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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

Commission file number 0-9408

PRIMA ENERGY CORPORATION

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 Act
None

Securities registered pursuant to Section 12(g) of the Act
Common 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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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.

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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.

Productive Wells

The following table summarizes our total gross and net productive wells, as of December 31, 2002.

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Additionally, we own royalty interests in 52 gross wells that are not included in the above table.

   Developed and Undeveloped Acreage

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