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 9,221,894 shares of voting stock held by non-affiliates of the Registrant, based upon the closing price of the common stock on June 30, 2003 of $20.82 per share as reported on the Nasdaq National Market, was $191,999,833. Shares of common stock held by each officer and director and by each person who owns 10% or more of the outstanding common stock have been excluded in that such persons may be deemed affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

As of February 27, 2004, Registrant had outstanding 12,964,142 shares of Common Stock, $0.015 Par Value, its only class of voting stock.

Document Incorporated by Reference

Parts of the following document are incorporated by reference to Items 10, 11, 12, 13 and 14 of Part III of the Form 10-K Report: Definitive Proxy Statement for the Registrant’s 2004 Annual Meeting of Stockholders.

TABLE OF CONTENTS

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PART I

ITEMS 1 and 2. BUSINESS and PROPERTIES

References in this report to “Prima,” “the Company,” “we,” “us” or “our” are intended to refer to Prima Energy Corporation and its consolidated subsidiaries. This report contains numerous “forward-looking statements” that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. These include, without limitation, statements relating to future drilling and completion of wells, well operations, production, prices, costs and expenses, cash flow, investments, utilization of oilfield service equipment, reserve estimates (including estimates for future net revenues associated with such reserves and the present value of such future net revenues), business strategies, and other plans and objectives of Prima management for future operations and activities and other such matters. The words, “believes,” “plans,” “intends,” “estimates,” “projects,” “expects,” “anticipates,” “strategy,” “budgeted” and similar expressions, identify forward-looking statements.

Prima does not undertake to update, revise or correct any of the forward-looking information. Readers are cautioned that such forward-looking statements should be read in conjunction with Prima’s disclosures under the heading: “Cautionary Statement for the Purposes of the ‘Safe Harbor’ Provisions of the Private Securities Litigation Reform Act of 1995” beginning on page 21 of this report.

General — The Company

Prima was incorporated in April 1980 to engage in crude oil and natural gas related exploration, acquisition, development, production, and related business activities. In October 1980, Prima became publicly owned with a $3.6 million common stock offering. Our subsequent activities have primarily been related to oil and gas production operations, but have also included oil and gas property management, oilfield services, and, at times, natural gas gathering, marketing and trading. The substantial majority of Prima’s consolidated assets and revenues continue to be related to its oil and gas production operations.

Our principal activities are currently organized into two active operating segments. The larger of these consists of the acquisition, exploration, development and operation of oil and gas properties. The second segment is comprised of oilfield service operations conducted for unaffiliated third parties and for Prima. Though at times in the past we have also been involved in oil and gas marketing and trading, and in gas gathering and compression operations, these activities were not significant during the three years ended December 31, 2003. See Note 7 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report for financial information pertaining to these industry segments.

Our oil and gas exploration, development and production operations are generally conducted within Prima Oil & Gas Company, a wholly owned subsidiary. We conduct most other activities within wholly owned subsidiaries of Prima Oil & Gas Company, including Action Oil Field Services, Inc. and Action Energy Services for oilfield services.

We have conducted our activities principally in the Rocky Mountain region of the United States. At the end of 2003, Prima owned or controlled mineral leasehold interests in over 510,000 gross, or 390,000 net, acres, predominately in the Denver-Julesburg (“D-J”) Basin of Colorado, the Powder River, Wind River, Big Horn and Green River Basins of Wyoming, and within the Wasatch Plateau and Overthrust Belt in Utah.

Historically, we have grown our proven oil and gas reserves and production primarily through acquiring oil and gas leaseholds and drilling wells to exploit and develop tight sand and coalbed methane (“CBM”) properties. Generally, the probability that such properties have hydrocarbons in place is estimated to be relatively high and the viability of establishing proved reserves is largely dependent on several factors, including: the market price for oil and gas; the costs of development, production and marketing; and determination of the amount of recoverable reserves and the rate at which such reserves can be extracted. To a lesser extent, we have added proved reserves through exploration activities and acquisition of properties with proved developed reserves. At the end of 2003, over 90% of our proved oil and gas reserves and production were associated with tight sand properties in the D-J Basin in eastern Colorado and CBM properties in the Powder River Basin in eastern Wyoming. The balance of our proved reserves and production at the end of 2003 related to properties in the Wind River Basin in central Wyoming and non-CBM wells in the Powder River Basin.

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We have identified more than 2,800 potential exploitation and development opportunities on our D-J Basin and Powder River Basin CBM-prospective acreage, of which 485 were assigned proved oil and gas reserves at year-end 2003. Most of the identified non-proved opportunities represent potential CBM drilling locations in the Powder River Basin, with the remainder comprised primarily of recompletion and refracturing projects and other drilling locations in the D-J Basin. This set of identified opportunities includes only those projects that we believe have the potential to be economically viable using future oil and gas prices reflected in commodity futures markets at the end of 2003. We have also developed an inventory of exploratory prospects in other areas, including the Green River Basin in western Wyoming, the Overthrust Belt in northeast Utah and the Uintah Basin in eastern Utah which could, if successfully tested, establish new areas for future exploitation and development activities.

Our oilfield service operations are presently conducted in two areas where Prima has an established base of exploitation and production operations. These are the D-J Basin and the CBM play in the Powder River Basin. Action Oilfield Services, which operates in the D-J Basin, owns various well servicing equipment including eight workover rigs, a swab rig, tractor trailer rigs for water hauling, and oilfield rental equipment, such as pumps, tanks and blowout preventers. Action Energy Services, which operates in the Powder River Basin, owns nine CBM drilling and service rigs. Our service companies provide services to both Prima and other operators, and during 2003 operations provided to unrelated parties generated approximately 12% of Prima’s total consolidated revenues. While these operations have typically generated positive earnings and cash flow, and have also enabled us to exert more control over costs and the quality of work performed for some of our well operations, they have not historically constituted a significant portion of Prima’s assets or operations.

The following is a brief summary of selected key financial and operating data reported by Prima at December 31, 2003:

•		$177,217,000 of assets.
•		$56,148,000 of net working capital (with $57,192,000 of cash and marketable securities).
•		No long-term debt.
•		Estimated net proved reserves of 125,796,000 Mcf of natural gas equivalents (“Mcfe”), with a pre-tax net present value using a 10% discount factor (“PV10”) of $239,800,000, based on constant year-end average price realizations of $4.95 per Mcf of natural gas and $32.88 per barrel of oil. The related after-tax standardized measure of discounted future net cash flows was $158,979,000.
•		Lease holdings of approximately 473,000 gross (360,000 net) undeveloped acres and 37,000 gross (30,000 net) developed acres.
•		Operations of 708 productive wells (91% of the productive wells in which we own a working interest).

For the year ended December 31, 2003, we reported the following:

•		Net income of $23,795,000.
•		Net cash provided by operating activities of $46,149,000.
•		Average daily net production of 35,658 Mcf of natural gas and 1,099 barrels of crude oil (42,252 Mcfe).
•		Average price realizations of $3.53 per Mcf of natural gas and $31.71 per barrel of crude oil.

Strategy

Objectives. We seek to create shareholder value by identifying, evaluating and capturing opportunities related to the oil and gas industry. Most of our investment activities have been, and are projected to be, associated with our exploration and production operations, including the acquisition, exploration, development, and exploitation of properties, and

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production of oil and gas. We have also invested and conducted operations in oilfield services, gas gathering and processing, and in oil and gas marketing and trading, and we intend to continue seeking such opportunities in the future. One of Prima’s goals is to be among the lowest-cost full-cycle producers of oil and gas, and to realize among the highest cash flow margins for reinvestment, in the industry. Through our related activities in other segments of the energy business, we seek to complement and reinforce the achievement of goals in our exploration and production operations, and to enhance total returns to shareholders.

Acreage. We seek to acquire oil and gas leaseholds in prospective areas at reasonable costs and with attractive terms. We can potentially benefit from the activities of other operators in these areas as well as from our own activities.

Operations. We generally prefer to operate oil and gas properties in which we own significant economic interests. As operator, we are in a better position to control the costs, timing, quality and safety of work performed, and other factors that can affect the profitability of a property. In some instances, however, we may prefer to retain non-operating interests in properties where another operator has achieved economies of scale or has other operating advantages.

Exploitation. We intend to continue property exploitation activities in our principal operating areas. In the D-J Basin, we plan to continue well refracturing, recompletions and development drilling, to the extent warranted by ongoing results and market conditions. We also plan to continue exploitation activities targeting CBM in the Powder River Basin and conventional reservoirs in the Wind River Basin, depending upon the merits of each activity and subject to regulatory considerations. We generally assess these activities as low-to-moderate risk endeavors that can be undertaken whenever market conditions are projected to be adequate for projects to meet our investment criteria, provided we are able to obtain necessary approvals from regulatory authorities.

Exploration. We generally seek to allocate 5% to 20% of our capital expenditures budget toward higher-risk exploration activities. These activities may include leasehold acquisitions, geologic and geophysical evaluation, and drilling test wells on prospects. Our exploratory prospects can be either internally generated or result from acquiring interests in other operators’ prospects. The objective of our exploration activities is to expose a portion of our capital to higher-risk projects that we believe have the potential to deliver high rates of return if successful. As compared to individual exploitation opportunities, a successful exploration project could have a more significant impact on Prima’s value but the likelihood of success is considerably lower.

Gathering, Marketing and Trading. We elect to market our own natural gas and crude oil production whenever we believe that we can enhance our net price realizations by doing so. At times, Prima may also own assets downstream of the wellhead, including, but not limited to, gathering and compression facilities. We invest in such downstream assets where we believe opportunities exist to enhance Prima’s overall project economics by capturing an additional portion of the value chain from the wellhead to the burner tip. We may also gather, compress and market third-party gas, if we expect that project rates of return will be attractive.

Oilfield Services. We believe that we can, at times, achieve better control of the timing, quality and cost of work performed on our wells by owning and operating well servicing equipment. We also intend for these activities to constitute a separate business segment and profit center through providing such services to other operators.

Mergers, Acquisitions and Divestitures. We regularly review merger, acquisition and divestiture opportunities related to the oil and gas industry that could complement or enhance Prima’s existing businesses. We intend to pursue, and if possible consummate, such transactions when we believe that they would improve the risk-adjusted returns realized by Prima’s shareholders over the long term.

Derivatives. We periodically use commodity futures contracts to mitigate the impact of the volatility of oil and gas prices on a portion of our production and gas marketing activities. Our use of such derivatives is also intended to improve our average oil and gas price realizations over time, to enhance profitability, though such outcome cannot be assured. We may also elect at times to enter into derivatives contracts for volumes that exceed our projected total production, or which increase, rather than decrease, our exposure to a decline in oil and gas prices or expansion of basis differentials. We would consider establishing such positions if our analyses lead us to believe that prices are likely to move in a manner

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that would generate gains from the positions. Derivative positions for volumes greater than our expected production, or which would increase our exposure to a decline in oil and gas prices or expansion of basis differentials, would be speculative and would be limited in size to an amount that, in management’s judgment would not be material to our balance sheet taken as a whole, but they might have a significant positive or negative impact on reported net earnings.

Oil and Gas Properties and Operations

Major Properties

Denver-Julesburg Basin

This basin has been under extensive development since the 1970’s and has been substantially drilled. However, continued development has been supported by improvements in fracturing (or “frac”) technology to enhance oil and gas recoveries from tight sand reservoirs and by higher oil and gas prices. Because of the additional drilling and well stimulations encouraged by these factors, the D-J Basin continues to be under very active development and basin-wide production is near all-time peak levels.

Our activities in the D-J Basin have been conducted primarily in the Wattenberg Area, which encompasses more than 1,000 square miles, between 20 and 55 miles northeast of Denver, Colorado. We have conducted operations in the D-J basin for more than 20 years, and at the end of 2003 we owned working interests in 455 wells in the area, 436 of which we operated. Our drilling and production activities to date in the D-J Basin have been centered in a portion of the Wattenberg Field where the primary productive reservoirs are found in the Codell and Niobrara formations, which blanket large areas of the field at depths of approximately 7,000 to 7,300 feet. These formations have moderate porosity and low permeability, and require fracture stimulation to establish economic production. Recoverable reserves from any individual wellbore are largely dependent on reservoir quality, sand thickness, and fracture stimulation techniques.

Our D-J Basin wells produce both natural gas and crude oil. Prima’s natural gas production in this area averages approximately 1,240 Btu per Mcf at the wellhead. Natural gas liquids (propane, butane, ethane, isobutane, and pentane) are extracted from the well stream and sold separately by third-party gatherer/purchasers but their value is reflected in our wellhead price for natural gas. Our average gas price realizations per Mcf in this area have ordinarily slightly exceeded Rocky Mountain spot prices due to the high Btu content of the gas, but this relationship varies with market conditions and is dependent, in part, on the price levels of natural gas liquids. In 2003, our gas price realizations for D-J Basin production averaged $4.13 per Mcf, compared to the Colorado Interstate Gas (“CIG”) index average of $4.04 per MMBtu. Our crude oil in this area is sweet and generally commands a price comparable to oil traded on the New York Mercantile Exchange (“NYMEX”).

Prima’s leasehold position in the D-J Basin at the end of 2003 included 19,110 gross (16,570 net) developed acres, and an additional 12,000 gross (11,000 net) undeveloped acres. Our estimated proved reserves in the D-J Basin at that date were approximately 53,753,000 Mcf of natural gas and 4,892,000 barrels of oil, or 83,105,000 Mcfe, representing 66% of our total estimated proved reserve quantities. During 2003, Prima’s net production from D-J Basin properties averaged approximately 14,700 Mcf of gas and 1,065 barrels of oil, or 21,100 Mcfe, per day, accounting for 50% of our total oil and gas production and 59% of our oil and gas sales revenues (excluding hedging effects). Our net production from D-J Basin wells was less than 1% lower in 2003 than in 2002, reflecting roughly offsetting effects of natural depletion and new activities.

Codell/Niobrara wells that we recently drilled and completed in this area have generally cost approximately $285,000 and targeted approximately 200,000 to 250,000 Mcfe of gross recoverable reserves per well (excluding refracs, discussed below). At year-end 2003, we controlled approximately 200 potential drill sites in the D-J Basin, with 90 of these attributed proved undeveloped reserves. These proved locations have projected rates of return above 35% using futures prices reflected on forward markets on December 31, 2003. During 2003, we drilled 28 gross (27.0 net) wells in the D-J Basin, all of which were successfully completed and placed on production.

Advancements in refracturing (“refrac”) stimulation technology have enabled us to add deliverability and reserves from the Codell and Niobrara formations. A refrac is a procedure in which a formation in an older well that has been

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previously fractured at least once is stimulated by another fracture treatment. We generally target older wells with declining deliverability for restimulation. Prima performed 38 refracs in Wattenberg during 2003, with such activities primarily focused on the Codell formation. These had an average cost of approximately $120,000 and are projected to deliver rates of return in excess of 100% based on actual cash flows through year-end, projected incremental production and futures prices reflected on forward markets on December 31, 2003. At the end of 2003, we had 136 proven D-J Basin refrac projects reflected in our reserve report. During the fourth quarter of 2003, we conducted two well operations to fracture-stimulate the Codell formation for a third time, referred to as a tri-frac. Based on encouraging short-term performance results, we believe that tri-frac operations may provide future opportunities to add reserves and production on many of our existing D-J Basin wells, but none of these are included in estimated proved reserves at the end of 2003.

We plan to continue our development and exploitation activities in the D-J Basin, and are currently budgeting for capital investments in the area aggregating approximately $14 million in 2004. Planned activities include drilling approximately 35 new Codell/Niobrara wells and refracing, tri-fracing or recompleting approximately 50 wells in the Codell and/or the Niobrara formation. Our plans are subject to revision, however, based on economic conditions, performance results, activities conducted in other areas, and other factors. New wells, refracs and recompletion operations in the D-J Basin are characterized by flush production at relatively high rates for a few months, after which relatively shallow decline rates are established at lower production levels. Therefore, we may accelerate these operations when oil and gas prices are high or defer them when prices are low, to enhance the impact on investment returns from the flush production.

