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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:

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.

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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:

   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

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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.

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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.

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:

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.

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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: