to a common unit of production (Mcf 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, 2002.

|              |          |          |  |                  |   |        |  |             |     |           |  |     |     |  |  |       |       | 
|------------- | -------- | -------- |  | ---------------- | - | ------ |  | ----------- | --- | --------- |  | --- | --- |  |  | ----- | ----- | 
|              |          |          |  | Productive Wells
|              |          |          |  |                 
|              |          |          |  | Oil              |   | Gas   
|              |          |          |  |                  |   |       
|              |          |          |  | Gross(1)         |   | Net(2) |  | Gross(1)(3) |     | Net(2)(3)
|              |          |          |  |                  |   |        |  |             |     |          
|Operated:     |          |          |  |                  |   |        |  |             |     |           |  |     |     |  |  |      
|              |          | Colorado |  |                  | 9 |        |  |             | 8.5 |           |  |     | 399 |  |  |       | 367.9 | 
|              |          | Wyoming  |  |                  | 0 |        |  |             | 0.0 |           |  |     | 208 |  |  |       | 186.8 | 
|Non-operated: |          |          |  |                  |   |        |  |             |     |           |  |     |     |  |  |      
|              |          | Colorado |  |                  | 0 |        |  |             | 0.0 |           |  |     | 19  |  |  |       | 8.1   | 
|              |          | Utah     |  |                  | 0 |        |  |             | 0.0 |           |  |     | 1   |  |  |       | 0.4   | 
|              |          | Wyoming  |  |                  | 0 |        |  |             | 0.0 |           |  |     | 39  |  |  |       | 3.6   | 
|              |          |          |  |                  |   |        |  |             |     |           |  |     |     |  |  |       |       | 
|              | Total(4) |          |  | 9                |   |        |  | 8.5         |     |           |  | 666 |     |  |  | 566.8 |      
|              |          |          |  |                  |   |        |  |             |     |           |  |     |     |  |  |       |       | 

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| |  | Additionally, we own royalty interests in 52 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 107 gross (95.6 net) CBM wells in Wyoming that were shut-in
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.                                                                                                  

Developed and
Undeveloped Acreage

At December 31, 2002, we held leased acreage as set forth below:

|                   |       |          |                      |        |                        |          |        |        |  |  |         |         |  |  |         |         | 
|------------------ | ----- | -------- | -------------------- | ------ | ---------------------- | -------- | ------ | ------ |  |  | ------- | ------- |  |  | ------- | ------- | 
|                   |       |          | Developed Acreage(1) |        | Undeveloped Acreage(2)
|                   |       |          |                      |        |                       
|Location           |       | Gross(3) |                      | Net(4) |                        | Gross(3) |        | Net(4)
|                   |       |          |                      |        |                        |          |        |       
|Big Horn Basin     |       |          | 0                    |        |                        |          | 0      |        |  |  | 101,000 |         |  |  | 26,000  |        
|Denver Basin       |       |          | 18,100               |        |                        |          | 15,500 |        |  |  | 13,000  |         |  |  | 12,000  |        
|Green River Basin  |       |          | 0                    |        |                        |          | 0      |        |  |  | 88,000  |         |  |  | 39,000  |        
|Powder River Basin |       |          | 11,500               |        |                        |          | 10,100 |        |  |  | 177,000 |         |  |  | 159,000 |        
|Uinta Basin        |       |          | 0                    |        |                        |          | 0      |        |  |  | 105,000 |         |  |  | 102,000 |        
|Wind River Basin   |       |          | 1,200                |        |                        |          | 150    |        |  |  | 41,000  |         |  |  | 25,000  |        
|Other basins       |       |          | 1,500                |        |                        |          | 50     |        |  |  | 18,000  |         |  |  | 15,000  |        
|                   |       |          |                      |        |                        |          |        |        |  |  |         |         |  |  |         |        
|                   | Total |          |                      | 32,300 |                        |          |        | 25,800 |  |  |         | 543,000 |  |  |         | 378,000 | 
|                   |       |          |                      |        |                        |          |        |        |  |  |         |         |  |  |         |        



---

|(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. 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 Expiring
|                      |                             |  |               
|                      |                             |  | Gross          |         | Net
|                      |                             |  |                |         |    
|Twelve Months Ending: |                             |  |                |         |     |  |         |        
|                      | December 31, 2003           |  |                | 15,000  |     |  |         | 9,000   | 
|                      | December 31, 2004           |  |                | 57,000  |     |  |         | 27,000  | 
|                      | December 31, 2005           |  |                | 90,000  |     |  |         | 57,000  | 
|                      | December 31, 2006           |  |                | 35,000  |     |  |         | 34,000  | 
|                      | December 31, 2007           |  |                | 40,000  |     |  |         | 26,000  | 
|                      | December 31, 2008 and later |  |                | 243,000 |     |  |         | 181,000 | 
|                      |                             |  |                |         |     |  |         |         | 
|                      |                             |  | 480,000        |         |     |  | 334,000 |        
|                      |                             |  |                |         |     |  |         |         | 

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Drilling
Activities

Certain information with regard to our drilling activities for the years ended
December 31, 2002, 2001 and 2000 is set forth below:

|             |            |  |       |    |      |  |       |      |     |  |       |     |     |  |       |       |  |  |     |     |  |  |       |       | 
|------------ | ---------- |  | ----- | -- | ---- |  | ----- | ---- | --- |  | ----- | --- | --- |  | ----- | ----- |  |  | --- | --- |  |  | ----- | ----- | 
|             |            |  | 2002  |    | 2001 |  | 2000 
|             |            |  |       |    |      |  |      
|             |            |  | Gross |    | Net  |  | Gross |      | Net |  | Gross |     | Net
|             |            |  |       |    |      |  |       |      |     |  |       |     |    
|Development: |            |  |       |    |      |  |       |      |     |  |       |     |     |  |       |       |  |  |     |     |  |  |       |      
|             | Productive |  |       | 55 |      |  |       | 50.1 |     |  |       | 123 |     |  |       | 121.3 |  |  |     | 178 |  |  |       | 176.7 | 
|             | Dry        |  |       | 0  |      |  |       | 0.0  |     |  |       | 0   |     |  |       | 0.0   |  |  |     | 3   |  |  |       | 2.0   | 
|             |            |  |       |    |      |  |       |      |     |  |       |     |     |  |       |       |  |  |     |     |  |  |       |      
|             |            |  | 55    |    |      |  | 50.1  |      |     |  | 123   |     |     |  | 121.3 |       |  |  | 181 |     |  |  | 178.7 |      
|             |            |  |       |    |      |  |       |      |     |  |       |     |     |  |       |       |  |  |     |     |  |  |       |      
|Exploratory: |            |  |       |    |      |  |       |      |     |  |       |     |     |  |       |       |  |  |     |     |  |  |       |      
|             | Productive |  |       | 18 |      |  |       | 11.0 |     |  |       | 14  |     |  |       | 14.0  |  |  |     | 5   |  |  |       | 4.9   | 
|             | Dry        |  |       | 0  |      |  |       | 0.0  |     |  |       | 2   |     |  |       | 0.3   |  |  |     | 0   |  |  |       | 0.0   | 
|             |            |  |       |    |      |  |       |      |     |  |       |     |     |  |       |       |  |  |     |     |  |  |       |      
|             |            |  | 18    |    |      |  | 11.0  |      |     |  | 16    |     |     |  | 14.3  |       |  |  | 5   |     |  |  | 4.9   |      
|             |            |  |       |    |      |  |       |      |     |  |       |     |     |  |       |       |  |  |     |     |  |  |       |      
|Total:       |            |  |       |    |      |  |       |      |     |  |       |     |     |  |       |       |  |  |     |     |  |  |       |      
|             | Productive |  | 73    |    |      |  | 61.1  |      |     |  | 137   |     |     |  | 135.3 |       |  |  | 183 |     |  |  | 181.6 |      
|             | Dry        |  | 0     |    |      |  | 0.0   |      |     |  | 2     |     |     |  | 0.3   |       |  |  | 3   |     |  |  | 2.0   |      
|             |            |  |       |    |      |  |       |      |     |  |       |     |     |  |       |       |  |  |     |     |  |  |       |      
|             |            |  | 73    |    |      |  | 61.1  |      |     |  | 139   |     |     |  | 135.6 |       |  |  | 186 |     |  |  | 183.6 |      
|             |            |  |       |    |      |  |       |      |     |  |       |     |     |  |       |       |  |  |     |     |  |  |       |      

Present
Activities

Subsequent to December 31, 2002, through March 11, 2003, we have participated
in the completion of two gross (1.9 net) wells and the restimulation of 6 gross
(5.7 net) wells in the Denver Basin, all of which have been placed on or
restored to production. During this same period, we continued our participation
in two non-operated (0.26 net) wells in the Cave Gulch area. One well is
waiting on completion, and the other well may be abandoned due to mechanical
problems.

Natural Gas and Oil
Marketing and Trading

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. At times, we use
financial instruments to hedge the price of a portion of Primas production or
production of others that we have committed to purchase for resale.

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
spot or day-to-day prices as posted. 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 2002. We have a
significant purchaser of our natural gas in the Denver Basin, Duke Energy Field
Services, LLC, that accounted for 33% of our total consolidated revenues in
2002. Duke is not affiliated with Prima and, while loss of Duke as a customer
might have a material adverse effect on our business, we believe we could
arrange to sell our gas to alternate customers on reasonably comparable terms.

We currently have four gathering agreements in effect to get our gas from the
wellhead into high-pressure header systems or interstate pipelines. These
include one in the Denver Basin, one in the Wind River Basin, and two in the
Powder River CBM play. 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 also 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 in 2002, but limited pipeline capacity
did create conditions during several months in which the netback price that we
received for our natural gas was significantly below prices being paid for gas
elsewhere in the country.

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

17



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##### Table of Contents



a net margin. However, from time to time we may have open purchase or sale
commitments without corresponding 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 2002 and had entered into no commitments after year-end 2002 through
March 11, 2003. In 2002, total revenues from the sale of Primas natural gas
production, including related hedging effects, were $16,413,000, or 64% of oil
and gas sales and 52% of consolidated total revenues.

Oil.Our oil production is sold under a number of contracts at negotiated
prices determined by quality, location, and prevailing market indices. The
contracts are generally month-to-month in duration. Our point of sale for
crude oil is typically at the tank battery near the well, where oil is picked
up and trucked by the purchaser to pipelines or refineries. During 2002, one of
the purchasers of our oil, Valero Energy Corporation, accounted for
approximately 29% of our total consolidated revenues for the year. We are not
affiliated with Valero, and we believe that we could sell our crude oil to
other purchasers on comparable terms should we lose Valero as a customer. In
2002, revenues from the sale of Primas crude oil, including related hedging
effects, totaled $9,372,000, or 36% of oil and gas sales and 29% of
consolidated total revenues.

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 NYMEX to CIG basis differential, which can occur when
natural gas supplies exceed pipeline capacity out of the Rocky Mountain region
or due to other factors, such as regional weather differences. During 2002, we
entered into derivatives contracts covering approximately 56% of our natural
gas production and 25% of our crude oil production. 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 and gas prices or widening
basis differentials. Approximately 6% of our natural gas production and 25% of
our crude oil production in 2002 were covered by derivatives contracts that
qualified for hedge accounting. See Item 7A, Quantitative and Qualitative
Disclosures about Market Risk, below for additional disclosures relating to
derivatives, including our open derivative positions as of March 18, 2003.

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 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 Denver Basin since 1986, operating out of a field office and yard near
LaSalle, Colorado. AOS owns various well servicing equipment including
completion rigs, a swab rig, tractor trailer rigs for water hauling, and
oilfield rental equipment, such as pumps, tanks and blowout preventers. During
2002, 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 Denver
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 2002, 17% 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 2002 totaled $6,470,000, or 20% of our consolidated revenues.

18



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##### Table of Contents



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. In
addition to providing well services, AES has six CBM drilling rigs. During
2002, activity levels in the Powder River Basin CBM play declined, due to weak
regional gas prices and limited availability of drilling permits on federal
lands due to the pending status of the EIS. As a result, we experienced a
decline in the utilization rates for our people and equipment. 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 2002, 28% 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
$1,856,000 in 2002, accounting for 6% of our consolidated revenues.




Gas Gathering Services

Arete Gathering Company, LLC.We formed Arete Gathering Company, LLC (Arete)
in the third quarter of 2000 to provide gas compression and gathering services
for the CBM play in the Powder River Basin. Arete installed its first gathering
system in Primas Stones Throw Area between mid-2000 and the first quarter of
2001. These assets were included in the Stones Throw sale transaction
consummated in March 2002. No other gathering systems have been installed by
Arete to date.

We will evaluate future opportunities to build gathering and compression
systems in the Powder River Basin based on the size and estimated reserve
potential of our acreage blocks, proximity to header systems and pipelines,
competitive options provided by third parties, and other factors affecting the
economics of each project. In areas where Prima does not have a significant
contiguous acreage block, or where third party gathering systems have already
been installed, we will generally elect not to have Arete build a gathering
system. Where Arete does install gathering and compression infrastructure, we
will seek to provide such services to third parties to benefit from
economies-of-scale and enhance our overall economic returns.




Other Properties, Equipment and Real Estate

We lease 15,840 square feet of office space in Denver, Colorado, at an
escalating annual cost that averages approximately $275,000 over the seven-year
term that commenced December 1, 2000. We own office furniture and equipment at
this location with a net book value of $199,000 at December 31, 2002.

We lease office space with yard and shop facilities in Gillette, Wyoming. The
shop, office building and yard facilities located on the land are used for our
Powder River Basin field and oilfield service operations. Net book value of our
oilfield service equipment, office furniture and equipment and leasehold
improvements at this location was $2,146,000 on December 31, 2002.

We own 160 acres of land with no mineral rights in Weld County, Colorado near
LaSalle, Colorado. The shop, office building and yard facilities located on
the land are used for our Denver Basin field and oilfield service operations.
Net book value of our oilfield service equipment, office furniture and
equipment and land and buildings at this location was $2,494,000 on December
31, 2002.

We own approximately ten acres of surface land with no mineral rights on the
western side of Greeley, Colorado. The land was acquired in March 2001 in
exchange for minor undeveloped mineral rights. This ten-acre parcel 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 2002, 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
and capital appreciation. The book value of this partnership interest was
$257,000 at December 31, 2002.

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Competition.

All of our businesses 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, and environmental and safety matters.

Regulation of Drilling and Production.Oil and gas operations are 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. Also, numerous departments and agencies, both federal and state, are
authorized by statute to issue rules and regulations binding on the oil and gas
industry and its individual members, some of which carry substantial penalties
for failure to comply. The regulatory burden on the oil and gas industry
increases the costs of doing business. 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. 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 such regulatory treatment
will continue indefinitely into 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.

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

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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.

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.

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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. The disposition of this water is regulated by
federal and state authorities. 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.




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,

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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, 2002, we had 130 full-time employees, including 37 in our
Denver office and 93 in district and field offices. Of the district and field
employees, 18 were employed in Primas lease and well management operations and
75 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.




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, 2002.

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:

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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.

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 24% of our total
proved reserves at December 31, 2002 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

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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 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 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 2003.
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.

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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.

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 our Powder
River Basin CBM properties are dependent upon the timing, content and
implementation of a pending record of decision by the Bureau of Land Management
concerning an environmental impact statement covering CBM development in the
area. 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.

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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 Companys years ended
December 31, 2002 and 2001.

|                                 |  |      |       |     |  |   |       | 
|-------------------------------- |  | ---- | ----- | --- |  | - | ----- | 
|Year Ended December 31, 2002     |  | HIGH |       | LOW
|                                 |  |      |       |    
|Quarter Ended March 31, 2002     |  | $    | 26.46 |     |  | $ | 19.10 | 
|Quarter Ended June 30, 2002      |  |      | 26.34 |     |  |   | 20.23 | 
|Quarter Ended September 30, 2002 |  |      | 23.00 |     |  |   | 15.70 | 
|Quarter Ended December 31, 2002  |  |      | 24.49 |     |  |   | 20.38 | 
|                                
|Year Ended December 31, 2001    
|                                 |  |      |       |    
|Quarter Ended March 31, 2001     |  | $    | 38.94 |     |  | $ | 25.25 | 
|Quarter Ended June 30, 2001      |  |      | 32.17 |     |  |   | 22.81 | 
|Quarter Ended September 30, 2001 |  |      | 27.69 |     |  |   | 19.99 | 
|Quarter Ended December 31, 2001  |  |      | 25.48 |     |  |   | 19.50 | 

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 March 11, 2003, the closing sale price for our common
stock was $18.75 per share.

(b) Holders of Record

Our common stockholders of record at March 11, 2003 totaled 831.

(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
2002, 2001 or 2000. Future cash dividends, if any, will be evaluated based
among other things, on our operating results, capital requirements and
financial condition at the time.

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(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, 2002:

|                                                           |  |                   |           |                   |  |                    |       |                     |  |                     |           | 
|---------------------------------------------------------- |  | ----------------- | --------- | ----------------- |  | ------------------ | ----- | ------------------- |  | ------------------- | --------- | 
|                                                           |  | (a)               |           | (b)               |  | (c)               
|                                                           |  |                   |           |                   |  | Number of         
|                                                           |  |                   |           |                   |  |                    |       |                     |  | securities         
|                                                           |  |                   |           |                   |  |                    |       |                     |  | remaining available
|                                                           |  | Number of         |           |                   |  |                    |       | for future issuance
|                                                           |  | securities to be  |           |                   |  |                    |       | under equity       
|                                                           |  | issued upon       |           | Weighted-average  |  | compensation plans
|                                                           |  | exercise of       |           | exercise price of |  | (excluding        
|                                                           |  | outstanding       |           | outstanding       |  | securities        
|                                                           |  | options, warrants |           | options, warrants |  | reflected in      
|Plan Category                                              |  | and rights        |           | and rights        |  | column (a))       
|                                                           |  |                   |           |                   |  |                   
|Equity compensation plans
approved by security holders     |  |                   | 1,083,825 |                   |  | $                  | 14.15 |                     |  |                     | 1,181,475 | 
|Equity compensation plans not
approved by security holders |  |                   |          |                   |  |                    |      |                     |  |                     |          | 
|                                                           |  |                   |           |                   |  |                    |       |                     |  |                     |           | 
|Total                                                      |  |                   | 1,083,825 |                   |  | $                  | 14.15 |                     |  |                     | 1,181,475 | 
|                                                           |  |                   |           |                   |  |                    |       |                     |  |                     |           | 

Issuance of Unregistered Securities

During 2002, Prima granted options to acquire a total of 194,000 common shares
that were not registered under the Securities Act of 1933, as amended. The
options were granted as follows:



| |  | Options to acquire a total of 22,500 common shares were granted to
directors of Prima under the terms of Primas Non-Employee Directors
Stock Option Plan.
|- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------
| 
| |  | Options to acquire a total of 171,500 common shares were granted to
certain key employees of Prima under the terms of Primas 2001 Stock
Incentive Plan.   

No underwriter was involved in any of the transactions and Prima paid no sales
commissions, fees, or similar compensation to any person in connection with the
issuance of the options. In each case, the options granted become exercisable
in 20% annual increments commencing on the first anniversary of the grant date.
Prima filed S-8 registration statements with the Securities and Exchange
Commission on November 7, 2002 for the Prima Energy Corporation Non-Employee
Directors Stock Option Plan and the Prima Energy Corporation 2001 Stock
Incentive Plan.

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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,
|                                                                                   |                                               |   |                         
|                                                                                   |                                               |   | 2002                     |        | 2001 |   | 2000    |        | 1999 |   | 1998   
|                                                                                   |                                               |   |                          |        |      |   |         |        |      |   |        
|Income Statement Data:                                                             |                                               |   |                          |        |      |   |         |        |      |   |         |        |  |   |        |        |  |   |        |       
|Revenues:                                                                          |                                               |   |                          |        |      |   |         |        |      |   |         |        |  |   |        |        |  |   |        |       
|                                                                                   | Oil and gas sales                             |   | $                        | 25,785 |      |   | $       | 44,548 |      |   | $       | 44,437 |  |   | $      | 20,644 |  |   | $      | 16,612 | 
|                                                                                   | Gains (losses) on derivative
instruments, net |   |                          | (2,918 | )    |   |         | 6,435  |      |   |         |       |  |   |        |       |  |   |        |       | 
|                                                                                   | Oilfield services                             |   |                          | 8,326  |      |   |         | 8,090  |      |   |         | 6,278  |  |   |        | 4,974  |  |   |        | 4,148  | 
|                                                                                   | Trading revenues                              |   |                          |       |      |   |         |       |      |   |         |       |  |   |        | 2,318  |  |   |        | 3,956  | 
|                                                                                   | Interest, dividend and other                  |   |                          | 597    |      |   |         | 1,214  |      |   |         | 1,464  |  |   |        | 1,286  |  |   |        | 4,378  | 
|                                                                                   |                                               |   |                          |        |      |   |         |        |      |   |         |        |  |   |        |        |  |   |        |       
|                                                                                   |                                               |   | 31,790                   |        |      |   | 60,287  |        |      |   | 52,179  |        |  |   | 29,222 |        |  |   | 29,094 |       
|                                                                                   |                                               |   |                          |        |      |   |         |        |      |   |         |        |  |   |        |        |  |   |        |       
|Expenses:                                                                          |                                               |   |                          |        |      |   |         |        |      |   |         |        |  |   |        |        |  |   |        |       
|                                                                                   | Depletion of oil and gas properties           |   |                          | 9,710  |      |   |         | 9,190  |      |   |         | 6,150  |  |   |        | 4,650  |  |   |        | 6,260  | 
|                                                                                   | Depreciation of other property                |   |                          | 1,291  |      |   |         | 1,369  |      |   |         | 1,054  |  |   |        | 817    |  |   |        | 616    | 
|                                                                                   | Lease operating expense                       |   |                          | 3,076  |      |   |         | 3,295  |      |   |         | 2,623  |  |   |        | 2,012  |  |   |        | 2,041  | 
|                                                                                   | Ad valorem and production taxes               |   |                          | 2,116  |      |   |         | 3,344  |      |   |         | 3,421  |  |   |        | 1,765  |  |   |        | 1,272  | 
|                                                                                   | Oilfield services                             |   |                          | 6,287  |      |   |         | 5,482  |      |   |         | 4,585  |  |   |        | 3,377  |  |   |        | 2,701  | 
|                                                                                   | General and administrative                    |   |                          | 3,255  |      |   |         | 3,559  |      |   |         | 2,916  |  |   |        | 1,712  |  |   |        | 1,143  | 
|                                                                                   | Impairment of natural gas swap                |   |                          |       |      |   |         | 241    |      |   |         |       |  |   |        |       |  |   |        |       | 
|                                                                                   | Trading costs                                 |   |                          |       |      |   |         |       |      |   |         |       |  |   |        | 2,827  |  |   |        | 3,936  | 
|                                                                                   |                                               |   |                          |        |      |   |         |        |      |   |         |        |  |   |        |        |  |   |        |       
|                                                                                   |                                               |   | 25,735                   |        |      |   | 26,480  |        |      |   | 20,749  |        |  |   | 17,160 |        |  |   | 17,969 |       
|                                                                                   |                                               |   |                          |        |      |   |         |        |      |   |         |        |  |   |        |        |  |   |        |       
|Income before income taxes and
cumulative effect of change in
accounting principle |                                               |   | 6,055                    |        |      |   | 33,807  |        |      |   | 31,430  |        |  |   | 12,062 |        |  |   | 11,125 |       
|Provision for income taxes                                                         |                                               |   | 825                      |        |      |   | 10,650  |        |      |   | 9,535   |        |  |   | 3,035  |        |  |   | 3,060  |       
|                                                                                   |                                               |   |                          |        |      |   |         |        |      |   |         |        |  |   |        |        |  |   |        |       
|Net income before cumulative effect of
change in accounting principle              |                                               |   | 5,230                    |        |      |   | 23,157  |        |      |   | 21,895  |        |  |   | 9,027  |        |  |   | 8,065  |       
|Cumulative effect of change in
accounting principle                                |                                               |   |                         |        |      |   | 611     |        |      |   |        |        |  |   |       |        |  |   |       |       
|                                                                                   |                                               |   |                          |        |      |   |         |        |      |   |         |        |  |   |        |        |  |   |        |       
|Net income                                                                         |                                               | $ | 5,230                    |        |      | $ | 23,768  |        |      | $ | 21,895  |        |  | $ | 9,027  |        |  | $ | 8,065  |       
|                                                                                   |                                               |   |                          |        |      |   |         |        |      |   |         |        |  |   |        |        |  |   |        |       
|Basic net income per share before
cumulative effect adjustment                     |                                               | $ | 0.41                     |        |      | $ | 1.82    |        |      | $ | 1.72    |        |  | $ | 0.70   |        |  | $ | 0.62   |       
|Cumulative effect adjustment                                                       |                                               |   |                         |        |      |   | 0.05    |        |      |   |        |        |  |   |       |        |  |   |       |       
|                                                                                   |                                               |   |                          |        |      |   |         |        |      |   |         |        |  |   |        |        |  |   |        |       
|Basic net income per share                                                         |                                               | $ | 0.41                     |        |      | $ | 1.87    |        |      | $ | 1.72    |        |  | $ | 0.70   |        |  | $ | 0.62   |       
|                                                                                   |                                               |   |                          |        |      |   |         |        |      |   |         |        |  |   |        |        |  |   |        |       
|Diluted net income per share before
cumulative effect adjustment                   |                                               | $ | 0.40                     |        |      | $ | 1.75    |        |      | $ | 1.65    |        |  | $ | 0.69   |        |  | $ | 0.61   |       
|Cumulative effect adjustment                                                       |                                               |   |                         |        |      |   | 0.05    |        |      |   |        |        |  |   |       |        |  |   |       |       
|                                                                                   |                                               |   |                          |        |      |   |         |        |      |   |         |        |  |   |        |        |  |   |        |       
|Diluted net income per share                                                       |                                               | $ | 0.40                     |        |      | $ | 1.80    |        |      | $ | 1.65    |        |  | $ | 0.69   |        |  | $ | 0.61   |       
|                                                                                   |                                               |   |                          |        |      |   |         |        |      |   |         |        |  |   |        |        |  |   |        |       
|Balance Sheet Data (at end of period):                                             |                                               |   |                          |        |      |   |         |        |      |   |         |        |  |   |        |        |  |   |        |       
|Total assets                                                                       |                                               | $ | 141,927                  |        |      | $ | 135,444 |        |      | $ | 104,900 |        |  | $ | 72,665 |        |  | $ | 66,866 |       
|Net property and equipment                                                         |                                               |   | 93,377                   |        |      |   | 96,005  |        |      |   | 70,597  |        |  |   | 44,467 |        |  |   | 55,607 |       
|Long-term debt                                                                     |                                               |   |                         |        |      |   |        |        |      |   |        |        |  |   |       |        |  |   | 120    |       
|Stockholders equity                                                               |                                               |   | 107,266                  |        |      |   | 101,740 |        |      |   | 80,298  |        |  |   | 58,908 |        |  |   | 51,308 |       
|Working capital                                                                    |                                               |   | 35,954                   |        |      |   | 28,122  |        |      |   | 25,678  |        |  |   | 21,408 |        |  |   | 5,467  |       

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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,
2002. 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. Actual results may differ from the estimates we calculated
due to changing business conditions or unexpected circumstances. Policies we
believe are critical to understanding our business operations and results of
operations are detailed below. For additional information on our significant
accounting policies you should see Notes to Consolidated Financial Statements,
particularly Notes 1 and 11, in our accompanying consolidated financial
statements.

Revenue Recognition  We engage in the exploration, development, acquisition
and production of natural gas and crude oil. Our revenue recognition policy is
significant because our revenue is a key component of our results of operations
and our forward-looking statements contained in Liquidity and Capital
Resources. We derive our revenue primarily from the sale of produced natural
gas and crude oil. Revenue is recorded in the month our production is delivered
to the purchaser, but payment is generally received between 20 and 90 days
after the date of production. At the end of each period we make estimates of
the amount of production delivered to the purchaser and the price we received.
We use our knowledge of our properties, their historical performance, NYMEX and
local spot market prices and other factors as the basis for these estimates.
Variances between our estimates and the actual amounts received, which have
historically been minimal, are recorded in the month such estimates are revised
or when payment is received.

Fair Value of Derivative Instruments  Beginning in 2001, the estimated fair
values of our derivative instruments are recorded on our consolidated balance
sheet. Generally, our derivative instruments are entered into to mitigate risks
related to the prices we will receive for our future natural gas and oil
production. Although our derivatives are reported on the balance sheet at fair
value, to the extent that instruments qualify for hedge accounting treatment,
changes in fair value are not included in our consolidated results of
operations. Instead, they are recorded net of taxes directly to stockholders
equity until the hedged oil or natural gas quantities are produced, at which
time any gain or loss realized is recognized as an adjustment to revenues. To
the extent changes in the fair values of derivatives relate to instruments not
qualifying for hedge accounting treatment, such changes are recorded in income
in the period they occur. In determining the amounts to be recorded, we are
required to estimate the fair values of derivatives. Our estimates are based
upon various factors that include 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 may require the use of the Black-Scholes
option-pricing model, although market quotations will be used to establish fair
value when available. For fixed price contracts, the futures prices estimated
as of the valuation date are

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compared to the prices fixed by the derivatives agreements, and the resulting
estimated future cash inflows or outflows over the lives of the hedges are
discounted to calculate the fair value of the derivative contracts. These
pricing and discounting variables are sensitive to market volatility as well as
changes in future price expectations, regional price differences and interest
rates. We periodically validate our valuations using independent third party
quotations.

Reserve Estimates  The estimates of our oil and gas reserves are, by
necessity, projections based on geologic and engineering data, and there are
uncertainties inherent in the interpretation of such data as well as the
projection of future rates of production and the timing of development
expenditures. Reserve engineering is a subjective process of estimating
underground accumulations of oil and gas that are difficult to measure. The
accuracy of any reserve estimate is a function of the quality of available
data, engineering and geological interpretation and judgment. Estimates of
economically recoverable gas and oil reserves and future net cash flows
necessarily depend upon a number of variable factors and assumptions, such as
expected future production rates, oil and gas prices, operating costs,
severance taxes and development costs, all of which may in fact vary
considerably from actual results. Future development costs projected for proved
undeveloped locations may ultimately increase to an extent that these reserves
might not be economically recoverable. For these reasons, estimates of the
economically recoverable quantities of oil and gas attributable to any
particular group of properties, classifications of such reserves based on risk
of recovery, and estimates of the future net cash flows expected there from may
vary substantially due to new data or changed assumptions. Any significant
variance in the assumptions could materially affect the estimated quantity and
value of the reserves, which could affect the carrying value of Primas oil and
gas properties and/or the rate of depletion of the oil and gas properties.
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 and
delay rentals. 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.

Depletion  The capitalized costs of our oil and gas properties, plus
estimated future development and abandonment 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
are a significant component of amortization, and revisions in such estimates
may alter the rate of future expense. Generally, if estimated reserve volumes
increase or decrease, then the amortization rate per unit of production will
change inversely. However, when estimated future costs change, the amortization
rate moves in the same direction. The per-unit rate is not affected by
production volumes.

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 the net
capitalized costs of our oil and gas properties exceed the cost center ceiling,
we are subject to a ceiling test writedown to the extent of such excess. A
ceiling test writedown is a non-cash charge to earnings. If required, it would
reduce earnings and impact stockholders equity in the period of occurrence and
result in lower amortization 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 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 associated prices of oil and gas reserves that are included in
the discounted present value of the reserves do not require judgment. The
future net revenues associated with our estimated proved reserves are not based
on our assessment of future prices. The ceiling calculation dictates that
prices and costs in effect as of the last day of the quarter are assumed to
remain constant in the

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future. However, we may not be subject to a writedown if prices increase
shortly after the end of a quarter in which a writedown might otherwise be
required.

Unevaluated Costs  Unevaluated costs are excluded from our amortization base
until we have evaluated the properties associated with these costs. The costs
associated with unevaluated leasehold acreage and wells that have not yet been
determined to be 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. Leasehold costs are
transferred to our 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
management judgment and may be subject to changes over time based on several
factors, including our drilling plans, availability of capital, project
economics and results of drilling on adjacent acreage.

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.

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 subsequently determined to be appropriate are recorded in the period
in which our estimate is revised.




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 $21,524,000 in the year ended
December 31, 2002, compared to $43,008,000 for the year ended December 31, 2001
and $36,376,000 for the year ended December 31, 2000. Our net working capital
increased from $28,122,000 at the end of 2001 to $35,954,000 on December 31,
2002. Our cash equivalents and short-term investments also increased in 2002,
from $25,755,000 at the beginning of the year to $38,007,000 at the end of
2002, and Prima was free of long-term debt at both dates. We also had no
capital lease agreements or guarantees. Our operating lease agreements are
disclosed in Note 7 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.
Oil and gas sales prices have been volatile and our average price realizations
in 2002 were 35% lower, on an Mcfe basis, than in 2001. Combined with an 11%
decline in net production volumes, these lower prices led to a 42% decline in
Primas oil and gas sales revenue from 2001 to 2002, including hedging effects,
from $44,548,000 to $25,785,000. The decline in our oil and gas sales revenue
was the primary factor accounting for lower cash flow in 2002. Primas future
revenues will continue to be significantly affected by volatility in oil and
gas

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prices. As further discussed below, oil and gas prices to-date in 2003 and as
reflected in futures markets for the balance of the year, are higher than in
2002, and we are projecting an increase in Primas net production volumes. As
such, oil and gas sales, and cash provided by operating activities, are
expected to increase in the current year.

We realized $14,577,000 of proceeds from the sale of oil and gas properties in
2002. Approximately $13,514,000 of this amount was realized through the sale on
March 5, 2002 of the Stones Throw CBM project in the northern Powder River
Basin, associated gathering system facilities and approximately 35,000 net
undeveloped acres in the Stones Throw area. The Stones Throw property accounted
for approximately 6% of our 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 Stones Throw wells accounted for
approximately 17% of our oil and gas production and 8% of our sales revenue
before hedging effects in the first two months of 2002.

We invested $22,252,000 in additions to oil and gas properties during 2002,
compared to $35,248,000 in 2001 and $31,952,000 in 2000. During 2002,
$15,157,000 was expended for oil and gas property development, $5,685,000 for
exploratory activities, $876,000 for acquisitions of unproved oil and gas
properties, and $534,000 for purchases of proved properties. Other uses of
funds in 2002 included $768,000 for other fixed assets, predominantly oilfield
service equipment and facilities, and $813,000 for treasury stock repurchases
net of proceeds from stock option exercises.

Excluding acquisitions, we plan to make capital investments in 2003 aggregating
between $25 million and $30 million. Our initial projected allocation for such
investments is approximately as follows: 50% for exploitation of CBM properties
in the Powder River Basin; 25% for development of properties in the Denver
Basin; 15% for higher-risk exploration activities; and 10% for other
operations, including oilfield service companies. The planned CBM activities
include drilling a total of 75 to 90 gross wells in our Porcupine-Tuit,
Kingsbury, Wild Turkey, and Cedar Draw project areas. Activities planned at
Porcupine-Tuit will be primarily for drilling proved undeveloped locations near
other wells that have been producing gas at favorable rates from relatively
shallow, but thick Wyodak coals for several months. Drilling at the other three
projects will be targeting non-proved reserves in deeper coals that have not
yet been extensively developed in the area. We anticipate that these deeper
coals will need to be de-watered for a longer period of time, perhaps a year or
more, before significant gas production rates could be established. As a
result, these activities may not generate additions to our production or proved
reserves in the current year. If our expectations are realized, however,
operations on these properties will result in significant increases in both
production and proved reserves in future periods. We intend to review our
capital budget on an ongoing basis and may adjust it based on drilling results,
changes in oil and gas prices, identification of new opportunities, or other
factors. In addition, although not budgeted, we continue to seek acquisitions
that we believe will enhance our existing businesses. An acquisition could be
consummated using our existing working capital, bank borrowings, and/or through
issuance of debt or equity securities.

In January 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, 2002, approximately 403,000 shares remained subject to
repurchase under this authorization.

We expect to fund our 2003 oil and gas property exploration, development, and
exploitation operations, ordinary equipment additions for our service
companies, and any repurchases of common stock with cash provided by operating
activities. Working capital on hand at the beginning of the year may also be
utilized. 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.

Without any contribution from new exploration or acquisitions, we are
projecting that our current year oil and gas production will approximate
12,500,000 Mcfe to 13,000,000 Mcfe, representing year-over-year growth of 18%
to 23%. The initial 58 wells that were hooked up at Primas Porcupine-Tuit
project area during the second half of 2002 have performed well, and this CBM
project is the principal source of the expected year-over-year production
growth. Gross production at Porcupine-Tuit has ramped up to approximately
18,000 Mcf per day at the end of February 2003, and we expect gross production
to increase to approximately 21,000 Mcf per day at some point during the second
quarter of the

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year, when the third-party contracted to gather our gas in this area is
planning to install additional compression. We have been delayed in obtaining
permits to access certain drilling locations within our Porcupine-Tuit project
area, due to regulatory review and a third-partys appeal of the Forest
Services decision in favor of approving our requested permits. We anticipate a
favorable resolution of this appeal and are currently planning to drill
approximately 26 wells beginning in the third quarter of 2003. However, this
scheduled drilling is dependent upon receiving permit approvals from both the
Forest Service and the Bureau of Land Management, and further delays could be
encountered. If such delays occur, our estimates of 2003 production could be
unfavorably impacted. Prima plans to hook-up four wells drilled at
Porcupine-Tuit in 2002 that are currently shut-in later in the year. If
drilling permits are secured for new drilling, hook-up of these four wells and
new wells drilled in 2003 will be coordinated to maximize efficiencies. Our net
working and revenue interests in the existing and planned wells at
Porcupine-Tuit average approximately 93% and 78%, respectively.

Natural gas is currently expected to account for more than 85% of Primas total
oil and gas production in 2003. Gas prices have strengthened during the past
several months, in response to a number of factors, including (among others):



| |  |  | cold weather during the winter of 2002-2003 that has reduced storage inventories;  
| | - |  | -----------------------------------------------------------------------------------
|
| |  |  | declining North American natural gas production; and                               
|
| |  |  | a modest response to-date in drilling activity levels in response to higher prices.

As of March 18, 2003, average prices for the 2003 NYMEX gas contracts that have
expired (January through March) plus the average of the quoted prices for the
remainder of 2003 NYMEX gas contracts combine to average $5.59 per MMBtu of
natural gas. These compare to the average closing prices for NYMEX gas
contracts during 2002 of $3.34 per MMBtu of natural gas. Our realized gas
prices are generally lower than NYMEX, due primarily to location and
transportation costs, as discussed below, but these NYMEX comparisons are a
reflection of recent price movements in gas markets. There is no assurance,
however, that prices reflected in futures markets will actually be realized,
except to the extent that fixed price contracts are entered into.

As of the close of business on March 18, 2003, we had forward-sold 200,000
MMBtu of natural gas per month for the months of May 2003 through October 2003,
at an average NYMEX price of $5.81 per MMBtu. These contracts do not qualify as
effective hedges because we have not locked in the basis differential between
the NYMEX-contract Henry Hub delivery point and a Rocky Mountain delivery point
near our wells. For the period covered by these NYMEX contracts, this basis
differential was quoted at approximately $1.20 per MMBtu discount for The
Colorado Interstate Gas (CIG) Index, as of March 18, 2003. An additional
200,000 MMBtu of natural gas have been forward-sold for April 2003, at an
average CIG price of $4.20 per MMBtu, which represents an effective hedge. With
respect to crude oil, as of March 18, 2003 we had entered into forward-sale
NYMEX contracts covering 5,000 barrels per month for the contract months of
July 2003 through December 2003, at an average price of $30.75 per barrel.
Combined, these positions total approximately 1,580,000 Mcfe of volumes,
representing less than 20% of Primas expected oil and gas production during
the last nine months of 2003.




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. Gas prices declined significantly after reaching
record high levels early in 2001, until early 2003 when prices again approached
record levels. 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.

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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
2002, CIG gas prices have averaged approximately $0.57 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 $1.37 (2002), and monthly variances in
index prices have ranged between an $0.11 premium (January 1993) and a $2.44
discount (October 2002). Basis differentials widened considerably beginning in
May 2002, resulting in depressed regional prices for Rocky Mountain gas in 2002
despite relatively strong gas prices in other areas of the country.

Although Rocky Mountain gas prices improved during this past winter, basis
differentials have remained wide, as prices in other regions have increased as
much or more. Due in part to pipeline capacity expansion projects that will
improve access to higher-priced gas markets, commodity futures markets as of
March 18, 2003 reflected expectations of moderately improving basis
differentials, to $1.32 per MMBtu from May through October 2003, and $0.77 per
MMBtu for the winter of 2003-2004. The largest of these planned expansions, and
the one scheduled to come on line soonest, is the Kern River Pipeline, which is
expected to commence operations in May 2003 with an additional 900,000 Mcf per
day of capacity that will move gas from southwest Wyoming to Nevada and
California markets. 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.

The following table, which presents selected operating data, is followed by
discussion of our results of operations for the periods indicated:

|                                              |  |      |            |      |  |      |            |  |  |   |            | 
|--------------------------------------------- |  | ---- | ---------- | ---- |  | ---- | ---------- |  |  | - | ---------- | 
|                                              |  | 2002 |            | 2001 |  | 2000
|                                              |  |      |            |      |  |     
|Production:                                   |  |      |            |      |  |      |            |  |  |   |            | 
|Natural gas (Mcf)                             |  |      | 8,343,000  |      |  |      | 9,277,000  |  |  |   | 8,683,000  | 
|Oil (barrels)                                 |  |      | 373,000    |      |  |      | 431,000    |  |  |   | 440,000    | 
|Total natural gas equivalents (Mcfe)          |  |      | 10,580,000 |      |  |      | 11,863,000 |  |  |   | 11,325,000 | 
|Revenue:                                      |  |      |            |      |  |      |            |  |  |   |            | 
|Natural gas sales                             |  | $    | 16,413,000 |      |  | $    | 33,392,000 |  |  | $ | 31,542,000 | 
|Oil sales                                     |  | $    | 9,372,000  |      |  | $    | 11,156,000 |  |  | $ | 12,895,000 | 
|Total oil and gas sales                       |  | $    | 25,785,000 |      |  | $    | 44,548,000 |  |  | $ | 44,437,000 | 
|Avg. sales price (including hedging effects): |  |      |            |      |  |      |            |  |  |   |            | 
|Natural gas (per Mcf)                         |  | $    | 1.97       |      |  | $    | 3.60       |  |  | $ | 3.63       | 
|Oil (per barrel)                              |  | $    | 25.14      |      |  | $    | 25.88      |  |  | $ | 29.29      | 
|Total natural gas equivalents (per Mcfe)      |  | $    | 2.44       |      |  | $    | 3.76       |  |  | $ | 3.92       | 
|Expenses (per Mcfe):                          |  |      |            |      |  |      |            |  |  |   |            | 
|Depletion of oil & gas properties             |  | $    | 0.92       |      |  | $    | 0.77       |  |  | $ | 0.54       | 
|Lease operating expense                       |  | $    | 0.29       |      |  | $    | 0.28       |  |  | $ | 0.23       | 
|Ad valorem and production taxes               |  | $    | 0.20       |      |  | $    | 0.28       |  |  | $ | 0.30       | 
|General and administrative expense            |  | $    | 0.31       |      |  | $    | 0.30       |  |  | $ | 0.26       | 

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 compare 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

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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.

Our revenues for 2002 included $3,376,000 of aggregate losses from oil and gas
derivatives (see Derivatives Contracts in Note 4 of Notes to Consolidated
Financial Statements). This total included hedging losses of $458,000, which
were reflected in our oil and gas sales, plus $2,918,000 of separately reported
losses on derivative instruments that did not qualify for hedge accounting.
Derivative instruments that did not 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 $2,918,000 of
recorded losses on non-qualifying derivatives consisted of $1,546,000 of net
amounts received by us on settlements of positions closed in 2002, offset by
$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.

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. Total gains
realized by us on all derivatives pertaining to production months in 2002,
including the portion reported as non-hedge derivatives, totaled $1,088,000.
Total gains realized on all derivatives related to production months in 2001,
including the portion reported as non-hedge derivatives, totaled $5,438,000.

Oil and gas sales reported by us 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
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 natural gas production totaled 8,343,000 Mcf in 2002 compared to 9,277,000
Mcf in 2001, representing a current year 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 decreased approximately 11%, to 10,580,000
Mcfe in 2002, from 11,863,000 Mcfe in 2001. Total production was 79% natural
gas and 21% oil in 2002, compared to 78% gas and 22% oil in the prior year.

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 $1,291,000 and $1,369,000 for 2002 and 2001,
respectively.

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Lease operating expenses (LOE) 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.

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 $8,326,000 for the year ended December 31, 2002
compared to $8,090,000 for the year ended December 31, 2001, an increase of
$236,000, or 3%. Costs of oilfield services provided to third parties were
$6,287,000 in 2002 compared to $5,482,000 for 2001, an increase of $805,000 or
15%. Approximately 19% of fees billed by the service companies in 2002 were for
Prima-owned property interests, compared to 34% in 2001.

General and administrative expenses (G&A), 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
increased 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 $1,573,000 in 2001 to
$1,944,000 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. Permanent differences will be smaller in future years, in the
absence of new legislation, as a result of the expiration of Section 29 tax
credits at the end of 2002.

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 is accounted for by the Stones
Throw property disposition, and net revisions aggregating approximately 16,614
MMcfe. Estimated additions to proved reserves from extensions, discoveries and
acquisitions in 2002 totaled approximately 10,971 MMcfe, slightly greater than
total production during the year of approximately 10,580 MMcfe. Most of Primas
investments in 2002 were directed toward activities that did not add, nor were
expected to add, incremental proved reserves during the year, including:



| |  |  | development of previously-established proved reserves in the Denver
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 has not yet been completed and determination of commerciality
is 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 more conservative
estimation methodology and incorporation of additional data related to
non-producing properties with thinner, shallower coals. In addition to
incorporating stricter criteria employed by Primas independent engineers for
determining which undrilled CBM locations qualified as having proved reserves,
Prima elected

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to prepare estimates of CBM reserves at the end of 2002 utilizing more
conservative assumptions than previously used. Among the changes were the
following:



| |  |  | 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 reflect an
assumption of 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.

As a result, our estimated reserves at the end of 2002 excluded properties with
thinner, shallower coals that we do not currently anticipate developing, as we
concentrate on higher-potential reserve targets. At December 31, 2002, these
higher-potential reserve targets were not proved. Generally, these 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. These deeper coals are in the early stages of evaluation
and development by Prima and other operators in the area.

2001 vs. 2000

For the year ended December 31, 2001, we reported net income of $23,768,000, or
$1.80 per diluted share, on revenues of $60,287,000. These amounts compare to
net income of $21,895,000, or $1.65 per diluted share, on revenues of
$52,179,000 in the year ended December 31, 2000. Expenses, other than income
taxes, were $26,480,000 for 2001 compared to $20,749,000 for 2000. Revenues
increased $8,108,000 or 16%, expenses increased $5,731,000 or 28% and net
income increased $1,873,000 or 9% in 2001.

Our revenues for 2001 included $9,816,000 of gains from oil and gas
derivatives. This total included hedging gains of $3,381,000, which were
reflected in oil and gas sales, plus $6,435,000 of separately reported gains on
derivative instruments not qualifying for hedge accounting, of which $2,057,000
was realized and $4,378,000 was unrealized as of December 31, 2001. Total gains
realized on all derivatives related to production months in 2001, including the
portion reported as non-hedge derivatives, totaled $5,438,000. During the prior
year, we realized $42,000 of hedging gains, all of which was recognized as a
component of oil and gas sales.

Oil and gas sales reported for 2001 totaled $44,548,000, compared to
$44,437,000 for 2000, an increase of less than 1%. The flat sales results were
creditable to a 5% year-over-year growth in production volumes offset by
approximately a like-sized decline in the average price realized per equivalent
unit of production. Excluding gains from derivative instruments, oil and gas
sales reported for 2001 were $41,167,000, compared to $44,395,000 for 2000, a
decrease of $3,228,000 or 7%.

The following information is provided excluding effects of derivatives. The
average sales price received for our natural gas production was $3.24 per Mcf
in 2001, compared to $3.63 per Mcf in 2000, a decrease of $0.39 per Mcf, or
11%. The average price we received per barrel of oil was $25.68 in 2001,
compared to $29.20 in 2000, representing a decrease of $3.52 per barrel or 12%.
On an Mcf equivalent basis, the average price received was $3.47 per Mcfe in
2001 compared to $3.92 per Mcfe in the prior year, representing an overall 11%
decline in average prices. The portion of total oil and gas revenues that we
derived from natural gas was 73% in 2001, compared to 71% in 2000.

Our natural gas production totaled 9,277,000 Mcf in 2001 compared to 8,683,000
Mcf in 2000, representing an increase of 594,000 Mcf, or 7%. Our oil
production totaled 431,000 barrels and 440,000 barrels in 2001 and 2000,
respectively, representing a decrease of 9,000 barrels, or 2%. On an equivalent
unit basis, production increased approximately 5%, to 11,863,000 Mcfe in 2001,
from 11,325,000 Mcfe in 2000. Total production was 78% natural gas and 22% oil
in 2001, compared to 77% gas and 23% oil in the prior year. Net production from
our CBM operations, which totaled 1,453,000

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Mcf in 2001 compared to 7,000 Mcf in 2000, more than offset net decreases from
other producing properties that were attributable to natural declines and
limited new activity in the second half of 2001.

Our depletion expense for oil and gas properties was $9,190,000, or $0.77 per
Mcfe, in 2001, compared to $6,150,000, or $0.54 per Mcfe, in 2000. The increase
in the depletion rate reflected a number of factors, including:



| |  | significant declines in oil and gas prices, which, under the
methodology prescribed, affects estimates of oil and gas reserves that
can be economically recovered through future production;
|- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| 
| |  | increases in oilfield service costs, which impacted actual costs
incurred and the assumptions used to estimate future development costs;
and                                                
| 
| |  | use of more conservative assumptions for estimating undeveloped CBM
reserves.                                                                                                               

The depletion rate per Mcfe was increased mid-year 2001 to reflect these
factors, and averaged $0.90 during the second half of the year. Depreciation of
other fixed assets was $1,369,000 and $1,054,000 for 2001 and 2000,
respectively. The increase of $315,000, or 30%, was due primarily to
acquisitions of oilfield service equipment in 2000 and 2001.

Our LOE totaled $3,295,000 for the year ended December 31, 2001 compared to
$2,623,000 for the year ended December 31, 2000, an increase of $672,000 or
26%. The increase was primarily attributable to new production from CBM wells.
Ad valorem and production taxes were $3,344,000 and $3,421,000 for the same
periods, a decrease of $77,000 or 2%. Production taxes fluctuate with revenues
and changing mill levy rates, and averaged 8.1% of total oil and gas sales
excluding hedging effects in 2001 and 7.7% in 2000. Total lifting costs (LOE
plus ad valorem and production taxes) were $0.56 per Mcfe for 2001 compared to
$0.53 per Mcfe for 2000.

Oilfield service revenues from third parties totaled $8,090,000 for the year
ended December 31, 2001, compared to $6,278,000 for the year ended December 31,
2000, an increase of $1,812,000, or 29%. Costs of oilfield services provided to
third parties were $5,482,000 in 2001, compared to $4,585,000 for 2000, an
increase of $897,000 or 20%. Higher revenues and costs both reflected increases
in the amount of equipment placed in service. Improved revenues were also
partially attributable to rate increases resulting from increased demand for
oilfield services. Approximately 34% of fees billed by the service companies in
2001 were for Prima-owned property interests, compared to 37% in 2000.

G&A, net of third party reimbursements and amounts capitalized, totaled
$3,559,000 for the year ended December 31, 2001 compared to $2,916,000 for the
year ended December 31, 2000. Net G&A costs increased by $643,000 or 22% due to
expansion of our activities and operations, partially offset by increased
amounts capitalized. Third party reimbursements of management and operator fees
decreased from $426,000 in 2000 to $371,000 in 2001 as the result of
acquisitions of additional ownership interests in certain managed properties.
Capitalized G&A increased from $1,200,000 in 2000 to $1,573,000 in 2001,
reflecting additional costs incurred to manage exploration and development
activities.

Our provision for income taxes was $10,650,000 for the year ended December 31,
2001 compared to $9,535,000 for the year ended December 31, 2000, an increase
of $1,115,000 or 12%. Primas effective tax rate increased to 31.5% in 2001
from 30.3% in 2000. The higher effective tax rate in 2001 was primarily
attributable to a $2,377,000, or 8%, increase in pre-tax income without a
proportionate increase in permanent differences.