Powder River Basin Coalbed Methane

At December 31, 2003, we controlled leaseholds covering approximately 110,000 gross (97,000 net) acres in the Powder River Basin CBM play and had established proved gas reserves totaling approximately 34,965,000 Mcf on a small portion of this acreage. These CBM reserves represented 28% of Prima’s total estimated proved oil and gas reserve quantities at the end of 2003. Our net gas production from this area increased from an average of approximately 4,300 Mcf per day in 2002 to 17,700 Mcf per day in 2003, due to performance of our Porcupine-Tuit property where wells placed on-line in 2002 produced for a full year and additional wells were drilled and brought on-line. In 2003, the Powder River Basin CBM area accounted for 42% of our total oil and gas production and 32% of our oil and gas sales revenues (excluding hedging effects). Based on current market conditions and excluding the potential impact of exploratory discoveries or proved property acquisitions, we expect that our future activities in the Powder River Basin CBM area will account for significant portions of our capital expenditures, proved reserve additions and new sources of production during the next several years. There is no certainty, however, that future activities will generate the results that we currently project.

As of December 31, 2003, we had drilled 418 wells and acquired five wells in the Powder River Basin CBM play. At that date, 105 of these were connected to sales lines (including 99 that were producing gas), 153 were waiting on connection to gathering systems (of which 16 were already on pump, in the process of being de-watered), and the remaining wells were sold (most in 2002). We anticipate that approximately 130 of the 153 wells awaiting connection to gathering systems will be connected during the second half of 2004 and will begin gas production after sufficient de-watering has occurred. The remaining wells awaiting hook-up will be connected to a gathering system once wider-scale development occurs in the areas where these wells are located. Based on engineering estimates prepared as of the end of 2003, our reserve report for this CBM area included 254 proved undeveloped locations and identified over 2,350 additional non-proved prospective drill sites on our leaseholds, subject to economic viability that will be dependent upon projected regional gas prices, estimated development and operating costs, future drilling results from activities by Prima and other operators, and other factors. Prima is majority (often 100%) owner and operator of all of the Powder River Basin CBM properties where it owns a working interest.

The CBM play in the Powder River Basin is prospective over a vast geographic area encompassing approximately three million acres in northeastern Wyoming and southeastern Montana. Industry drilling activity to date has primarily been focused in Wyoming, where most of the acreage and thicker coal seams lie. According to the Wyoming Oil & Gas Commission, over 16,000 Powder River Basin CBM wells have been drilled in the state through the end of 2003 and

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approximately 12,000 of these wells were producing an aggregate of approximately 950 MMcf of natural gas per day during December 2003. At times during the past five years, this has been the most active drilling play in the United States. Although activity levels moderated in 2002 and 2003, due to unsettled federal land use issues (discussed below), depressed regional gas prices in 2002, and other factors, significant estimated potential gas reserves remain unexploited in the area.

The primary target coals are found in the Fort Union formation at depths ranging from 600 feet to 2,200 feet. It is common to encounter multiple coal zones varying in thickness from a few feet to over 150 feet between these depths. The methane in coal beds is adsorbed, or attached, within the coal layers and is held in place by water within the coals. When water is produced from the coal seam, the pressure is reduced, allowing the gas to desorb from the coal. Operators in the area have experienced de-watering times ranging from a few days to over one year, with the de-watering time influenced by well density, coal depth, permeability, gas content, structure and other factors. Gas production rates from individual wells in the play have ranged from a few Mcf per day to over 1,000 Mcf per day after sufficient de-watering.

Significant industry CBM drilling activities in this area began in 1994 and have primarily been focused on developing reserves in the Wyodak coal, on the east side of the basin. Typically, costs for these wells (including allocable costs for related surface equipment and infrastructure) averaged $70,000 to $90,000 per well, and yielded gross gas reserves averaging 250,000 to 300,000 Mcf per well. Future drilling operations are expected to be focused on development of the Big George, Wall and other coal seams that are generally deeper and often thicker than the Wyodak coal. We expect that as these deeper, thicker coals are developed, the gas reserves and production per well and the average drilling, completion and operating costs per well will be greater than experienced so far to develop the Wyodak coal seam.

To produce gas in this CBM play, wells generally must be hooked-up to a low-pressure gathering system and compression, commonly referred to as “screw compression,” which typically holds wellhead pressure to less than 10 pounds per square inch gauged (“psig”). The gas must then move through a gathering system where, at its terminus, gas needs to be further boosted to about 1,400 psig to enter a high-pressure header-system line. This high-pressure boost is commonly referred to as “reciprocating (or recip) compression.” CBM gas from this area is generally somewhat less than 1,000 Btu per Mcf and may require carbon dioxide extraction to meet interstate pipeline gas quality specifications. Due to relatively high compression and transportation costs, net price realizations for this gas are below Rocky Mountain indices. The amount of the discount varies with the nominal level of the indices, Btu content of the gas, location of the property, fuel use and other factors, but in 2003 Prima’s realized price on production from CBM wells averaged $2.87 per Mcf, compared to the CIG index average of $4.04, for a difference of $1.17 per Mcf.

Our CBM-prospective net acreage holdings in the Powder River Basin at the end of 2003 were comprised of approximately 83% federal, 7% state, and 10% fee (private) leases. Generally, the federal leases have an initial ten-year term, state leases have a five-year term, and the terms of fee leases vary from a few months to several years. The primary lease terms of federal acreage have generally been extended for the period that access to the lands has been restricted while an Environmental Impact Statement (“EIS”) was pending or subject to legal challenge after its completion.

