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SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

[x]   QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2003

OR

[  ]   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____________ to ____________

Commission file number 0-9408

PRIMA ENERGY CORPORATION

1099 18th Street, Suite 400, Denver CO 80202
(Address of principal executive offices)     (Zip Code)

(303) 297-2100
(Registrant’s telephone number, including area code)

No Change
(Former name, former address and former fiscal year, if changed from last report.)

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 [  ]

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12-b-2 of the Exchange Act). Yes [x]    No [  ]

As of April 30, 2003, the Registrant had 12,741,742 shares of Common Stock, $0.015 Par Value, outstanding.

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PRIMA ENERGY CORPORATION

INDEX

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS

ASSETS

See accompanying notes to unaudited consolidated financial statements.

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PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS (cont’d.)

LIABILITIES AND STOCKHOLDERS’ EQUITY

See accompanying notes to unaudited consolidated financial statements.

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PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)

See accompanying notes to unaudited consolidated financial statements.

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PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)

See accompanying notes to unaudited consolidated financial statements.

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PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

(1)  Amounts have been reclassified to reflect cash held in a like-kind exchange escrow account as cash and cash equivalents based upon the subsequent closure of the escrow account when a like-kind exchange transaction was not consummated. The adjustment increased by $11,746,000 the amount of cash provided by investing activities and increased the amount of cash and cash equivalents held at the end of March 2002.

See accompanying notes to unaudited consolidated financial statements.

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PRIMA ENERGY CORPORATION
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. GENERAL

     Prima Energy Corporation is an independent oil and gas company primarily engaged in the exploration for, and the acquisition, development and production of, crude oil and natural gas. Through wholly owned subsidiaries, we also conduct operations in oil and gas property management, oilfield services and natural gas gathering, marketing and trading. These activities have been conducted predominantly in the Rocky Mountain region of the United States.

     Our consolidated financial statements include the accounts of Prima Energy Corporation and its subsidiaries, which are collectively referred to in this report as “Prima” or “the Company.” All significant intercompany transactions have been eliminated.

     Financial information presented herein as of March 31, 2003 and for the three-month periods ended March 31, 2003 and 2002 is unaudited but reflects all adjustments that we believe are necessary to fairly present Prima’s financial position, results of operations and cash flows for the periods shown. Such adjustments consist only of normal recurring accruals. Certain prior-year amounts have also been reclassified to conform to classifications reflected as of March 31, 2003. Results for interim periods are not necessarily indicative of results to be expected for our full fiscal year ending December 31, 2003.

     The consolidated financial statements presented in this Form 10-Q should be read in conjunction with the Notes to Consolidated Financial Statements that were included in Prima’s Annual Report on Form 10-K filed for the year ended December 31, 2002.

2. ASSET RETIREMENT OBLIGATIONS

     Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 provides that, if the fair value for an asset retirement obligation can be reasonably estimated, the liability should be recognized in the period in which it is incurred. Oil and gas producing companies typically incur such liabilities upon drilling or acquiring wells. Under the method prescribed by SFAS No. 143, an asset retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting charge to property cost. The corresponding property cost, less the estimated undiscounted salvage value, is then included in the calculation of depletion cost for oil and gas properties. Periodic accretion of discount of the estimated liability is also recorded in the income statement. Prior to adoption of SFAS No. 143, we accrued for any estimated asset retirement obligation, net of estimated salvage value, as part of our calculation of depletion, depreciation and amortization. Under this method, the estimated net cost of the obligation would be recognized over the life of the property on a unit-of-production basis, with the estimated obligation netted in property cost as part of the accumulated depreciation, depletion and amortization balance. Based on our experience that salvage values have generally equaled or exceeded abandonment costs for the types of properties that Prima has owned to date, such net costs have been negligible.

     Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable laws and regulations. We have determined our asset retirement obligation by calculating the present value of estimated future cash flows related to the liability. Our adoption of SFAS No. 143 as of January 1, 2003 resulted in the recognition of an increase in the carrying value of our oil and gas

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properties of $2,252,000, an increase in our deferred tax liability of $217,000, an increase in other non-current liabilities of $1,632,000, and a net-of-tax adjustment increasing net income by $403,000, which was recorded as the cumulative effect of a change in accounting principle. The estimated pro forma effect of January 1, 2002 adoption of SFAS No. 143 on net income and earnings per share for interim and annual periods in 2002 is not material. The liability for asset retirement obligations of $1,632,000 recorded as of January 1, 2003 was increased by $32,000 for accretion of discount during the quarter to arrive at the recorded liability of $1,664,000 at the end of March 2003.

3. DERIVATIVES TRANSACTIONS

     From time to time, we have used crude oil and natural gas futures, options and swaps, to mitigate risks associated with fluctuating oil and natural gas prices and basis differentials. While the use of such derivatives can reduce the adverse effects of oil and gas price declines or increases in basis differentials, they also generally limit the benefits of price increases.