Proved oil and gas reserves: From the end of 2000 to the end of 2001, our
proved oil and gas reserves declined by 40,960 MMcfe, from 176,546 MMcfe to
135,586 MMcfe. The 23% decline was attributable to a 48,161 MMcfe reduction of
previous estimates of proved reserves, largely attributable to using average
gas and oil prices that were 74% and 26% lower, respectively, than at the end
of 2000. Estimated reserve quantities were particularly affected for our CBM
properties in the Powder River Basin, for which average gas prices dropped by
81%, from $7.14 per Mcf at the end of 2000 to $1.38 per Mcf at the end of 2001.
Overall, average prices used to calculate proved reserves were $1.94 per Mcf of
natural gas and $19.71 per barrel of oil at December 31, 2001, compared to
$7.57 and $26.48, respectively, at the end of 2000. Revisions also reflected
changes in estimated future costs and more conservative assumptions used to
estimate undeveloped CBM reserves, as noted above.

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New Accounting Pronouncements

In July 2001, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for
Asset Retirement Obligations. This statement requires companies to recognize
the fair value of an asset retirement liability in the financial statements by
capitalizing that cost as part of the cost of the related long-lived asset. The
asset retirement liability should then be allocated to expense by using a
systematic and rational method. The statement is effective January 1, 2003. The
Company has not determined the impact of adoption of this statement.

In April 2002 the FASB issued SFAS No. 145, Rescission of FASB Statements No.
4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.
This Statement rescinds SFAS No. 4, Reporting Gains and Losses from
Extinguishment of Debt, and an amendment of that Statement, SFAS No. 64,
Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements. This
Statement also rescinds SFAS No. 44, Accounting for Intangible Assets of
Motor Carriers. This Statement amends SFAS No. 13, Accounting for Leases,
to eliminate an inconsistency between the required accounting for
sale-leaseback transactions and the required accounting for certain lease
modifications that have economic effects that are similar to sale-leaseback
transactions. This Statement also amends other existing authoritative
pronouncements to make various technical corrections, clarify meanings, or
describe their applicability under changed conditions. The provisions of this
Statement shall be applied in fiscal years beginning after May 15, 2002. We
currently do not believe that adoption of this Statement will have an impact on
the Company.

In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated
With Exit or Disposal Activities, which provides guidance for financial
accounting and reporting of costs associated with exit or disposal activities
and nullifies EITF Issue No. 94-3, Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring). This statement requires the recognition of
a liability for a cost associated with an exit or disposal activity when the
liability is incurred, as opposed to when the entity commits to an exit plan
under EITF No. 94-3. The statement is effective for the Company in 2003. The
adoption of SFAS No. 146 is not expected to have a material effect on the
Companys financial position or results of operations.

In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based
Compensation  Transition and Disclosure  an amendment of FASB Statement No.
123. SFAS No. 148 amends SFAS No. 123, Accounting for Stock-Based
Compensation to provide alternative methods of transition for a voluntary
change to the fair value based method of accounting for stock-based employee
compensation. In addition, SFAS No. 148 amends the disclosure requirements of
SFAS No. 123 to require prominent disclosures in both annual and interim
financial statements about the method of accounting for stock-based employee
compensation and the effect of the method used on reported results. SFAS No.
148 is effective for financial statements for fiscal years ending after
December 15, 2002. Prima  currently intends to continue to account for stock based
compensation using the methods detailed in the stock-based compensation
accounting policy and to provide disclosures as prescribed by SFAS 148.




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 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.

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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 Note 1 and Note 4 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 2002, we sold 373,000 barrels of produced oil. A hypothetical decrease
of $2.61 per barrel (10% of average prices for the period exclusive of hedging
transactions) would have decreased our revenues by $974,000 for the period. We
sold 8,343,000 Mcf of produced natural gas during the same period. A
hypothetical decrease of $0.20 per Mcf (10% of average prices for the period
exclusive of hedging transactions) would have decreased our revenues by
$1,669,000 for the period.

We closed on certain derivatives positions between the end of 2002 and March
18, 2003, for net realized losses totaling $162,000. As of the close of
business on March 18, 2003, our open oil and gas derivatives instruments
reflected net unrealized mark-to-market gains of $992,000, as follows:

|                       |                      |       |        |                 |               |           |          |       |            |        |         |  |   |         |         |  | 
|---------------------- | -------------------- | ----- | ------ | --------------- | ------------- | --------- | -------- | ----- | ---------- | ------ | ------- |  | - | ------- | ------- |  | 
|                       |                      |       |        |                 |               |           |          |       |            |        | Average |  |   |         |        
|                       |                      |       | Market |                 | Total Volumes |           | Contract |       | Unrealized
|Time Period            |                      | Index |        | (MMBtu or Bbls) |               | Price     |          | Gains
|                       |                      |       |        |                 |               |           |          |      
|Natural Gas Futures    |                      |       |        |                 |               |           |          |       |            |        |         |  |   |        
|                       | April 2003           |       | CIG    |                 |               | 200,000   |          |       | $          | 4.200  |         |  | $ | 184,000 |        
|                       | May - October 2003   |       | NYMEX  |                 |               | 1,200,000 |          |       |            | 5.813  |         |  |   | 711,000 |        
|Oil Futures           
|                       | July - December 2003 |       | NYMEX  |                 |               | 30,000    |          |       |            | 30.750 |         |  |   | 97,000  |        
|                       |                      |       |        |                 |               |           |          |       |            |        |         |  |   |         |         | 
|Total Unrealized Gains |                      |       |        |                 |               |           |          |       |            |        |         |  |   | $       | 992,000 | 
|                       |                      |       |        |                 |               |           |          |       |            |        |         |  |   |         |         | 

The CIG natural gas contracts, but not the NYMEX natural gas contracts, are
considered to be effective hedges, since Primas current production is all
located in the Rocky Mountain region. For the period covered by these NYMEX
contracts, a recent quote to lock in the basis differential, which would
convert the NYMEX natural gas contracts to effective hedges, was approximately
a $1.20 per MMBtu discount for Rocky Mountain natural gas. The oil contracts
also represent effective hedges. Combined, these positions total approximately
1,580,000 Mcfe of volumes, representing less than 20% of Primas expected oil
and gas production during the last nine months of 2003.

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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.




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




ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12, and 13 are omitted
because we will 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 scheduled for May 12, 2003 and is hereby incorporated by
reference.




ITEM 14. 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-14(c) and 15d-14(c) 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. 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.

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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

|                                                                                                     |  |      |    | 
|---------------------------------------------------------------------------------------------------- |  | ---- | -- | 
|                                                                                                     |  | Page
|                                                                                                     |  |     
|Independent Auditors Report                                                                         |  |      | 45 | 
|Consolidated Balance Sheets at December 31, 2002 and 2001                                            |  |      | 46 | 
|Consolidated Statements of Income for the years ended
December 31, 2002, 2001 and 2000               |  |      | 48 | 
|Consolidated Statements of Comprehensive Income for the years ended
December 31, 2002, 2001 and 2000 |  |      | 49 | 
|Consolidated Statements of Stockholders Equity for the years ended
December 31, 2002, 2001 and 2000 |  |      | 50 | 
|Consolidated Statements of Cash Flows for the years ended
December 31, 2002, 2001 and 2000           |  |      | 51 | 
|Notes to Consolidated Financial Statements for the years ended
December 31, 2002, 2001 and 2000      |  |      | 52 | 

(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, 2002, Prima filed the following current
reports on Form 8-K:



| |  |  | Report dated November 12, 2002, reporting earnings for the quarter
and nine months ended September 30, 2002, and providing an update on
operating activities and commodity hedging.                                                                                                                                          
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | Report dated November 14, 2002 submitting certifications by the
Chief Executive Officer and Chief Financial Officer of Prima Energy
Corporation pursuant to 18 U.S.C. §1350 as adopted by §906 of the
Sarbanes-Oxley Act of 2002.                                                                                            
|
| |  |  | Report dated November 29, 2002 providing an update on its
exploratory well in the Coyote Flats prospect, reporting on a joint
venture agreement reached with a private company to develop coal bed
methane reserves in the Powder River Basin, and announcing the
resignation of its Vice President of Corporate Development.

(c)  Exhibits

The following exhibits are filed with or are incorporated by reference into
this report on Form 10-K.

|        |  |                                                                                                                                                                                                                         
|------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit |  |                                                                                                                                                                                                                         
|No.     |  | Document                                                                                                                                                                                                                
|        |  |                                                                                                                                                                                                                         
|3.1     |  | 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.)

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|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|No.     |  | Document                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|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, as Exhibit A, the Form of Right Certificate, as
Exhibit B, 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,
2000. (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 the 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.)                                                                                                                                                                                                                                                                                                                             
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|21      |  | Subsidiaries of the Registrant                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|23.1    |  | Consent of Independent Auditors                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|23.2    |  | Consent of Independent Reservoir Engineers and Geologists                                                                                                                                                                                                                                                                                                                                                                                                                                                       

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INDEPENDENT AUDITORS REPORT

Prima Energy Corporation:

We have audited the accompanying consolidated balance sheets of Prima
Energy Corporation (Company) and subsidiaries as of December 31, 2002 and
2001, and the related consolidated statements of income, comprehensive income,
stockholders equity, and cash flows for each of the three years in the period
ended December 31, 2002. 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, 2002 and 2001, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2002 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.

DELOITTE & TOUCHE LLP

March 14, 2003
Denver, Colorado

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PRIMA ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2002 and 2001

ASSETS

|                                                                            |                              |                      |             |            |            |      |             |            |            | 
|--------------------------------------------------------------------------- | ---------------------------- | -------------------- | ----------- | ---------- | ---------- | ---- | ----------- | ---------- | ---------- | 
|                                                                            |                              |                      |             | 2002       |            | 2001
|                                                                            |                              |                      |             |            |            |     
|CURRENT ASSETS                                                              |                              |                      |             |            |            |      |             |           
|Cash and cash equivalents                                                   |                              | $                    | 36,263,000  |            |            | $    | 23,337,000  |           
|Available for sale securities, at market                                    |                              |                      | 1,744,000   |            |            |      | 2,418,000   |           
|Receivables (net of allowance for doubtful
accounts: $304,000 and $295,000) |                              |                      | 7,492,000   |            |            |      | 5,806,000   |           
|Derivatives, at fair value                                                  |                              |                      |            |            |            |      | 4,472,000   |           
|Inventory                                                                   |                              |                      | 940,000     |            |            |      | 1,415,000   |           
|Other                                                                       |                              |                      | 818,000     |            |            |      | 710,000     |           
|                                                                            |                              |                      |             |            |            |      |             |           
|                                                                            |                              | Total current assets |             |            | 47,257,000 |      |             |            | 38,158,000 | 
|                                                                            |                              |                      |             |            |            |      |             |           
|OIL AND GAS PROPERTIES, at cost, accounted for
using the full cost method:  |                              |                      |             |            |            |      |             |           
|Proved                                                                      |                              |                      | 130,948,000 |            |            |      | 130,710,000 |           
|Unproved                                                                    |                              |                      | 20,570,000  |            |            |      | 13,132,000  |           
|Less accumulated depreciation, depletion and
amortization                   |                              |                      | (62,980,000 | )          |            |      | (53,270,000 | )         
|                                                                            |                              |                      |             |            |            |      |             |           
|                                                                            | Oil and gas properties  net |                      |             | 88,538,000 |            |      |             | 90,572,000 |           
|                                                                            |                              |                      |             |            |            |      |             |           
|PROPERTY AND EQUIPMENT, at cost                                             |                              |                      |             |            |            |      |             |           
|Oilfield service equipment                                                  |                              |                      | 9,457,000   |            |            |      | 9,159,000   |           
|Furniture and equipment                                                     |                              |                      | 712,000     |            |            |      | 694,000     |           
|Field office, shop and land                                                 |                              |                      | 478,000     |            |            |      | 473,000     |           
|                                                                            |                              |                      |             |            |            |      |             |           
|                                                                            |                              |                      | 10,647,000  |            |            |      | 10,326,000  |           
|Less accumulated depreciation                                               |                              |                      | (5,808,000  | )          |            |      | (4,893,000  | )         
|                                                                            |                              |                      |             |            |            |      |             |           
|                                                                            | Property and equipment  net |                      |             | 4,839,000  |            |      |             | 5,433,000  |           
|                                                                            |                              |                      |             |            |            |      |             |           
|OTHER ASSETS                                                                |                              |                      | 1,293,000   |            |            |      | 1,281,000   |           
|                                                                            |                              |                      |             |            |            |      |             |           
|                                                                            |                              | $                    | 141,927,000 |            |            | $    | 135,444,000 |           
|                                                                            |                              |                      |             |            |            |      |             |           

See accompanying notes to consolidated financial statements.

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PRIMA ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS (contd.)
DECEMBER 31, 2002 and 2001

LIABILITIES AND STOCKHOLDERS EQUITY

|                                                                                                      |                           |                            |             |            |             |      |             |            |             | 
|----------------------------------------------------------------------------------------------------- | ------------------------- | -------------------------- | ----------- | ---------- | ----------- | ---- | ----------- | ---------- | ----------- | 
|                                                                                                      |                           |                            |             | 2002       |             | 2001
|                                                                                                      |                           |                            |             |            |             |     
|CURRENT LIABILITIES                                                                                   |                           |                            |             |            |             |      |             |           
|Accounts payable                                                                                      |                           | $                          | 3,129,000   |            |             | $    | 1,668,000   |           
|Amounts payable to oil and gas property owners                                                        |                           |                            | 3,192,000   |            |             |      | 1,910,000   |           
|Ad valorem and production taxes payable                                                               |                           |                            | 3,864,000   |            |             |      | 3,272,000   |           
|Accrued and other liabilities                                                                         |                           |                            | 893,000     |            |             |      | 1,408,000   |           
|Derivatives, at fair values                                                                           |                           |                            | 225,000     |            |             |      |            |           
|Deferred tax liability                                                                                |                           |                            |            |            |             |      | 1,778,000   |           
|                                                                                                      |                           |                            |             |            |             |      |             |           
|                                                                                                      | Total current liabilities |                            |             | 11,303,000 |             |      |             | 10,036,000 |            
|AD VALOREM TAXES, non-current                                                                         |                           |                            | 2,077,000   |            |             |      | 3,302,000   |           
|DEFERRED INCOME TAX LIABILITY                                                                         |                           |                            | 21,281,000  |            |             |      | 20,366,000  |           
|                                                                                                      |                           |                            |             |            |             |      |             |           
|                                                                                                      |                           | Total liabilities          |             |            | 34,661,000  |      |             |            | 33,704,000  | 
|                                                                                                      |                           |                            |             |            |             |      |             |           
|STOCKHOLDERS EQUITY                                                                                  |                           |                            |             |            |             |      |             |           
|Preferred stock, $0.001 par value, 2,000,000 shares
authorized; no shares issued                      |                           |                            |            |            |             |      |            |           
|Common stock, $0.015 par value, 35,000,000 shares
authorized; 13,064,048 and 12,889,923 shares issued |                           |                            | 196,000     |            |             |      | 193,000     |           
|Additional paid-in capital                                                                            |                           |                            | 5,250,000   |            |             |      | 3,147,000   |           
|Retained earnings                                                                                     |                           |                            | 107,470,000 |            |             |      | 102,240,000 |           
|Accumulated other comprehensive income (loss)                                                         |                           |                            | (115,000    | )          |             |      | 26,000      |           
|Treasury stock, 236,538 and 155,351 shares, at cost                                                   |                           |                            | (5,535,000  | )          |             |      | (3,866,000  | )         
|                                                                                                      |                           |                            |             |            |             |      |             |           
|                                                                                                      |                           | Stockholders equity  net |             |            | 107,266,000 |      |             |            | 101,740,000 | 
|                                                                                                      |                           |                            |             |            |             |      |             |           
|                                                                                                      |                           | $                          | 141,927,000 |            |             | $    | 135,444,000 |           
|                                                                                                      |                           |                            |             |            |             |      |             |           

See accompanying notes to consolidated financial statements.

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PRIMA ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 and 2000

|                                                                                        |                                        |   |            |           |      |   |            |           |  |   |            |           | 
|--------------------------------------------------------------------------------------- | -------------------------------------- | - | ---------- | --------- | ---- | - | ---------- | --------- |  | - | ---------- | --------- | 
|                                                                                        |                                        |   | 2002       |           | 2001 |   | 2000      
|                                                                                        |                                        |   |            |           |      |   |           
|REVENUES                                                                                |                                        |   |            |           |      |   |            |           |  |   |            |          
|Oil and gas sales                                                                       |                                        | $ | 25,785,000 |           |      | $ | 44,548,000 |           |  | $ | 44,437,000 |          
|Gains (losses) on derivative instruments, net                                           |                                        |   | (2,918,000 | )         |      |   | 6,435,000  |           |  |   |           |          
|Oilfield services                                                                       |                                        |   | 8,326,000  |           |      |   | 8,090,000  |           |  |   | 6,278,000  |          
|Interest, dividend and other income                                                     |                                        |   | 597,000    |           |      |   | 1,214,000  |           |  |   | 1,464,000  |          
|                                                                                        |                                        |   |            |           |      |   |            |           |  |   |            |          
|                                                                                        |                                        |   | 31,790,000 |           |      |   | 60,287,000 |           |  |   | 52,179,000 |          
|                                                                                        |                                        |   |            |           |      |   |            |           |  |   |            |          
|EXPENSES                                                                                |                                        |   |            |           |      |   |            |           |  |   |            |          
|Depreciation, depletion and amortization:                                               |                                        |   |            |           |      |   |            |           |  |   |            |          
|                                                                                        | Depletion of oil and gas properties    |   |            | 9,710,000 |      |   |            | 9,190,000 |  |   |            | 6,150,000 | 
|                                                                                        | Depreciation of property and equipment |   |            | 1,291,000 |      |   |            | 1,369,000 |  |   |            | 1,054,000 | 
|Lease operating expense                                                                 |                                        |   | 3,076,000  |           |      |   | 3,295,000  |           |  |   | 2,623,000  |          
|Ad valorem and production taxes                                                         |                                        |   | 2,116,000  |           |      |   | 3,344,000  |           |  |   | 3,421,000  |          
|Oilfield services                                                                       |                                        |   | 6,287,000  |           |      |   | 5,482,000  |           |  |   | 4,585,000  |          
|General and administrative                                                              |                                        |   | 3,255,000  |           |      |   | 3,559,000  |           |  |   | 2,916,000  |          
|Impairment of natural gas swap                                                          |                                        |   |           |           |      |   | 241,000    |           |  |   |           |          
|                                                                                        |                                        |   |            |           |      |   |            |           |  |   |            |          
|                                                                                        |                                        |   | 25,735,000 |           |      |   | 26,480,000 |           |  |   | 20,749,000 |          
|                                                                                        |                                        |   |            |           |      |   |            |           |  |   |            |          
|Income before income taxes and cumulative effect
of change in accounting principle      |                                        |   | 6,055,000  |           |      |   | 33,807,000 |           |  |   | 31,430,000 |          
|Provision for income taxes                                                              |                                        |   | 825,000    |           |      |   | 10,650,000 |           |  |   | 9,535,000  |          
|                                                                                        |                                        |   |            |           |      |   |            |           |  |   |            |          
|Net income before cumulative effect of change in
accounting principle                   |                                        |   | 5,230,000  |           |      |   | 23,157,000 |           |  |   | 21,895,000 |          
|Cumulative effect of change in accounting principle
(net of income taxes of $265,000)   |                                        |   |           |           |      |   | 611,000    |           |  |   |           |          
|                                                                                        |                                        |   |            |           |      |   |            |           |  |   |            |          
|NET INCOME                                                                              |                                        | $ | 5,230,000  |           |      | $ | 23,768,000 |           |  | $ | 21,895,000 |          
|                                                                                        |                                        |   |            |           |      |   |            |           |  |   |            |          
|Basic net income per share before cumulative effect
of change in accounting principle   |                                        | $ | 0.41       |           |      | $ | 1.82       |           |  | $ | 1.72       |          
|Cumulative effect of change in accounting
principle                                     |                                        |   |           |           |      |   | 0.05       |           |  |   |           |          
|                                                                                        |                                        |   |            |           |      |   |            |           |  |   |            |          
|BASIC NET INCOME PER SHARE                                                              |                                        | $ | 0.41       |           |      | $ | 1.87       |           |  | $ | 1.72       |          
|                                                                                        |                                        |   |            |           |      |   |            |           |  |   |            |          
|Diluted net income per share before cumulative
effect of change in accounting principle |                                        | $ | 0.40       |           |      | $ | 1.75       |           |  | $ | 1.65       |          
|Cumulative effect of change in accounting
principle                                     |                                        |   |           |           |      |   | 0.05       |           |  |   |           |          
|                                                                                        |                                        |   |            |           |      |   |            |           |  |   |            |          
|DILUTED NET INCOME PER SHARE                                                            |                                        | $ | 0.40       |           |      | $ | 1.80       |           |  | $ | 1.65       |          
|                                                                                        |                                        |   |            |           |      |   |            |           |  |   |            |          

See accompanying notes to consolidated financial statements.

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PRIMA ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 and 2000

|                                                                                             |  |      |           |      |  |      |            |   |  |   |            |  
|-------------------------------------------------------------------------------------------- |  | ---- | --------- | ---- |  | ---- | ---------- | - |  | - | ---------- | -
|                                                                                             |  | 2002 |           | 2001 |  | 2000
|                                                                                             |  |      |           |      |  |     
|Net income                                                                                   |  | $    | 5,230,000 |      |  | $    | 23,768,000 |   |  | $ | 21,895,000 |  
|                                                                                             |  |      |           |      |  |      |            |   |  |   |            |  
|Other comprehensive income (loss):                                                           |  |      |           |      |  |      |            |   |  |   |            |  
|Change in fair value of hedges                                                               |  |      | (690,000  | )    |  |      | 3,475,000  |   |  |   |           |  
|Reclassification adjustment for realized losses
(gains)
on hedges included in net income     |  |      | 458,000   |      |  |      | (3,381,000 | ) |  |   |           |  
|Deferred income tax benefit (expense) related
to change
in fair value of hedges              |  |      | 86,000    |      |  |      | (35,000    | ) |  |   |           |  
|Change in fair value of available-for-sale
securities                                        |  |      | (16,000   | )    |  |      | 147,000    |   |  |   | 170,000    |  
|Reclassification adjustment for realized losses
included in net income                       |  |      | 25,000    |      |  |      | 1,000      |   |  |   | 18,000     |  
|Deferred income tax expense related to change in
fair value of available-for-sale securities |  |      | (4,000    | )    |  |      | (55,000    | ) |  |   | (70,000    | )
|                                                                                             |  |      |           |      |  |      |            |   |  |   |            |  
|                                                                                             |  |      | (141,000  | )    |  |      | 152,000    |   |  |   | 118,000    |  
|                                                                                             |  |      |           |      |  |      |            |   |  |   |            |  
|COMPREHENSIVE INCOME                                                                         |  | $    | 5,089,000 |      |  | $    | 23,920,000 |   |  | $ | 22,013,000 |  
|                                                                                             |  |      |           |      |  |      |            |   |  |   |            |  

See accompanying notes to consolidated financial statements.

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PRIMA ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 and 2000

|                                                          |  |           |         |            |  |          |            |               |  |          |             |       |  |             |          |   |  |   |            |   |  |   |             |  
|--------------------------------------------------------- |  | --------- | ------- | ---------- |  | -------- | ---------- | ------------- |  | -------- | ----------- | ----- |  | ----------- | -------- | - |  | - | ---------- | - |  | - | ----------- | -
|                                                          |  |           |         |            |  |          |            |               |  |          |             |       |  | Accumulated |          |   |  |   |            |   |  |  
|                                                          |  | Common    |         | Additional |  |          |            |               |  | Other    |             |       |  |             |          |   |  |  
|                                                          |  | Stock,    |         | Paid-In    |  | Retained |            | Comprehensive |  | Treasury |             |       |  |            
|                                                          |  | Par Value |         | Capital    |  | Earnings |            | Income (Loss) |  | Stock    |             | Total
|                                                          |  |           |         |            |  |          |            |               |  |          |             |      
|BALANCES, January 1, 2000                                 |  | $         | 198,000 |            |  | $        | 5,628,000  |               |  | $        | 56,577,000  |       |  | $           | (244,000 | ) |  | $ | (3,251,000 | ) |  | $ | 58,908,000  |  
|Net income                                                |  |           |         |            |  |          |            |               |  |          | 21,895,000  |       |  |             |          |   |  |   |            |   |  |   | 21,895,000  |  
|Exercise of stock options                                 |  |           | 1,000   |            |  |          | 591,000    |               |  |          |             |       |  |             |          |   |  |   |            |   |  |   | 592,000     |  
|Tax benefit from exercise of non-
qualified stock options |  |           |         |            |  |          | 720,000    |               |  |          |             |       |  |             |          |   |  |   |            |   |  |   | 720,000     |  
|Other comprehensive income                                |  |           |         |            |  |          |            |               |  |          |             |       |  |             | 118,000  |   |  |   |            |   |  |   | 118,000     |  
|Treasury stock purchased                                  |  |           |         |            |  |          |            |               |  |          |             |       |  |             |          |   |  |   | (1,935,000 | ) |  |   | (1,935,000  | )
|Treasury stock canceled                                   |  |           | (7,000  | )          |  |          | (5,179,000 | )             |  |          |             |       |  |             |          |   |  |   | 5,186,000  |   |  |   |            |  
|                                                          |  |           |         |            |  |          |            |               |  |          |             |       |  |             |          |   |  |   |            |   |  |   |             |  
|BALANCES, December 31, 2000                               |  |           | 192,000 |            |  |          | 1,760,000  |               |  |          | 78,472,000  |       |  |             | (126,000 | ) |  |   |           |   |  |   | 80,298,000  |  
|Net income                                                |  |           |         |            |  |          |            |               |  |          | 23,768,000  |       |  |             |          |   |  |   |            |   |  |   | 23,768,000  |  
|Exercise of stock options                                 |  |           | 1,000   |            |  |          | 525,000    |               |  |          |             |       |  |             |          |   |  |   |            |   |  |   | 526,000     |  
|Tax benefit from exercise of non-
qualified stock options |  |           |         |            |  |          | 732,000    |               |  |          |             |       |  |             |          |   |  |   |            |   |  |   | 732,000     |  
|Other comprehensive income                                |  |           |         |            |  |          |            |               |  |          |             |       |  |             | 152,000  |   |  |   |            |   |  |   | 152,000     |  
|Treasury stock purchased                                  |  |           |         |            |  |          |            |               |  |          |             |       |  |             |          |   |  |   | (3,866,000 | ) |  |   | (3,866,000  | )
|Other                                                     |  |           |         |            |  |          | 130,000    |               |  |          |             |       |  |             |          |   |  |   |            |   |  |   | 130,000     |  
|                                                          |  |           |         |            |  |          |            |               |  |          |             |       |  |             |          |   |  |   |            |   |  |   |             |  
|BALANCES, December 31, 2001                               |  |           | 193,000 |            |  |          | 3,147,000  |               |  |          | 102,240,000 |       |  |             | 26,000   |   |  |   | (3,866,000 | ) |  |   | 101,740,000 |  
|Net income                                                |  |           |         |            |  |          |            |               |  |          | 5,230,000   |       |  |             |          |   |  |   |            |   |  |   | 5,230,000   |  
|Exercise of stock options                                 |  |           | 3,000   |            |  |          | 853,000    |               |  |          |             |       |  |             |          |   |  |   |            |   |  |   | 856,000     |  
|Tax benefit from exercise of non-
qualified stock options |  |           |         |            |  |          | 1,250,000  |               |  |          |             |       |  |             |          |   |  |   |            |   |  |   | 1,250,000   |  
|Other comprehensive income (loss)                         |  |           |         |            |  |          |            |               |  |          |             |       |  |             | (141,000 | ) |  |   |            |   |  |   | (141,000    | )
|Treasury stock purchased                                  |  |           |         |            |  |          |            |               |  |          |             |       |  |             |          |   |  |   | (1,669,000 | ) |  |   | (1,669,000  | )
|                                                          |  |           |         |            |  |          |            |               |  |          |             |       |  |             |          |   |  |   |            |   |  |   |             |  
|BALANCES, December 31, 2002                               |  | $         | 196,000 |            |  | $        | 5,250,000  |               |  | $        | 107,470,000 |       |  | $           | (115,000 | ) |  | $ | (5,535,000 | ) |  | $ | 107,266,000 |  
|                                                          |  |           |         |            |  |          |            |               |  |          |             |       |  |             |          |   |  |   |            |   |  |   |             |  

See accompanying notes to consolidated financial statements.

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PRIMA ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 and 2000

|                                                                                 |                                              |                                           |             |            |            |      |             |            |             |   |             |           |             |  
|-------------------------------------------------------------------------------- | -------------------------------------------- | ----------------------------------------- | ----------- | ---------- | ---------- | ---- | ----------- | ---------- | ----------- | - | ----------- | --------- | ----------- | -
|                                                                                 |                                              |                                           |             | 2002       |            | 2001 |             | 2000      
|                                                                                 |                                              |                                           |             |            |            |      |             |           
|OPERATING ACTIVITIES                                                             |                                              |                                           |             |            |            |      |             |            |             |   |             |          
|Net income                                                                       |                                              | $                                         | 5,230,000   |            |            | $    | 23,768,000  |            |             | $ | 21,895,000  |          
|Adjustments to reconcile net income to net
cash provided by operating activities |                                              |                                           |             |            |            |      |             |            |             |   |             |          
|                                                                                 | Depreciation, depletion and amortization     |                                           |             | 11,001,000 |            |      |             | 10,559,000 |             |   |             | 7,204,000 |            
|                                                                                 | Deferred income taxes                        |                                           |             | (977,000   | )          |      |             | 9,123,000  |             |   |             | 7,319,000 |            
|                                                                                 | Unrealized derivative activities             |                                           |             | 4,464,000  |            |      |             | (4,378,000 | )           |   |             |          |            
|                                                                                 | Tax benefits from stock option plans         |                                           |             | 1,250,000  |            |      |             | 732,000    |             |   |             | 720,000   |            
|                                                                                 | Other                                        |                                           |             | 95,000     |            |      |             | (106,000   | )           |   |             | 25,000    |            
|                                                                                 | Changes in operating assets and liabilities: |                                           |             |            |            |      |             |            |             |   |             |           |            
|                                                                                 |                                              | Receivables                               |             |            | (1,698,000 | )    |             |            | 3,096,000   |   |             |           | (3,618,000  | )
|                                                                                 |                                              | Inventory                                 |             |            | 475,000    |      |             |            | (6,000      | ) |             |           | (572,000    | )
|                                                                                 |                                              | Other current assets                      |             |            | 89,000     |      |             |            | 241,000     |   |             |           | (129,000    | )
|                                                                                 |                                              | Accounts payable and payables to owners   |             |            | 2,743,000  |      |             |            | (2,130,000  | ) |             |           | 2,124,000   |  
|                                                                                 |                                              | Production taxes payable                  |             |            | (633,000   | )    |             |            | 1,504,000   |   |             |           | 2,344,000   |  
|                                                                                 |                                              | Accrued and other liabilities             |             |            | (515,000   | )    |             |            | 605,000     |   |             |           | (936,000    | )
|                                                                                 |                                              |                                           |             |            |            |      |             |            |             |   |             |          
|                                                                                 |                                              | Net cash provided by operating activities |             |            | 21,524,000 |      |             |            | 43,008,000  |   |             |           | 36,376,000  |  
|                                                                                 |                                              |                                           |             |            |            |      |             |            |             |   |             |          
|INVESTING ACTIVITIES                                                             |                                              |                                           |             |            |            |      |             |            |             |   |             |          
|Additions to oil and gas properties                                              |                                              |                                           | (22,252,000 | )          |            |      | (35,248,000 | )          |             |   | (31,952,000 | )        
|Proceeds from sales of oil and gas property                                      |                                              |                                           | 14,577,000  |            |            |      | 57,000      |            |             |   |            |          
|Purchases of other properties  net of proceeds                                  |                                              |                                           | (768,000    | )          |            |      | (1,746,000  | )          |             |   | (1,390,000  | )        
|Sales (purchases) of securities  net                                            |                                              |                                           | 658,000     |            |            |      | 41,000      |            |             |   | (192,000    | )        
|                                                                                 |                                              |                                           |             |            |            |      |             |            |             |   |             |          
|                                                                                 |                                              | Net cash used in investing activities     |             |            | (7,785,000 | )    |             |            | (36,896,000 | ) |             |           | (33,534,000 | )
|                                                                                 |                                              |                                           |             |            |            |      |             |            |             |   |             |          
|FINANCING ACTIVITIES                                                             |                                              |                                           |             |            |            |      |             |            |             |   |             |          
|Treasury stock purchased                                                         |                                              |                                           | (1,669,000  | )          |            |      | (3,866,000  | )          |             |   | (1,935,000  | )        
|Proceeds from exercise of stock options                                          |                                              |                                           | 856,000     |            |            |      | 526,000     |            |             |   | 592,000     |          
|Other                                                                            |                                              |                                           |            |            |            |      | 183,000     |            |             |   |            |          
|                                                                                 |                                              |                                           |             |            |            |      |             |            |             |   |             |          
|                                                                                 |                                              | Net cash used in financing activities     |             |            | (813,000   | )    |             |            | (3,157,000  | ) |             |           | (1,343,000  | )
|                                                                                 |                                              |                                           |             |            |            |      |             |            |             |   |             |          
|Increase in cash and cash equivalents                                            |                                              |                                           | 12,926,000  |            |            |      | 2,955,000   |            |             |   | 1,499,000   |          
|Cash and cash equivalents, beginning of year                                     |                                              |                                           | 23,337,000  |            |            |      | 20,382,000  |            |             |   | 18,883,000  |          
|                                                                                 |                                              |                                           |             |            |            |      |             |            |             |   |             |          
|CASH AND CASH EQUIVALENTS, end of year                                           |                                              | $                                         | 36,263,000  |            |            | $    | 23,337,000  |            |             | $ | 20,382,000  |          
|                                                                                 |                                              |                                           |             |            |            |      |             |            |             |   |             |          

See accompanying notes to consolidated financial statements.

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PRIMA ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 and 2000

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, 2002.

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.

Consolidated Statements of Cash Flows

Cash in excess of daily requirements is generally invested in money market
accounts and commercial paper 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 $1,187,000, $905,000 and $2,722,000 for the
years ended December 31, 2002, 2001 and 2000, respectively. No interest was
paid in 2002 or 2001. Cash paid for interest in 2000 was $15,000.

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.

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Commencing with its adoption of Statement of Financial Accounting
Standards 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, 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 undeveloped 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 losses during the three-year
period ended December 31, 2002.

The Company has not accrued costs for future site restoration,
dismantlement and abandonment costs related to proved oil and gas properties
because management has estimated that such costs will be fully offset by the
salvage value of equipment sold upon abandonment of these properties. Such
estimates have been based upon the Companys historical experience and review
of its current properties and restoration obligations. In accordance with
Statement of Financial Accounting Standards (SFAS) No. 143, discussed below,
Prima will begin to accrue asset retirement costs, without offset for projected
equipment salvage values, effective January 1, 2003.

Property and Equipment

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. Long-lived assets, other than oil and gas
properties, 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 losses during the
three-year period ended December 31, 2002.

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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. The imbalance position was not
significant at the end of 2002 or 2001.

Oilfield Services and Operator Fees

Fees earned from providing oilfield services and operating wells for third
parties are recorded when the services are performed. Oilfield services fees
are recognized as income. Operating fees are recorded as a reduction of general
and administrative expenses.

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 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 tax benefits are also
recognized for tax credits that are available to offset future federal income
taxes. Deferred income taxes are determined by applying currently enacted tax
rates.

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 derivative
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 CIG 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 CIG 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.

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Stock-Based Compensation

At December 31, 2002, Prima had stock-based compensation plans in effect,
which are more fully described in Note 8. 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.