On April 30, 2003, the BLM issued the final Record of Decision (“ROD”) in relation to its EIS regarding future CBM drilling in the Powder River Basin. Among other conditions for future operations, this ROD requires additional surveys for plant and animal species and cultural artifacts, and noxious weed mitigation. We have filed permit applications for approval by the BLM under the terms of the new EIS, but cannot predict whether or when such permits will be granted. Since the issuance of the final ROD, the BLM has been reviewing their permitting processes in an effort to eventually facilitate issuance to industry of approximately 3,000 drilling permits per year for this area, but actual issuances of permits have so far continued to be made at a fraction of that pace. BLM permit issuances may also be affected for some period by several pending lawsuits that were filed shortly after the ROD was issued, challenging portions of the BLM’s decision. At this time, we are unable to predict the outcome of this matter or its impact on our planned operations in the Powder River Basin. A significant portion of the wells we plan to drill in 2004 would require federal permits to be issued by the BLM. However, we do not expect that any limitations on our ability to drill during 2004 will affect the rate of our production until late in the year.

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The Wyoming Department of Environmental Quality (“DEQ”) is responsible for considering applications for water discharge permits and air discharge permits, which are required to operate natural gas fired compressors. Water produced from CBM wells is generally potable (drinking water quality) and permits to discharge water on the surface had generally been attainable early in development of the eastern side of the basin. However, issuance of permits to surface discharge water was significantly slowed during the past two years in order to allow further study of the potential impacts of the mineral content of the water on agriculture and wildlife. It is expected that, in the future, the Wyoming DEQ will generally require water management techniques other than surface discharge, such as collection in containment reservoirs or treating, in accordance with conditions also outlined in the BLM’s EIS. These additional requirements will add to the costs of CBM development and production, but we do not believe that they will materially impact the economic viability of the play. We have not encountered, nor do we expect to encounter, significant difficulties in obtaining air permits for our CBM operations from the DEQ.

The transportation infrastructure in this basin is currently capable of moving approximately 1,500,000 Mcf per day of natural gas, compared to the estimated 950,000 Mcf per day produced in December 2003. Downstream of these header systems serving the Powder River Basin, the pipeline grid has been significantly enhanced over the past year by several interstate pipeline expansions, creating adequate capacity at present to transport gas from the Rocky Mountain region to other markets. We do not currently own firm transportation for our own account, and so are relying on availability of capacity on pipelines in order to market our gas.

We established our first significant Powder River Basin CBM production in 2001 from the Stones Throw property (in the northern part of the play), where gross production rates increased over several months to a level in excess of 8,000 Mcf per day (approximately 6,800 Mcf net) shortly before the time the property was sold in March 2002. In July 2002, we initiated production from 27 wells at our Porcupine-Tuit CBM property (in the southern part of the play). Production from this property increased over the balance of the year and in 2003, as wells de-watered, more wells were drilled and hooked up, and additional third-party-owned compression capacity was installed. At the end of 2003, 85 wells had been drilled and hooked up at Porcupine-Tuit and were producing at a combined gross rate of approximately 25,000 Mcf per day (approximately 19,500 Mcf net). Overall, predominantly reflecting contributions these two properties, Prima’s Powder River Basin CBM properties accounted for net production averaging approximately 4,000 Mcf per day, 4,300 Mcf per day, and 17,700 Mcf per day, respectively, in 2001, 2002, and 2003. These early-stage developments primarily targeted relatively shallow Wyodak coals.

During 2003, Prima drilled 76 gross (57.7 net) Powder River Basin CBM wells and our direct capital expenditures on the Powder River Basin CBM play, including surface equipment and related infrastructure, totaled approximately $8.5 million. Activities during the year were focused on Porcupine-Tuit, where we drilled 24 wells, and on project areas in the central part of the basin where most of our core undeveloped land holdings in the play are concentrated. These include our Kingsbury, Cedar Draw and North Shell Draw project areas, located approximately 15 to 25 miles west and northwest of Gillette, Wyoming, where 2003 drilling activities were conducted to continue evaluation and development of four main identified coal seams, from the shallower Lower Anderson coal to the deeper Wall coal, found at depths ranging from 700 feet to 2,000 feet. These areas account for most of the previously-drilled wells that we intend to tie in to a gathering system in 2004. Further west lie additional key project areas where we control significant acreage, including Wild Turkey, where the Big George coal is found at approximately 1,300 feet, and Fortification Creek, which also has multiple developable coal seams at depths ranging from 700 feet to 1,600 feet. We anticipate that it will take some time to establish significant proved CBM reserves and production from these areas, particularly from the deeper coals, as they are untested in much of the basin and extensive de-watering will likely need to occur before commercial quantities of gas production can be realized. Furthermore, it is not assured that these projects will ultimately be successful and that they will yield significant reserves and production.

We are currently budgeting for capital investments in the Powder River Basin CBM play during 2004 of approximately $24 million for drilling costs, production equipment, and related infrastructure costs. Planned activities are focused primarily in the Kingsbury, Cedar Draw, North Shell Draw and Wild Turkey project areas. Our preliminary plans call for drilling an estimated 150 wells and hooking up most of these and 130 previously-drilled wells into gathering systems, as

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well as investing in infrastructure such as power connections and water management facilities. Due to uncertainties regarding regulatory approvals needed to conduct these activities, we can make no assurance that we will be able to conduct the operations that we have planned or that we will reach the targeted level of capital investments.