The following assumptions were utilized to estimate the fair values of
options granted during the three years ended December 31, 2002, using the
Black-Scholes Valuation Model:

|                                    |  |      |     |      |  |      |     |   |  |  |     |  
|----------------------------------- |  | ---- | --- | ---- |  | ---- | --- | - |  |  | --- | -
|                                    |  | 2002 |     | 2001 |  | 2000
|                                    |  |      |     |      |  |     
|Expected dividend yield             |  |      | 0   | %    |  |      | 0   | % |  |  | 0   | %
|Expected price volatility           |  |      | 41  | %    |  |      | 43  | % |  |  | 76  | %
|Risk free interest rate             |  |      | 2.9 | %    |  |      | 5.1 | % |  |  | 6.1 | %
|Expected life of options (in years) |  |      | 6   |      |  |      | 6   |   |  |  | 9   |  

Based on the above, the estimated weighted average fair values of employee
stock options granted during 2002 and 2001 were $11.52 and $16.04,
respectively. No employee stock options were granted in 2000. The weighted
average fair values of non-employee directors options granted during 2002,
2001 and 2000 were $9.04, $12.49 and $20.47, respectively. Additional awards in
future years are anticipated.

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 effect on net income and earnings per share if
the Company had applied the fair value recognition provisions of SFAS No. 123.

|                             |             |  |      |           |      |  |      |            |  |  |   |            | 
|---------------------------- | ----------- |  | ---- | --------- | ---- |  | ---- | ---------- |  |  | - | ---------- | 
|                             |             |  | 2002 |           | 2001 |  | 2000
|                             |             |  |      |           |      |  |     
|Net Income                   |             |  |      |           |      |  |      |            |  |  |   |           
|                             | As reported |  | $    | 5,230,000 |      |  | $    | 23,768,000 |  |  | $ | 21,895,000 | 
|                             | Pro forma   |  | $    | 4,342,000 |      |  | $    | 23,359,000 |  |  | $ | 21,585,000 | 
|Basic net income per share   |             |  |      |           |      |  |      |            |  |  |   |           
|                             | As reported |  | $    | 0.41      |      |  | $    | 1.87       |  |  | $ | 1.72       | 
|                             | Pro forma   |  | $    | 0.34      |      |  | $    | 1.83       |  |  | $ | 1.69       | 
|Diluted net income per share |             |  |      |           |      |  |      |            |  |  |   |           
|                             | As reported |  | $    | 0.40      |      |  | $    | 1.80       |  |  | $ | 1.65       | 
|                             | Pro forma   |  | $    | 0.33      |      |  | $    | 1.77       |  |  | $ | 1.62       | 

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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 8, 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 the 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 July 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligations. This statement requires companies to recognize the
fair value of an asset retirement liability in the financial statements by
capitalizing that cost as part of the cost of the related long-lived asset. The
asset retirement liability should then be allocated to expense by using a
systematic and rational method. The statement is effective January 1, 2003. The
Company has not determined the impact of adoption of this statement.

In April 2002 the FASB issued SFAS No. 145, Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections. This Statement rescinds SFAS No. 4, Reporting Gains and Losses
from Extinguishment of Debt, and an amendment of that Statement, SFAS No. 64,
Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements. This
Statement also rescinds SFAS No. 44, Accounting for Intangible Assets of
Motor Carriers. This Statement amends SFAS No. 13, Accounting for Leases,
to eliminate an inconsistency between the required accounting for
sale-leaseback transactions and the required accounting for certain lease
modifications that have economic effects that are similar to sale-leaseback
transactions. This Statement also amends other existing authoritative
pronouncements to make various technical corrections, clarify meanings, or
describe their applicability under changed conditions. The provisions of this
Statement shall be applied in fiscal years beginning after May 15, 2002. The
adoption of SFAS No. 145 is not expected to have a material effect on the
Companys financial position or results of operations.

In July 2002, the FASB issued SFAS No. 146, Accounting for Costs
Associated With Exit or Disposal Activities, which provides guidance for
financial accounting and reporting of costs associated with exit or disposal
activities and nullifies EITF Issue No. 94-3, Liability Recognition for
Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring). This statement requires
the recognition of a liability for a cost associated with an exit or disposal
activity when the liability is incurred, as opposed to when the entity commits
to an exit plan under EITF No. 94-3. The statement is effective for the Company
in 2003. The adoption of SFAS No. 146 is not expected to have a material effect
on the Companys financial position or results of operations.

In December 2002, the FASB issued SFAS No. 148, Accounting for
Stock-Based Compensation  Transition and Disclosure  an amendment of FASB
Statement No. 123. SFAS No. 148 amends SFAS No. 123, Accounting for
Stock-Based Compensation to provide alternative methods of transition for a
voluntary change to the fair value based method of accounting for stock-based
employee compensation. In addition, SFAS No. 148 amends the disclosure
requirements of SFAS No. 123 to require prominent disclosures in both annual
and interim financial statements about the method of accounting for stock-based
employee compensation and the effect of the method used on reported results.
SFAS No. 148 is effective for financial statements for fiscal years ending
after December 15, 2002. The Company currently intends to continue to account
for stock-based compensation using the methods detailed in the stock-based
compensation accounting policy and to provide disclosures as prescribed by SFAS
148.

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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, 2002 and 2001, the Company sold securities with a market value of $929,000
and $166,000, which resulted in realized gains and losses of $66,000 and
$(1,000), respectively. The Company also determined that there was an
other-than-temporary decline in the fair market value of an individual security
in its portfolio. Consequently, an impairment loss of $91,000 was recognized
in 2002. Other net unrealized losses on securities are included in accumulated
other comprehensive income, net of deferred income taxes of $(16,000) and
$(20,000), respectively, at December 31, 2002 and 2001. The changes in net
unrealized losses on securities for the years ended December 31, 2002 and 2001
were as follows:

|                                         |  |      |         |      |  |   |          |  
|---------------------------------------- |  | ---- | ------- | ---- |  | - | -------- | -
|                                         |  | 2002 |         | 2001
|                                         |  |      |         |     
|Net unrealized (loss), beginning of year |  | $    | (53,000 | )    |  | $ | (201,000 | )
|Net unrealized (loss), end of year       |  |      | (44,000 | )    |  |   | (53,000  | )
|                                         |  |      |         |      |  |   |          |  
|Net change in unrealized loss            |  | $    | 9,000   |      |  | $ | 148,000  |  
|                                         |  |      |         |      |  |   |          |  

The components of fair value as of December 31, 2002 and 2001 were as follows:

|                                          |  |      |           |      |  |   |           |  
|----------------------------------------- |  | ---- | --------- | ---- |  | - | --------- | -
|                                          |  | 2002 |           | 2001
|                                          |  |      |           |     
|Cost (including reinvested distributions) |  | $    | 1,788,000 |      |  | $ | 2,471,000 |  
|Gross unrealized gains                    |  |      | 46,000    |      |  |   | 88,000    |  
|Gross unrealized losses                   |  |      | (90,000   | )    |  |   | (141,000  | )
|                                          |  |      |           |      |  |   |           |  
|Fair value                                |  | $    | 1,744,000 |      |  | $ | 2,418,000 |  
|                                          |  |      |           |      |  |   |           |  

3. 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) |  | Amount   
|                              |                              |  |             |            |               |  |          
|Year Ended December 31, 2002: |                              |  |             |            |               |  |           |            |  |  |   |     
|                              | Basic Net Income per Share   |  | $           | 5,230,000  |               |  |           | 12,770,716 |  |  | $ | 0.41 | 
|                              |                              |  |             |            |               |  |           |            |  |  |   |      | 
|                              | Effect of Stock Options      |  |             |           |               |  |           | 450,660    |  |  |   |      | 
|                              |                              |  |             |            |               |  |           |            |  |  |   |      | 
|                              | Diluted Net Income per Share |  | $           | 5,230,000  |               |  |           | 13,221,376 |  |  | $ | 0.40 | 
|                              |                              |  |             |            |               |  |           |            |  |  |   |      | 
|Year Ended December 31, 2001: |                              |  |             |            |               |  |           |            |  |  |   |     
|                              | Basic Net Income per Share   |  | $           | 23,768,000 |               |  |           | 12,731,181 |  |  | $ | 1.87 | 
|                              |                              |  |             |            |               |  |           |            |  |  |   |      | 
|                              | Effect of Stock Options      |  |             |           |               |  |           | 487,970    |  |  |   |      | 
|                              |                              |  |             |            |               |  |           |            |  |  |   |      | 
|                              | Diluted Net Income per Share |  | $           | 23,768,000 |               |  |           | 13,219,151 |  |  | $ | 1.80 | 
|                              |                              |  |             |            |               |  |           |            |  |  |   |      | 
|Year Ended December 31, 2000: |                              |  |             |            |               |  |           |            |  |  |   |     
|                              | Basic Net Income per Share   |  | $           | 21,895,000 |               |  |           | 12,748,917 |  |  | $ | 1.72 | 
|                              |                              |  |             |            |               |  |           |            |  |  |   |      | 
|                              | Effect of Stock Options      |  |             |           |               |  |           | 544,006    |  |  |   |      | 
|                              |                              |  |             |            |               |  |           |            |  |  |   |      | 
|                              | Diluted Net Income per Share |  | $           | 21,895,000 |               |  |           | 13,292,923 |  |  | $ | 1.65 | 
|                              |                              |  |             |            |               |  |           |            |  |  |   |      | 

The Board of Directors of Prima approved two separate three-for-two stock
splits of the Company common stock during 2000. All share and per-share
amounts included in these financial statements have been restated to show the
retroactive effects of the stock splits.

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During 2000, Prima purchased 108,150 shares of its common stock for its
treasury for $1,935,000. The Board of Directors authorized the retirement of
431,199 shares of common stock held in the treasury as of December 31, 2000.
These shares were returned to an authorized but unissued status. In January
2001, the Board approved a repurchase program of up to 5% of the Companys
common stock then outstanding, or approximately 640,000 shares. In 2001, the
Company purchased 155,351 treasury shares for $3,866,000. In 2002, the Company
purchased 81,187 treasury shares for $1,669,000. The combined total of 236,538
shares repurchased to date represents approximately 1.8% of the shares then
outstanding, or 37% of the shares authorized for repurchase under the program.
As of December 31, 2002, approximately 403,000 shares remained subject to
repurchase under this authorization. Through March 18, 2003, Prima had
repurchased an additional 29,700 treasury shares at an average cost of $18.74
per share.

During 2000, the stockholders of Prima approved an increase in the number
of authorized shares of common stock from 12,000,000 to 18,000,000 shares.
During 2001, the stockholders approved an additional increase to 35,000,000
authorized shares.

4. DERIVATIVES CONTRACTS

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. 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 qualify for hedge accounting,
while others are non-qualifying. Derivative instruments that did not qualify
for hedge accounting were principally 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
in 2002, 2001 and 2000:

|                                                                                                      |  |      |            |      |  |      |           |  |  |   |        | 
|----------------------------------------------------------------------------------------------------- |  | ---- | ---------- | ---- |  | ---- | --------- |  |  | - | ------ | 
|                                                                                                      |  | 2002 |            | 2001 |  | 2000
|                                                                                                      |  |      |            |      |  |     
|Realized gains (losses) on derivatives qualifying for
hedge accounting, included in oil and gas sales |  | $    | (458,000   | )    |  | $    | 3,381,000 |  |  | $ | 42,000 | 
|Realized gains on non-qualifying hedges                                                               |  |      | 1,546,000  |      |  |      | 2,057,000 |  |  |   |       | 
|Unrealized gains (losses) on non-qualifying hedges                                                    |  |      | (4,464,000 | )    |  |      | 4,378,000 |  |  |   |       | 
|                                                                                                      |  |      |            |      |  |      |           |  |  |   |        | 
|Aggregate amounts reported on consolidated
statements of income                                       |  | $    | (3,376,000 | )    |  | $    | 9,816,000 |  |  | $ | 42,000 | 
|                                                                                                      |  |      |            |      |  |      |           |  |  |   |        | 

On December 31, 2002, Primas open hedge positions, all of which related
to the first quarter of 2003, consisted of 200,000 MMBtu of natural gas sold
forward at an average NYMEX price of $3.3155 per MMBtu. The unrealized
mark-to-market losses for these derivative positions, aggregating $225,000 at
that date, were included in current liabilities as of December 31, 2002. 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.

In addition, $139,000 of realized losses on closed derivatives positions
that qualified for hedge accounting were included in other comprehensive income
in 2002 and will be included as a reduction of oil and gas sales in 2003, as
the related production months occur.

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5. INCOME TAXES

The provision for income taxes consists of the following components:

|                           |         |   |           |           |      |   |            |           |   |   |           |           | 
|-------------------------- | ------- | - | --------- | --------- | ---- | - | ---------- | --------- | - | - | --------- | --------- | 
|                           |         |   | 2002      |           | 2001 |   | 2000      
|                           |         |   |           |           |      |   |           
|Current:                   |         |   |           |           |      |   |            |           |   |   |           |          
|                           | Federal |   | $         | 1,636,000 |      |   | $          | 2,067,000 |   |   | $         | 2,114,000 | 
|                           | State   |   |           | 166,000   |      |   |            | (275,000  | ) |   |           | 102,000   | 
|                           |         |   |           |           |      |   |            |           |   |   |           |           | 
|                           |         |   | 1,802,000 |           |      |   | 1,792,000  |           |   |   | 2,216,000 |          
|                           |         |   |           |           |      |   |            |           |   |   |           |           | 
|Deferred:                  |         |   |           |           |      |   |            |           |   |   |           |          
|                           | Federal |   |           | (429,000  | )    |   |            | 8,732,000 |   |   |           | 6,656,000 | 
|                           | State   |   |           | (35,000   | )    |   |            | 782,000   |   |   |           | 382,000   | 
|                           |         |   |           |           |      |   |            |           |   |   |           |           | 
|                           |         |   | (464,000  | )         |      |   | 9,514,000  |           |   |   | 7,038,000 |          
|                           |         |   |           |           |      |   |            |           |   |   |           |           | 
|Tax credits                |         |   | (513,000  | )         |      |   | (391,000   | )         |   |   | 281,000   |          
|                           |         |   |           |           |      |   |            |           |   |   |           |           | 
|Provision for income taxes |         | $ | 825,000   |           |      | $ | 10,915,000 |           |   | $ | 9,535,000 |          
|                           |         |   |           |           |      |   |            |           |   |   |           |           | 

During 2002, 2001 and 2000, the Company recognized income tax deductions
of $3,375,000, $1,979,000 and $1,946,000, respectively, from the exercise of
nonqualified stock options. Stockholders equity has been credited in the
amount of $1,250,000, $732,000 and $720,000 for the income tax benefit of these
deductions. The provision for income taxes in 2001 included $265,000 of
current expense that was netted in the cumulative effect of change in
accounting method. During 2001, Prima recognized taxable income of $207,000
from short-swing profits. Stockholders equity has been reduced in the amount
of $77,000 for the current income tax expense associated with this income.

The significant components of deferred tax assets and liabilities included
in the balance sheet are as follows:

|                             |                                  |   |            |            |      |   |            |            | 
|---------------------------- | -------------------------------- | - | ---------- | ---------- | ---- | - | ---------- | ---------- | 
|                             |                                  |   | 2002       |            | 2001
|                             |                                  |   |            |            |     
|Deferred Tax Assets:         |                                  |   |            |            |      |   |            |           
|                             | Minimum tax credit carryforwards |   | $          | 2,241,000  |      |   | $          | 1,727,000  | 
|                             | State income taxes               |   |            | 648,000    |      |   |            | 663,000    | 
|                             | Accrued bonuses                  |   |            | 201,000    |      |   |            |           | 
|                             | Derivatives                      |   |            | 83,000     |      |   |            |           | 
|                             | Other                            |   |            | 109,000    |      |   |            | 68,000     | 
|                             |                                  |   |            |            |      |   |            |            | 
|                             | Total Deferred Tax Assets        |   |            | 3,282,000  |      |   |            | 2,458,000  | 
|                             |                                  |   |            |            |      |   |            |            | 
|Deferred Tax Liabilities:    |                                  |   |            |            |      |   |            |           
|                             | Intangible drilling costs        |   |            | 22,666,000 |      |   |            | 21,259,000 | 
|                             | Derivatives                      |   |            |           |      |   |            | 1,655,000  | 
|                             | Depreciation                     |   |            | 742,000    |      |   |            | 641,000    | 
|                             | Land held for investment         |   |            | 370,000    |      |   |            | 370,000    | 
|                             | Other                            |   |            | 589,000    |      |   |            | 677,000    | 
|                             |                                  |   |            |            |      |   |            |            | 
|                             | Total Deferred Tax Liabilities   |   |            | 24,367,000 |      |   |            | 24,602,000 | 
|                             |                                  |   |            |            |      |   |            |            | 
|Net Deferred Tax Liabilities |                                  | $ | 21,085,000 |            |      | $ | 22,144,000 |           
|                             |                                  |   |            |            |      |   |            |            | 

A reconciliation of income tax computed at the federal statutory tax rate to
the Companys effective tax rate is as follows:

|                                     |                    |  |       |      |      |  |      |      |   |  |      |      |  
|------------------------------------ | ------------------ |  | ----- | ---- | ---- |  | ---- | ---- | - |  | ---- | ---- | -
|                                     |                    |  | 2002  |      | 2001 |  | 2000
|                                     |                    |  |       |      |      |  |     
|Federal statutory income tax rate    |                    |  | 34.0  | %    |      |  | 34.0 | %    |   |  | 34.0 | %   
|Percentage depletion                 |                    |  | (6.3  | )    |      |  | (1.2 | )    |   |  | (1.5 | )   
|Section 29 credits                   |                    |  | (15.8 | )    |      |  | (3.0 | )    |   |  | (3.1 | )   
|State taxes, net of federal benefits |                    |  | 1.5   |      |      |  | 1.0  |      |   |  | 1.0  |     
|Other                                |                    |  | 0.3   |      |      |  | 0.7  |      |   |  | (0.1 | )   
|                                     |                    |  |       |      |      |  |      |      |   |  |      |     
|                                     | Effective tax rate |  |       | 13.7 | %    |  |      | 31.5 | % |  |      | 30.3 | %
|                                     |                    |  |       |      |      |  |      |      |   |  |      |     

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At December 31, 2002, Prima had minimum tax credit carryforwards of
approximately $2,241,000, which may be carried forward indefinitely.