Other

Powder River Basin, Conventional. At the end of 2003, Prima owned working interests in 17 gross (12.8 net) conventional wells in the Powder River Basin, and deep-rights (below the coals) under 2,000 gross (1,400 net) developed acres and 160,000 gross (146,500 net) undeveloped acres in the area. Our estimated proved reserves at the end of 2003 from conventional sands in the Powder River Basin totaled 2,602,000 Mcf of natural gas and 60,000 barrels of oil, or 2,964,000 Mcfe, representing 2.4% of our total estimated proved reserve quantities. During 2003, Prima’s net production from these properties averaged approximately 1,400 Mcfe per day, accounting for 3.3% of our total oil and gas production and 3.4% of our oil and gas sales revenues (excluding hedging effects). Our net production from Powder River Basin conventional wells was 24% lower in 2003 than in 2002, reflecting natural depletion, as no new wells were drilled. No significant activity is currently planned for 2004.

Cave Gulch (Wind River Basin). At the end of 2003, Prima owned primarily non-operated working interests in 50 gross (3.8 net) wells in the Cave Gulch Field in the Wind River Basin. Our Wind River Basin acreage position is comprised of 1,240 gross (170 net) developed acres and 37,000 gross (23,000 net) undeveloped acres. Prima’s estimated proved reserves at the end of 2003 attributable to this area totaled 4,644,000 Mcf of natural gas and 14,000 barrels of oil, or 4,727,000 Mcfe, representing 3.8% of our total estimated proved reserve quantities. During 2003, Prima’s net production from the Cave Gulch Field averaged approximately 2,000 Mcfe per day, accounting for 4.7% of our total oil and gas production and 5.3% of our oil and gas sales revenues (excluding hedging effects). Our net production from Cave Gulch wells was 20% higher in 2003 than in 2002, as new wells and recompletions offset natural depletion. Prima’s capital investments at Cave Gulch in 2003 aggregated approximately $2.3 million, including costs of participating in drilling 17 gross (1.3 net) wells. The operator has indicated that up to six gross (0.5 net) additional wells are preliminarily planned for 2004, for a projected net Prima investment of approximately $1 million.

Coyote Flats Prospect. Prima’s Coyote Flats Prospect is located 15 to 25 miles northwest of Price, Utah, and is approximately 15 miles northwest of the Drunkard’s Wash Field, which is expected to ultimately produce in excess of 1.2 Tcf of natural gas from the Cretaceous Ferron coals and sandstones. We control approximately 75,000 gross (73,000 net) undeveloped acres within the prospect area. Data from drilling operations conducted on the Coyote Flats acreage during the 1950’s indicated gas shows from the Emery coal seam interval, the Ferron sand and the Dakota sand. Our primary exploratory objectives at Coyote Flats are coal beds in the Emery member of the Mancos shale and the Ferron sandstone interval. Emery coals are found across the majority of the lease position at depths below 3,000 feet, while the Ferron sandstone is found on the acreage at depths ranging from 5,000 to 8,500 feet.

During the fourth quarter of 2002, we drilled a 100%-owned exploratory well on the Coyote Flats Prospect, to begin to evaluate the Emery coals and the Ferron sandstone. The Scofield-Thorpe #22-41 well was drilled and cased to a total depth of 6,247 feet, before operations were suspended for the winter. The well encountered an aggregate 122 feet of Emery coal, from numerous coal beds, including eight with a thickness exceeding five feet, and the Ferron sandstone section was drilled between 5,991 and 6,247 feet. Encouraging gas shows were encountered while drilling from several of the Emery coal beds and from fractured shales and sandstones in the Ferron section.

In the second half of 2003, Prima initiated completion and testing of the Ferron sandstone reservoirs in the Scofield-Thorpe #22-41 well. We completed a 30-day production test on the well followed by a 7-day pressure build-up test. The test results were encouraging, as gas rates of 1,100 Mcf per day and water rates of 150 bpd were measured, with gradually increasing gas rates and decreasing water rates. During 2004, we plan to conduct follow-up drilling on the Coyote Flats Prospect to further evaluate the Ferron sandstone reservoirs, and we also expect to initiate a multi-well pilot program to test the Emery CBM potential. We may seek a partner to participate in these operations.

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East Clear Creek Prospect. We control approximately 9,000 gross and net acres in our East Clear Creek Prospect, located approximately 15 miles west of Price, Utah. This prospect is one mile east of Clear Creek Field, and two miles west of the Gordon Creek Field, both of which have produced from the Cretaceous Ferron sandstone. The Clear Creek Field produced in excess of 135 Bcf from 16 wells and the Gordon Creek Field was recently producing at a gross rate of approximately 2,700 Mcf per day from five wells placed on line over the past year. Prima has been working with the U.S. Forest Service and the Bureau of Land Management on an EIS that must be completed before drilling permits will be issued on this prospect. We expect to receive a permit to drill a test well on this prospect later this year and plan to drill a well as soon as practicable thereafter that will target the Ferron and Dakota sandstones at a depth of approximately 7,000 feet on a seismically-defined structure.

Flat Canyon Prospect. Prima owns approximately 6,600 gross and net acres under its Flat Canyon Prospect, located in Emery County, Utah. Our acreage immediately offsets the Flat Canyon Field, which was discovered in 1952. The Flat Canyon Field has produced 9.6 Bcf of natural gas and 14,000 barrels of oil from six wells completed in the Cretaceous Ferron sandstones. We plan to test the Cretaceous Ferron and Dakota formations on the prospect at depths between 6,500 and 7,500 feet. Prima is currently working with the U.S. Forest Service and the Bureau of Land Management to permit a well on this prospect.

Christmas Meadows Prospect. Prima currently holds leases or farmout rights representing approximately a 47% working interest in the Table Top Federal Unit, which is comprised of approximately 24,000 gross acres in Summit County, Utah, roughly 30 miles south of Evanston, Wyoming. The Christmas Meadows prospect, within the Unit, is a large seismically-defined anticlinal closure along the Uinta Mountain front, within the Rocky Mountain Overthrust Belt. Several potential pay sands have been identified down to an estimated depth of approximately 18,000 feet. This project has been delayed for several years and the federal leases have been temporarily suspended while the U.S. Forest Service was preparing an EIS and considering a revision of the forest plan for the area. It currently appears that these issues may be near resolution, enabling a test well to be spudded in the second half of 2004 or in 2005. The initial test well is expected to be drilled to a depth of approximately 15,000 feet to test the Frontier and Dakota sandstones. Once operations in the unit are commenced, Prima and its partners will have approximately six months to establish capability of commercial production, otherwise certain leases will expire. We anticipate participating in the test well for all or a portion of our current working interest.

Merna Prospect. Prima owns an average 35% working interest in 74,000 gross acres in the greater Merna area, located in the northern Green River Basin, in Sublette County, Wyoming. The Merna anticlinal structure is 20 miles northwest of the prolific Pinedale Anticline, where the over-pressured Cretaceous Lance and Mesaverde formations are under extensive development. The same objectives are targeted on the Merna Prospect. In late 2002, the Miller Federal #7-4 well was drilled by another operator along the Merna anticline on lands in which Prima had farmed out its 50% working interest. An affiliate of this operator installed a 36-mile natural gas pipeline to facilitate extended production testing and market sales for this well and future wells that might be drilled in the Merna area. The Miller Federal #7-4 well exhibited strong gas shows at high pressure while drilling but subsequent completion of the well in 2003 resulted in only modest production rates. This well and previous drilling in the area have established the presence of a thick Lance sand interval with gas in place, but project success will likely depend on encountering naturally-fractured reservoirs or successful application of fracture stimulation, due to relatively low porosity and permeability. In 2002, a large regional 3-D seismic survey that encompassed a large portion of the Merna Prospect acreage was completed. In late 2003, another operator initiated a test well on Merna acreage in which Prima held an interest. Prima is participating in the Sage Flat Federal #17-20 well, with a 6.3% working interest before payout and a 10.9% working interest after payout. The Sage Flat Federal #17-20 well is located three miles north of the Miller Federal #7-4 well.

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Proved Reserves

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Net proved reserves as of December 31, 2003, 2002 and 2001 were estimated by Prima’s engineers and audited by Netherland, Sewell and Associates, Inc., independent petroleum engineers.

The table below sets forth the estimated quantities of net proved reserves attributed to our property interests at the end of each of the last three years, and the present value of estimated future net cash flows attributed to such reserves using prices in effect as of the respective year-end dates, held constant. The average net realizable prices used to estimate proved reserve quantities at the end of 2003, 2002, and 2001, respectively, were as follows: $4.95, $2.64, and $1.94 per Mcf for natural gas; and $32.88, $31.30, and $19.71 per barrel of oil. In accordance with Securities and Exchange Commission guidelines, projected future net cash flows from production of proved reserves were discounted by ten percent per annum to derive present values and the “Standardized Measure” of discounted future net cash flows after income taxes. The 10% discount factor is not necessarily a market rate, and present value, no matter what discount factor used, is materially affected by assumptions as to future prices and costs and timing of future production, which may prove to be inaccurate. For further information concerning estimated proved reserves and the discounted future net cash flows related to these reserves, see unaudited “Supplementary Oil and Gas Information” in Note 12 within the Notes to Consolidated Financial Statements.

     There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing and amounts of development expenditures. Oil and gas reserve engineering should be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available engineering and geological data and interpretation, and judgment. Results of drilling, testing and production after estimates are prepared may justify revisions. Accordingly, reserve estimates are often materially different from the quantities of oil and natural gas that are ultimately produced. We are not currently aware of any developments subsequent to December 31, 2003 that we believe would warrant a significant upward or downward revision to our estimated proved reserves as of that date. Oil and natural gas prices have historically been volatile and are expected to continue to be so in the future. Changes in product prices affect the economic limits and, therefore, recoverable reserve quantities of oil and gas wells, as well as the present value of estimated future net cash flows and the standardized measure of discounted future net cash flows.

     Since January 1, 2003, we have filed Department of Energy Form EIA-23, “Annual Survey of Oil and Gas Reserves,” as required of operators of domestic oil and gas properties. There are differences between the reserves as reported on Form EIA-23 and reserves as reported herein. Form EIA-23 requires that operators report on total proved developed reserves for operated wells only and that the reserves be reported on a gross operated basis rather than on a net interest basis.

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Production

The following table summarizes information with respect to our producing oil and gas properties for each of the periods shown.

Productive Wells

The following table summarizes our total gross and net productive wells as of December 31, 2003.

Additionally, we own royalty interests in 148 gross wells that are not included in the above table.

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Developed and Undeveloped Acreage

At December 31, 2003, our oil and gas lease holdings were as follows:

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. We have generally been able to obtain extensions of the primary terms of our federal leases for the period that we have been unable to obtain drilling permits due to a pending EIS or related legal challenges. The following table sets forth the expiration periods of the gross and net acres subject to leases summarized in the table of undeveloped acreage, unless such leases are currently held by production from a portion of the lease that has been developed.