6. 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,
2002, 2001 and 2000. 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.

|                                                 |                                          |                          |                                          |            |             |            |             |             |             |            |            |            |             |            | 
|------------------------------------------------ | ---------------------------------------- | ------------------------ | ---------------------------------------- | ---------- | ----------- | ---------- | ----------- | ----------- | ----------- | ---------- | ---------- | ---------- | ----------- | ---------- | 
|                                                 |                                          |                          |                                          |            | 2002        |            | 2001        |             | 2000       
|                                                 |                                          |                          |                                          |            |             |            |             |             |            
|Revenues                                         |                                          |                          |                                          |            |             |            |             |             |             |            |            |           
|                                                 | Oil & gas (including derivative effects) |                          | $                                        | 22,867,000 |             |            | $           | 50,983,000  |             |            | $          | 44,437,000 |            
|                                                 | Oilfield services                        |                          |                                          | 10,325,000 |             |            |             | 12,207,000  |             |            |            | 9,912,000  |            
|                                                 |                                          |                          |                                          |            |             |            |             |             |             |            |            |            |            
|                                                 |                                          |                          | 33,192,000                               |            |             |            | 63,190,000  |             |             |            | 54,349,000 |           
|                                                 | Corporate                                |                          |                                          | 597,000    |             |            |             | 1,214,000   |             |            |            | 1,464,000  |            
|                                                 | Intersegment eliminations                |                          |                                          | (1,999,000 | )           |            |             | (4,117,000  | )           |            |            | (3,634,000 | )          
|                                                 |                                          |                          |                                          |            |             |            |             |             |             |            |            |            |            
|                                                 |                                          |                          | Per financial statements                 |            | $           | 31,790,000 |             |             | $           | 60,287,000 |            |            | $           | 52,179,000 | 
|                                                 |                                          |                          |                                          |            |             |            |             |             |             |            |            |            |            
|                                                 | Operating Earnings                       |                          |                                          |            |             |            |             |             |             |            |            |            |            
|                                                 |                                          |                          | Oil & gas (including derivative effects) |            | $           | 7,965,000  |             |             | $           | 34,913,000 |            |            | $           | 32,243,000 | 
|                                                 |                                          |                          | Oilfield services                        |            |             | 1,094,000  |             |             |             | 2,083,000  |            |            |             | 844,000    | 
|                                                 |                                          |                          |                                          |            |             |            |             |             |             |            |            |            |            
|                                                 |                                          |                          | 9,059,000                                |            |             |            | 36,996,000  |             |             |            | 33,087,000 |           
|                                                 | Corporate                                |                          |                                          | (2,906,000 | )           |            |             | (2,624,000  | )           |            |            | (1,657,000 | )          
|                                                 | Intersegment eliminations                |                          |                                          | (98,000    | )           |            |             | (565,000    | )           |            |            |           |            
|                                                 |                                          |                          |                                          |            |             |            |             |             |             |            |            |            |            
|                                                 | Per financial statements                 |                          | $                                        | 6,055,000  |             |            | $           | 33,807,000  |             |            | $          | 31,430,000 |            
|                                                 |                                          |                          |                                          |            |             |            |             |             |             |            |            |            |            
|Identifiable Assets                              |                                          |                          |                                          |            |             |            |             |             |             |            |            |           
|                                                 | Oil & gas                                |                          | $                                        | 95,300,000 |             |            | $           | 100,200,000 |             |            | $          | 72,747,000 |            
|                                                 | Oilfield services                        |                          |                                          | 6,322,000  |             |            |             | 7,218,000   |             |            |            | 6,044,000  |            
|                                                 |                                          |                          |                                          |            |             |            |             |             |             |            |            |            |            
|                                                 |                                          |                          | 101,622,000                              |            |             |            | 107,418,000 |             |             |            | 78,791,000 |           
|                                                 | Corporate                                |                          |                                          | 40,305,000 |             |            |             | 28,026,000  |             |            |            | 26,109,000 |            
|                                                 |                                          |                          |                                          |            |             |            |             |             |             |            |            |            |            
|                                                 |                                          | Per financial statements |                                          | $          | 141,927,000 |            |             | $           | 135,444,000 |            |            | $          | 104,900,000 |           
|                                                 |                                          |                          |                                          |            |             |            |             |             |             |            |            |            |            
|Depreciation, Depletion and Amortization Expense |                                          |                          |                                          |            |             |            |             |             |             |            |            |           
|                                                 | Oil & gas                                |                          | $                                        | 9,710,000  |             |            | $           | 9,190,000   |             |            | $          | 6,150,000  |            
|                                                 | Oilfield services                        |                          |                                          | 1,035,000  |             |            |             | 1,097,000   |             |            |            | 850,000    |            
|                                                 |                                          |                          |                                          |            |             |            |             |             |             |            |            |            |            
|                                                 |                                          |                          | 10,745,000                               |            |             |            | 10,287,000  |             |             |            | 7,000,000  |           
|                                                 | Corporate                                |                          |                                          | 256,000    |             |            |             | 272,000     |             |            |            | 204,000    |            
|                                                 |                                          |                          |                                          |            |             |            |             |             |             |            |            |            |            
|                                                 |                                          | Per financial statements |                                          | $          | 11,001,000  |            |             | $           | 10,559,000  |            |            | $          | 7,204,000   |           
|                                                 |                                          |                          |                                          |            |             |            |             |             |             |            |            |            |            
|Capital Expenditures                             |                                          |                          |                                          |            |             |            |             |             |             |            |            |           
|                                                 | Oil & gas                                |                          | $                                        | 22,252,000 |             |            | $           | 35,248,000  |             |            | $          | 31,952,000 |            
|                                                 | Oilfield services                        |                          |                                          | 868,000    |             |            |             | 1,539,000   |             |            |            | 1,235,000  |            
|                                                 |                                          |                          |                                          |            |             |            |             |             |             |            |            |            |            
|                                                 |                                          |                          | 23,120,000                               |            |             |            | 36,787,000  |             |             |            | 33,187,000 |           
|                                                 | Corporate                                |                          |                                          | 274,000    |             |            |             | 419,000     |             |            |            | 378,000    |            
|                                                 |                                          |                          |                                          |            |             |            |             |             |             |            |            |            |            
|                                                 |                                          | Per financial statements |                                          | $          | 23,394,000  |            |             | $           | 37,206,000  |            |            | $          | 33,565,000  |           
|                                                 |                                          |                          |                                          |            |             |            |             |             |             |            |            |            |            

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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 are 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 either of these customers could have a material adverse
effect on Prima, the Company believes it would be able to locate other
customers for the purchase of its production.

|                                |  |      |    |      |  |      |    |   |  |  |    |  
|------------------------------- |  | ---- | -- | ---- |  | ---- | -- | - |  |  | -- | -
|                                |  | 2002 |    | 2001 |  | 2000
|                                |  |      |    |      |  |     
|Duke Energy Field Services, Inc |  |      | 33 | %    |  |      | 31 | % |  |  | 36 | %
|Valero Energy                   |  |      | 29 |      |  |      | 16 |   |  |  | 21 |  

7. COMMITMENTS AND CONTINGENCIES

Prima entered into a seven-year office space lease effective December 1,
2000. Office lease expense totaled $295,000, $282,000 and $187,000 for the
years ended December 31, 2002, 2001 and 2000, respectively. The Company also
entered into a twelve-month lease for compressor rental effective November 25,
2002. Future minimum annual rentals under these non-cancelable operating
leases for the remainder of their terms are as follows:

|                              |  |   |           | 
|----------------------------- |  | - | --------- | 
|Year ending December 31, 2003 |  | $ | 356,000   | 
|Year ending December 31, 2004 |  |   | 317,000   | 
|Year ending December 31, 2005 |  |   | 317,000   | 
|Year ending December 31, 2006 |  |   | 317,000   | 
|Year ending December 31, 2007 |  |   | 290,000   | 
|                              |  |   |           | 
|                              |  | $ | 1,597,000 | 
|                              |  |   |           | 

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.

8. 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. Options granted to date under the plan
vest ratably over three to five years, and expire ten years from the date of
grant. At December 31, 2002, options to acquire 926,325 shares of the
Companys common stock were outstanding. The exercise prices, which equaled the
market prices of the stock on the dates of grant, range from $3.93 to $33.25
per share, with a weighted average price of $13.30 per share. As of December
31, 2002, the
weighted average remaining contractual life of the options
outstanding is 5 years, 1 month. A summary of options granted, exercised and
outstanding during the three years ended December 31, 2002 is as follows:

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|                                 |  |           |           |                  |  |   |       | 
|-------------------------------- |  | --------- | --------- | ---------------- |  | - | ----- | 
|                                 |  | Number    |           | Weighted Average
|                                 |  | of Shares |           | Exercise Prices 
|                                 |  |           |           |                 
|Balance at December 31, 1999     |  |           | 1,004,625 |                  |  | $ | 5.50  | 
|Granted during 2000              |  |           |          |                  |  |   |      | 
|Exercised in 2000                |  |           | (92,650   | )                |  |   | 5.62  | 
|Forfeited in 2000                |  |           |          |                  |  |   |      | 
|                                 |  |           |           |                  |  |   |       | 
|Outstanding at December 31, 2000 |  |           | 911,975   |                  |  |   | 5.49  | 
|Granted during 2001              |  |           | 216,000   |                  |  |   | 32.53 | 
|Exercised in 2001                |  |           | (86,425   | )                |  |   | 5.01  | 
|Forfeited in 2001                |  |           | (3,600    | )                |  |   | 9.39  | 
|                                 |  |           |           |                  |  |   |       | 
|Outstanding at December 31, 2001 |  |           | 1,037,950 |                  |  |   | 11.14 | 
|Granted during 2002              |  |           | 171,500   |                  |  |   | 25.36 | 
|Exercised in 2002                |  |           | (174,125  | )                |  |   | 4.79  | 
|Forfeited in 2002                |  |           | (109,000  | )                |  |   | 25.91 | 
|                                 |  |           |           |                  |  |   |       | 
|Outstanding at December 31, 2002 |  |           | 926,325   |                  |  |   | 13.20 | 
|                                 |  |           |           |                  |  |   |       | 
|Exercisable at December 31, 2000 |  |           | 654,125   |                  |  |   | 4.70  | 
|Exercisable at December 31, 2001 |  |           | 648,625   |                  |  |   | 5.01  | 
|Exercisable at December 31, 2002 |  |           | 601,092   |                  |  |   | 7.37  | 

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. At December 31, 2002, options to acquire 157,500 shares of the Companys
common stock were outstanding under the plan, at exercise prices ranging from
$6.67 to $32.33 per share. As of December 31, 2002, the weighted average
remaining contractual life of the options outstanding is 7 years, 4 months. A
summary of options granted, exercised and outstanding during the three years
ended December 31, 2002 is as follows:

|                                 |  |           |         |                  |  |   |       | 
|-------------------------------- |  | --------- | ------- | ---------------- |  | - | ----- | 
|                                 |  | Number    |         | Weighted Average
|                                 |  | of Shares |         | Exercise Prices 
|                                 |  |           |         |                 
|Balance at December 31, 1999     |  |           | 112,500 |                  |  | $ | 7.30  | 
|Granted during 2000              |  |           | 61,875  |                  |  |   | 25.36 | 
|Exercised during 2000            |  |           | (4,500  | )                |  |   | 6.67  | 
|Forfeited during 2000            |  |           | (23,625 | )                |  |   | 7.42  | 
|                                 |  |           |         |                  |  |   |       | 
|Outstanding at December 31, 2000 |  |           | 146,250 |                  |  |   | 14.94 | 
|Granted during 2001              |  |           | 22,500  |                  |  |   | 25.49 | 
|Exercised during 2001            |  |           | (10,125 | )                |  |   | 7.02  | 
|Forfeited during 2001            |  |           | (23,625 | )                |  |   | 10.86 | 
|                                 |  |           |         |                  |  |   |       | 
|Outstanding at December 31, 2001 |  |           | 135,000 |                  |  |   | 17.86 | 
|Granted during 2002              |  |           | 22,500  |                  |  |   | 20.52 | 
|Exercised during 2002            |  |           |        |                  |  |   |      | 
|Forfeited during 2002            |  |           |        |                  |  |   |      | 
|                                 |  |           |         |                  |  |   |       | 
|Outstanding at December 31, 2002 |  |           | 157,500 |                  |  |   | 18.37 | 
|                                 |  |           |         |                  |  |   |       | 
|Exercisable at December 31, 2000 |  |           | 30,375  |                  |  |   | 7.02  | 
|Exercisable at December 31, 2001 |  |           | 42,750  |                  |  |   | 12.02 | 
|Exercisable at December 31, 2002 |  |           | 69,750  |                  |  |   | 14.34 | 

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Summary of Outstanding Options

The following table summarizes information about stock options outstanding
at December 31, 2002 on a combined basis for the employee and non-employee
directors plans:

|                |               |                |                           |                   |                           |                |           |                |        |                |           |             |  |  |  |                |  |  |   |            | 
|--------------- | ------------- | -------------- | ------------------------- | ----------------- | ------------------------- | -------------- | --------- | -------------- | ------ | -------------- | --------- | ----------- |  |  |  | -------------- |  |  | - | ---------- | 
|                |               |                | Stock Options Outstanding |                   | Stock Options Exercisable
|                |               |                |                           |                   |                          
|                |               |                |                           |                   |                           |                | Weighted- |                |        |                |           |             |  |  |  |                |  |  |  
|                |               |                | Number                    |                   | Average                   |                | Weighted- |                | Number |                | Weighted-
|Range of        |               | Outstanding at |                           | Remaining         |                           | Average        |           | Exercisable at |        | Average       
|Exercise Prices |               | 12/31/02       |                           | Contractual Life  |                           | Exercise Price |           | 12/31/02       |        | Exercise Price
|                |               |                |                           |                   |                           |                |           |                |        |               
|$               | 3.93  4.41   |                |                           | 343,625           |                           |                |           | 1.6            |        |                | $         | 4.19        |  |  |  | 343,625        |  |  | $ | 4.19       | 
|                | 6.67  9.83   |                |                           | 360,450           |                           |                |           | 5.8            |        |                |           | 7.19        |  |  |  | 256,950        |  |  |   | 7.02       | 
|                | 16.18  20.78 |                |                           | 16,875            |                           |                |           | 9.7            |        |                |           | 19.25       |  |  |  |               |  |  |   |           | 
|                | 21.75  26.38 |                |                           | 139,000           |                           |                |           | 8.6            |        |                |           | 24.78       |  |  |  | 21,375         |  |  |   | 22.94      | 
|                | 29.90  33.25 |                |                           | 223,875
1,083,825 |                           |                |           | 8.2
4.5        |        |                |           | 32.45
13.90 |  |  |  | 48,892
670,842 |  |  |   | 32.07
7.91 | 

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, 2002, 2001 and 2000, Prima expensed $339,000,
$316,000 and $283,000, respectively, for its contributions to the ESOP.

9. 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

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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 and capital appreciation. The partnership owns the 22 acres free
and clear. One of the general partners of the partnership is a company
controlled by a brother of the Companys president. The Company participated
on the same basis as the other limited partners. The disinterested members of
the Companys Board of Directors approved the transaction. The carrying value
of this investment at December 31, 2002 and 2001 was $257,000. During the
three years ended December 31, 2002, the Company did not make any capital
contributions to the partnership, nor did it receive any distributions
therefrom.

10. 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 Stones Throw area. 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 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.

11. 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:

|                                                |                     |   |            |            |      |   |            |            |  |   |            |            | 
|----------------------------------------------- | ------------------- | - | ---------- | ---------- | ---- | - | ---------- | ---------- |  | - | ---------- | ---------- | 
|                                                |                     |   | 2002       |            | 2001 |   | 2000      
|                                                |                     |   |            |            |      |   |           
|Acquisition costs:                              |                     |   |            |            |      |   |            |            |  |   |            |           
|                                                | Unproved properties |   | $          | 876,000    |      |   | $          | 2,114,000  |  |   | $          | 1,741,000  | 
|                                                | Proved properties   |   |            | 534,000    |      |   |            | 400,000    |  |   |            | 237,000    | 
|Exploration costs                               |                     |   | 5,685,000  |            |      |   | 1,620,000  |            |  |   | 642,000    |           
|Development costs                               |                     |   | 15,157,000 |            |      |   | 31,114,000 |            |  |   | 29,332,000 |           
|                                                |                     |   |            |            |      |   |            |            |  |   |            |            | 
|                                                | Total               |   | $          | 22,252,000 |      |   | $          | 35,248,000 |  |   | $          | 31,952,000 | 
|                                                |                     |   |            |            |      |   |            |            |  |   |            |            | 
|Depletion cost per equivalent
Mcf of production |                     | $ | 0.92       |            |      | $ | 0.77       |            |  | $ | 0.54       |           

Costs Not Being Amortized Oil and gas property costs not being
amortized at December 31, 2002 consisted of $20,570,000 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.