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Drilling Activities

Certain information with regard to our drilling activities for the years ended December 31, 2003, 2002 and 2001 is set forth below:

Present Activities

Year-to-date through February 27, 2004, we had drilled nine gross and net wells in the D-J Basin. Six of these wells were producing at that date, one was waiting on tie-in to a sales line and two were waiting on completion. We also restimulated (refraced or tri-fraced) 14 gross (12.8 net) wells in the D-J Basin, all of which have been restored to production. During this same period, we drilled five gross and net wells in the Powder River Basin CBM play and participated in drilling two non-operated (0.1 net) wells in the Cave Gulch area, all of which were waiting on completion as of February 27, 2004.

Natural Gas and Oil Marketing, Trading and Price Risk Management

Prima’s marketing and trading activities may include marketing our own production, marketing the production of other owners in wells that we operate, and the purchase and resale of third-party owned production. This oil and gas production is principally sold to end users, marketers, refiners and other purchasers having access to pipeline facilities or the ability to truck oil to local refineries. The marketing of oil and gas can be affected by a number of factors that are beyond our control and which cannot be accurately predicted. At times, we use financial instruments to hedge the price of a portion of our production or production of others that we have committed to purchase for resale.

In 2003, revenues from the sale of Prima’s natural gas production, including related hedging effects, totaled $45,911,000, representing 78% of our and gas sales and 65% of our consolidated total revenues. Revenues from the sale of Prima’s crude oil in 2003, including hedging effects, totaled $12,711,000, representing 22% of our oil and gas sales and 18% of our consolidated total revenues.

Natural Gas

The terms and conditions of our natural gas sales contracts vary as to price, quantity, term and other conditions, but in general follow 30-day index or day-to-day spot market prices. We occasionally sell gas at a fixed price for periods greater than 30 days as an effective price hedge, but had no such fixed-price sales arrangements in effect at year-end 2003. We currently have two significant purchasers for our natural gas, Duke Energy Field Services, LLC (“Duke”) and Western Gas Resources, Inc (“Western”). Neither of these companies is affiliated with Prima and, while loss of either as a purchaser or customer might have a material adverse effect on our business, we believe that we could arrange to sell our gas to alternate customers on reasonably comparable terms.

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Natural gas produced in the D-J Basin is high in heating content and must be processed to extract natural gas liquids. Duke purchases most of our D-J Basin gas at the wellhead, under contracts that provide for Prima to receive fixed percentages of the proceeds generated by Duke’s sale of residue gas and natural gas liquids after the gas is processed at Duke’s plants. Net sales to Duke in 2003 accounted for approximately $19,193,000, or 27% of our total consolidated revenues.

Western purchases much of our gas production in the Powder River Basin, including CBM gas from wells in the Porcupine-Tuit area. This CBM gas, which accounted for over 95% of our sales to Western in 2003, is sold at the inlet to Western’s compression facilities at prices based on the monthly CIG index less certain costs for compression and transportation. Net sales to Western in 2003 accounted for approximately $19,062,000, or 27%, of our total consolidated revenues.

Our current gas gathering and marketing agreements generally arrange to get our gas from the wellhead into high-pressure header systems or interstate pipelines. We have not, however, contracted for downstream transportation on a firm basis. As such, we have no liability to pay reservation (demand) charges for header or pipeline capacity, but we also have no assurance that our gas will flow every day and we are at risk that regional imbalances between gas supply and pipeline capacity will unfavorably impact the gas prices that we realize for our production. No significant curtailments of gas production occurred during the three-year period ended December 31, 2003, but limited pipeline capacity did create conditions during several months, particularly between mid-2002 and mid-2003, in which the netback price that we received for our natural gas was significantly below prices being paid for gas elsewhere in the country. Due to expansions of pipeline capacity during 2003, we do not expect such conditions to recur in the near-term.

At times, we have also engaged in purchasing and re-selling third-party gas within our areas of operations. These arrangements typically provide for the purchase of natural gas at a known price or index, with a corresponding sale at a net margin. However, from time to time we may have open purchase or sale commitments without corresponding re-sale contracts, which could result in losses. Prima’s Chief Executive Officer reviews such opportunities before commitments are made and we closely monitor the mark-to-market gains or losses of such positions. We had no purchase-for-resale trading obligations outstanding at the end of 2003 and had entered into no commitments after year-end 2003 through February 27, 2004.

Oil

Our oil production is typically sold to refiners, marketers and other purchasers that truck it to local refineries or pipelines. The price is generally based on a prevailing spot market index, such as NYMEX, with adjustments for quality and location. We currently have one significant purchaser of crude oil, Valero Energy Corporation, which accounted for approximately $11,831,000, or 17%, of our total consolidated revenues in 2003. We are not affiliated with Valero and believe that we could sell our crude oil to other purchasers should we lose Valero as a purchaser, though the terms might be less favorable.

Price Risk Management

We sometimes utilize commodity futures, over-the-counter swaps or similar derivatives to mitigate risks related to the volatility of oil and gas prices. Such transactions can also be used to protect against the risk of an expanding differential between NYMEX and Rocky Mountain gas prices, which can occur when Rocky Mountain gas supplies exceed regional demand and pipeline capacity out of the Rocky Mountain region or due to other factors, such as regional weather differences. A portion of these contracts d