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Results of Operations Results of operations for oil and gas producing
activities were as follows:

|                                             |                                               |   |            |            |      |   |            |            |  |   |            |            | 
|-------------------------------------------- | --------------------------------------------- | - | ---------- | ---------- | ---- | - | ---------- | ---------- |  | - | ---------- | ---------- | 
|                                             |                                               |   | 2002       |            | 2001 |   | 2000      
|                                             |                                               |   |            |            |      |   |           
|Revenues                                     |                                               |   |            |            |      |   |            |            |  |   |            |           
|                                             | Oil and gas sales                             |   | $          | 25,785,000 |      |   | $          | 44,548,000 |  |   | $          | 44,437,000 | 
|                                             | Gains (losses) on derivative instruments, net |   |            | (2,918,000 | )    |   |            | 6,435,000  |  |   |            |           | 
|                                             |                                               |   |            |            |      |   |            |            |  |   |            |           
|                                             |                                               |   | 22,867,000 |            |      |   | 50,983,000 |            |  |   | 44,437,000 |           
|                                             |                                               |   |            |            |      |   |            |            |  |   |            |           
|Expenses                                     |                                               |   |            |            |      |   |            |            |  |   |            |           
|                                             | Depletion of oil and gas properties           |   |            | 9,710,000  |      |   |            | 9,190,000  |  |   |            | 6,150,000  | 
|                                             | Lease operating expense                       |   |            | 3,076,000  |      |   |            | 3,295,000  |  |   |            | 2,623,000  | 
|                                             | Ad valorem and production taxes               |   |            | 2,116,000  |      |   |            | 3,344,000  |  |   |            | 3,421,000  | 
|                                             | Impairment of natural gas swap                |   |            |           |      |   |            | 241,000    |  |   |            |           | 
|                                             |                                               |   |            |            |      |   |            |            |  |   |            |           
|                                             |                                               |   | 14,902,000 |            |      |   | 16,070,000 |            |  |   | 12,194,000 |           
|                                             |                                               |   |            |            |      |   |            |            |  |   |            |           
|Income before income taxes                   |                                               |   | 7,965,000  |            |      |   | 34,913,000 |            |  |   | 32,243,000 |           
|Income tax expense                           |                                               |   | 1,083,000  |            |      |   | 10,998,000 |            |  |   | 9,770,000  |           
|                                             |                                               |   |            |            |      |   |            |            |  |   |            |           
|Income from oil and gas producing activities |                                               | $ | 6,882,000  |            |      | $ | 23,915,000 |            |  | $ | 22,473,000 |           
|                                             |                                               |   |            |            |      |   |            |            |  |   |            |           

Supplemental Oil and Gas Reserve Information (Unaudited)

The reserve information presented below is based on estimates of net
proved reserves as of December 31, 2002 and 2001 that were prepared by the
Companys engineers and audited by Netherland, Sewell and Associates, Inc.,
independent petroleum engineers, and estimates at the end of 2000 that were
prepared or audited in part by Netherland, Sewell and Associates, Inc. and in
part by Ryder Scott Company, 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 must 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.

65



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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:

|                 |                                                |  |         |       |        |  |         |         |        |  |         |       |        |  |  |         |   |  |  |       |   |  |  |         |  
|---------------- | ---------------------------------------------- |  | ------- | ----- | ------ |  | ------- | ------- | ------ |  | ------- | ----- | ------ |  |  | ------- | - |  |  | ----- | - |  |  | ------- | -
|                 |                                                |  | 2002    |       | 2001   |  | 2000   
|                 |                                                |  |         |       |        |  |        
|                 |                                                |  | Oil     |       | Gas    |  | Oil     |         | Gas    |  | Oil     |       | Gas   
|                 |                                                |  | (MBBLS) |       | (MMCF) |  | (MBBLS) |         | (MMCF) |  | (MBBLS) |       | (MMCF)
|                 |                                                |  |         |       |        |  |         |         |        |  |         |       |       
|Proved reserves: |                                                |  |         |       |        |  |         |         |        |  |         |       |        |  |  |         |   |  |  |       |   |  |  |        
|                 | Beginning of year                              |  |         | 3,394 |        |  |         | 115,222 |        |  |         | 3,729 |        |  |  | 154,172 |   |  |  | 3,268 |   |  |  | 124,111 |  
|                 | Purchases of oil and
gas reserves in place     |  |         | 5     |        |  |         | 899     |        |  |         |      |        |  |  | 2,388   |   |  |  | 1     |   |  |  | 5       |  
|                 | Net exchanges of oil and gas
reserves in place |  |         |      |        |  |         | (331    | )      |  |         | 10    |        |  |  | (2,051  | ) |  |  | 14    |   |  |  | 125     |  
|                 | Revisions of previous
estimates                |  |         | 188   |        |  |         | (17,744 | )      |  |         | (611  | )      |  |  | (44,495 | ) |  |  | (259  | ) |  |  | (5,969  | )
|                 | Extensions, discoveries
and other additions    |  |         | 730   |        |  |         | 5,665   |        |  |         | 697   |        |  |  | 14,485  |   |  |  | 1,145 |   |  |  | 44,583  |  
|                 | Production                                     |  |         | (373  | )      |  |         | (8,343  | )      |  |         | (431  | )      |  |  | (9,277  | ) |  |  | (440  | ) |  |  | (8,683  | )
|                 | Sales of oil and gas
reserves in place         |  |         |      |        |  |         | (7,928  | )      |  |         |      |        |  |  |        |   |  |  |      |   |  |  |        |  
|                 |                                                |  |         |       |        |  |         |         |        |  |         |       |        |  |  |         |   |  |  |       |   |  |  |         |  
|                 | End of year                                    |  |         | 3,944 |        |  |         | 87,440  |        |  |         | 3,394 |        |  |  | 115,222 |   |  |  | 3,729 |   |  |  | 154,172 |  
|                 |                                                |  |         |       |        |  |         |         |        |  |         |       |        |  |  |         |   |  |  |       |   |  |  |         |  
|                 | Proved developed reserves:                     |  |         |       |        |  |         |         |        |  |         |       |        |  |  |         |   |  |  |       |   |  |  |         |  
|                 | Beginning of year                              |  |         | 2,949 |        |  |         | 69,168  |        |  |         | 2,945 |        |  |  | 77,385  |   |  |  | 2,521 |   |  |  | 54,079  |  
|                 | End of year                                    |  |         | 3,115 |        |  |         | 66,245  |        |  |         | 2,949 |        |  |  | 69,168  |   |  |  | 2,945 |   |  |  | 77,385  |  

Year-End Oil and Gas Prices Primas average net realizable oil and
natural gas prices at each year end, which were used in calculating reserve
estimates, were as follows:

|                      |  |      |       |      |  |      |       |  |  |   |       | 
|--------------------- |  | ---- | ----- | ---- |  | ---- | ----- |  |  | - | ----- | 
|                      |  | 2002 |       | 2001 |  | 2000
|                      |  |      |       |      |  |     
|Natural gas (per Mcf) |  | $    | 2.64  |      |  | $    | 1.94  |  |  | $ | 7.51  | 
|Oil (per barrel)      |  |      | 31.30 |      |  |      | 19.71 |  |  |   | 26.48 | 

Standardized Measure The following table presents the standardized
measure of discounted future net cash flows related to proved oil and gas
reserves.

|                                                         |  |      |             |      |  |      |             |   |  |   |               |  
|-------------------------------------------------------- |  | ---- | ----------- | ---- |  | ---- | ----------- | - |  | - | ------------- | -
|                                                         |  | 2002 |             | 2001 |  | 2000
|                                                         |  |      |             |      |  |     
|Future cash inflows                                      |  | $    | 354,617,000 |      |  | $    | 290,303,000 |   |  | $ | 1,256,037,000 |  
|Future production costs                                  |  |      | (93,357,000 | )    |  |      | (90,816,000 | ) |  |   | (218,269,000  | )
|Future development costs                                 |  |      | (39,484,000 | )    |  |      | (42,863,000 | ) |  |   | (61,828,000   | )
|                                                         |  |      |             |      |  |      |             |   |  |   |               |  
|Future net cash flows                                    |  |      | 221,776,000 |      |  |      | 156,624,000 |   |  |   | 975,940,000   |  
|10% discount factor                                      |  |      | (92,933,000 | )    |  |      | (64,719,000 | ) |  |   | (399,888,000  | )
|Discounted future income taxes                           |  |      | (37,564,000 | )    |  |      | (25,104,000 | ) |  |   | (204,931,000  | )
|                                                         |  |      |             |      |  |      |             |   |  |   |               |  
|Standardized measure of discounted future net cash
flows |  | $    | 91,279,000  |      |  | $    | 66,801,000  |   |  | $ | 371,121,000   |  
|                                                         |  |      |             |      |  |      |             |   |  |   |               |  

66



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A summary of changes in the standardized measure of discounted future net
cash flows is as follows:

|                                                                            |  |      |             |      |  |      |              |   |  |   |              |  
|--------------------------------------------------------------------------- |  | ---- | ----------- | ---- |  | ---- | ------------ | - |  | - | ------------ | -
|                                                                            |  | 2002 |             | 2001 |  | 2000
|                                                                            |  |      |             |      |  |     
|Standardized measure of discounted future net
cash flows, beginning of year |  | $    | 66,801,000  |      |  | $    | 371,121,000  |   |  | $ | 75,466,000   |  
|Sales of oil and gas, net of production costs and
taxes                     |  |      | (21,136,000 | )    |  |      | (34,057,000  | ) |  |   | (38,392,000  | )
|Net changes in prices and production costs                                  |  |      | 42,497,000  |      |  |      | (469,638,000 | ) |  |   | 358,936,000  |  
|Extensions, discoveries, and improved recovery,
less related costs          |  |      | 9,728,000   |      |  |      | 8,680,000    |   |  |   | 169,062,000  |  
|Development costs incurred during the year                                  |  |      | 7,518,000   |      |  |      | 19,920,000   |   |  |   | 12,128,000   |  
|Changes
in estimated future development costs                               |  |      | (3,313,000  | )    |  |      | 11,381,000   |   |  |   | 922,000      |  
|Revisions of previous quantity estimates                                    |  |      | (5,089,000  | )    |  |      | (46,997,000  | ) |  |   | (29,713,000  | )
|Purchases of reserves in place                                              |  |      | 640,000     |      |  |      | 1,088,000    |   |  |   | 349,000      |  
|Net exchanges of reserves in place                                          |  |      | (403,000    | )    |  |      | (7,429,000   | ) |  |   | 3,409,000    |  
|Sales of reserves in place                                                  |  |      | (4,056,000  | )    |  |      |             |   |  |   |             |  
|Other                                                                       |  |      | 1,360,000   |      |  |      | (4,207,000   | ) |  |   | (16,747,000  | )
|Accretion of discount                                                       |  |      | 9,191,000   |      |  |      | 37,112,000   |   |  |   | 7,547,000    |  
|Net changes in future income taxes                                          |  |      | (12,459,000 | )    |  |      | 179,827,000  |   |  |   | (171,846,000 | )
|                                                                            |  |      |             |      |  |      |              |   |  |   |              |  
|Standardized measure of discounted future net
cash flows, end of year       |  | $    | 91,279,000  |      |  | $    | 66,801,000   |   |  | $ | 371,121,000  |  
|                                                                            |  |      |             |      |  |      |              |   |  |   |              |  

12. QUARTERLY FINANCIAL DATA (UNAUDITED)

The following is a summary of the unaudited financial data for each
quarter for the years ended December 31, 2002 and 2001.

|                                |  |                    |            |         |  |         |           |         |  |   |           |  |  |   |            |  
|------------------------------- |  | ------------------ | ---------- | ------- |  | ------- | --------- | ------- |  | - | --------- |  |  | - | ---------- | -
|                                |  | Three Months Ended
|                                |  |                   
|                                |  | 12/31/02           |            | 9/30/02 |  | 6/30/02 |           | 3/31/02
|                                |  |                    |            |         |  |         |           |        
|Year Ended December 31, 2002    |  |                    |            |         |  |         |           |         |  |   |           |  |  |   |            |  
|Revenues                        |  | $                  | 10,233,000 |         |  | $       | 7,432,000 |         |  | $ | 8,718,000 |  |  | $ | 5,407,000  |  
|Gross profit(1)                 |  |                    | 7,444,000  |         |  |         | 4,485,000 |         |  |   | 5,520,000 |  |  |   | 2,265,000  |  
|Income 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      | )

|                                                                                 |  |                    |            |         |  |         |            |         |  |   |            |  |  |   |            | 
|-------------------------------------------------------------------------------- |  | ------------------ | ---------- | ------- |  | ------- | ---------- | ------- |  | - | ---------- |  |  | - | ---------- | 
|                                                                                 |  | Three Months Ended
|                                                                                 |  |                   
|                                                                                 |  | 12/31/01           |            | 9/30/01 |  | 6/30/01 |            | 3/31/01
|                                                                                 |  |                    |            |         |  |         |            |        
|Year Ended December 31, 2001                                                     |  |                    |            |         |  |         |            |         |  |   |            |  |  |   |            | 
|Revenues                                                                         |  | $                  | 10,454,000 |         |  | $       | 17,175,000 |         |  | $ | 14,188,000 |  |  | $ | 18,470,000 | 
|Gross profit(1)                                                                  |  |                    | 6,858,000  |         |  |         | 14,061,000 |         |  |   | 11,016,000 |  |  |   | 14,776,000 | 
|Income before income tax and
cumulative effect of change in
accounting principle |  |                    | 3,369,000  |         |  |         | 10,242,000 |         |  |   | 8,221,000  |  |  |   | 11,975,000 | 
|Net income                                                                       |  |                    | 2,354,000  |         |  |         | 7,067,000  |         |  |   | 5,671,000  |  |  |   | 8,676,000  | 
|Basic net income per share(2)                                                    |  |                    | 0.18       |         |  |         | 0.56       |         |  |   | 0.45       |  |  |   | 0.68       | 
|Diluted net income per share(2)                                                  |  |                    | 0.18       |         |  |         | 0.54       |         |  |   | 0.43       |  |  |   | 0.65       | 



---

|(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.                                          

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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 27th day of March, 2003.

| |  |                          |  |                            
| |  | ------------------------ |  | ---------------------------
| |  | PRIMA ENERGY CORPORATION
| |  |                          |  |                            
| |  | By:                      |  | /s/ Richard H. Lewis       
| |  |                          |  |                            
| |  |                          |  | Richard 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. LewisRichard H. Lewis       |  | Chairman of the Board
and President
(Principal Executive Officer)                        |  | March 27, 2003
|                                          
|/s/ Neil L. StenbuckNeil L. Stenbuck       |  | Executive Vice President - Finance,
Treasurer and Director
(Principal Financial Officer) |  | March 27, 2003
|                                          
|/s/ Sandra J. IrlandoSandra J. Irlando     |  | Vice President - Accounting
(Principal Accounting Officer)                               |  | March 27, 2003
|                                          
|/s/ James R. CummingsJames R. Cummings     |  | Director                                                                                 |  | March 27, 2003
|                                          
|/s/ Douglas J. GuionDouglas J. Guion       |  | Director                                                                                 |  | March 27, 2003
|                                          
|/s/ Catherine J. PagliaCatherine J. Paglia |  | Director                                                                                 |  | March 27, 2003
|                                          
|/s/ George L. SewardGeorge L. Seward       |  | Director                                                                                 |  | March 27, 2003

68



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CERTIFICATIONS

I, Richard H. Lewis, certify that:

1.     I have reviewed this annual report on Form 10-K of Prima Energy Corporation;

2.     Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3.     Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
Registrant as of, and for, the periods presented in this annual report;

4.     The Registrants other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the Registrant and we have:

a) designed such disclosure controls and procedures to ensure that material
information relating to the Registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the Registrants disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the Evaluation Date); and

c) presented in this annual report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;

5.     The Registrants other certifying officers and I have disclosed, based on
our most recent evaluation, to the Registrants auditors and the audit
committee of Registrants board of directors (or persons performing the
equivalent function):

a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the Registrants ability to record, process,
summarize and report financial data and have identified for the Registrants
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the Registrants internal controls;
and

6.     The Registrants other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

|                     |  |     |  |                                                        
|-------------------- |  | --- |  | -------------------------------------------------------
|Date: March 27, 2003 |  |     |  |                                                        
|                     |  |     |  |                                                        
|                     |  | By: |  | /s/ Richard H. Lewis                                   
|                     |  |     |  |                                                        
|                     |  |     |  | Richard H. Lewis,
President and Chief Executive Officer

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I, Neil L. Stenbuck, certify that:

1.     I have reviewed this annual report on Form 10-K of Prima Energy Corporation;

2.     Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3.     Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
Registrant as of, and for, the periods presented in this annual report;

4.     The Registrants other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the Registrant and we have:

a) designed such disclosure controls and procedures to ensure that material
information relating to the Registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the Registrants disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the Evaluation Date); and

c) presented in this annual report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;

5.     The Registrants other certifying officers and I have disclosed, based on
our most recent evaluation, to the Registrants auditors and the audit
committee of Registrants board of directors (or persons performing the
equivalent function):

a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the Registrants ability to record, process,
summarize and report financial data and have identified for the Registrants
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the Registrants internal controls;
and

6.     The Registrants other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

|                     |  |     |  |                                                                       
|-------------------- |  | --- |  | ----------------------------------------------------------------------
|Date: March 27, 2003 |  |     |  |                                                                       
|                     |  |     |  |                                                                       
|                     |  | By: |  | /s/ Neil L. Stenbuck                                                  
|                     |  |     |  |                                                                       
|                     |  |     |  | Neil L. Stenbuck,
Executive Vice President and Chief Financial Officer

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INDEX TO EXHIBITS

|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|No.     |  | Document                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|3.1     |  | 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, as Exhibit A, the Form of Right Certificate, as
Exhibit B, 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.)
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|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.)                                                                                                                                                                                                                                                                                                                                 
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|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,
2000. (Incorporated by reference to Annual Report on Form 10-K for
Prima Energy Corporation for the year ended December 31, 2000.)                                                                                                                                                                                                                                                
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|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 the quarter ended March 31, 2002.)                                                                                                                                                                                                                                                                                                             
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|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.)                                                                                                                                                                                                                                                                                                                             
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|21      |  | Subsidiaries of the Registrant                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
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|23.1    |  | Consent of Independent Auditors                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
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|23.2    |  | Consent of Independent Reservoir Engineers