     All derivative financial instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date, and/or the value confirmed by the counterparty. Changes in the fair value of effective cash flow hedges are recorded as a component of accumulated other comprehensive income (loss), which is later included in oil and gas sales when the hedged transaction occurs. Changes in the fair value of derivatives that are not designated as hedges, as well as any ineffective portion of hedge derivatives, are recorded in “gains (losses) on derivative instruments, net” in the income statement.

     Giving consideration to our current sources of oil and gas production, we have determined that, swaps, collars, puts or floors that are based on NYMEX oil prices or CIG gas prices qualify as effective cash flow hedges. Derivatives based on NYMEX gas prices will not qualify unless we have entered into corresponding transactions to hedge basis differentials between NYMEX and CIG indices. In addition, stand-alone basis-differential swaps and sales of call options do not qualify for hedge accounting.

     The gains and losses on derivatives instruments recognized in the first three months of 2003 and 2002 were primarily related to NYMEX gas swaps for which we did not elect to enter into corresponding swaps for Rocky Mountain basis differentials. In the first quarter of 2003, $638,000 of losses on derivative transactions that qualified for hedge accounting were included in oil and gas sales. No hedging gains or losses were included in oil and gas sales in 2002.

     As of March 31, 2003, Prima had recorded a current asset of $965,000, representing the aggregate unrealized mark-to-market gains for its open derivative positions at that date. These positions are summarized below:

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4. EARNINGS PER SHARE

     Basic net income per share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted net income per share reflects the potential dilution that could occur upon exercise of options to acquire common stock, computed using the treasury stock method. The treasury stock method assumes that the number of additional shares that could be issued is reduced by the number of shares that could have been repurchased with proceeds that Prima would receive upon exercise of the options. The amount of shares that could have been repurchased was determined using the average market price of our common stock during the reporting period.

     The following table reconciles the net earnings and common shares outstanding used in the calculations of basic and diluted net income per share for the quarter ended March 31, 2003. The diluted loss per share calculations for the quarter ended March 31, 2002 produce results that are anti-dilutive. The dilutive calculation for 2002 increased the common shares outstanding by 442,789 shares. Therefore, the diluted loss per share amounts for 2002 reported in the accompanying consolidated statements of income are the same as the basic loss per share amounts.

5. STOCK-BASED COMPENSATION

     Prima has stock-based compensation plans for its employees and its non-employee directors. The Company accounts for stock-based compensation using the intrinsic value recognition and measurement principles prescribed in Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” and related interpretations. No stock-based compensation expense for employees or non-employee directors is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant.

     For disclosure purposes, the fair value of options is measured at the date of grant using the Black-Scholes option valuation model, which was developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable. Such option valuation models require the input of highly subjective assumptions. Because options issued under Prima’s stock-based compensation plans have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the estimated fair value, these valuation models do not necessarily provide a reliable measure of the fair value of such stock options.

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     For purposes of pro forma disclosures, the estimated fair values of option grants are amortized to expense over the options’ vesting periods. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation.”

6. RECENT ACCOUNTING PRONOUNCEMENTS

     In June 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation— Transition and Disclosure — an amendment of FASB Statement No. 123, effective for the fiscal years beginning after December 31, 2002. SFAS No. 148 amends FASB Statement No. 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. We continue to follow the intrinsic value method prescribed by APB 25 in accounting for stock options, recognizing no compensation expense for options granted at or above market price. We adopted the provisions of SFAS No. 148 effective for the fiscal year ended December 31, 2002 and have complied with the amended disclosure requirements.

     In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities to amend and clarify financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. The changes in this statement require that contracts with comparable characteristics be accounted for similarly to achieve more consistent reporting of contracts as either derivative or hybrid instruments. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003 and will be applied prospectively. We do not anticipate any significant impact on our financial position or results of operations upon adoption.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     The following discussion is intended to assist in understanding Prima’s financial position at March 31, 2003, its results of operations for the three-month periods ended March 31, 2003 and March 31, 2002, and our assessment of Prima’s liquidity and capital resources.

Liquidity and Capital Resources

     Historically, Prima’s principal sources of liquidity have been the 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. Our revenues and cash flows are substantially derived from oil and gas sales, which are dependent upon oil and gas production volumes and sales prices.

     Cash flow from operations before changes in operating assets and liabilities totaled $9,196,000 in the first quarter of 2003, compared to $6,918,000 in the first quarter of 2002. (This is a non-GAAP financial measure derived from net cash provided by operating activities; see “Reconciliation of Non-GAAP Financial Measure” in table below.) We also received cash proceeds totaling $1,293,000 from the sale of certain oil and gas properties, while our investments in oil and gas properties during the quarter aggregated $3,952,000. Prima’s net working capital increased from $35,954,000 at the end of 2002 to $42,993,000 at March 31, 2003. Net working capital at the end of the first quarter of 2003 included cash equivalents and short-term investments totaling $39,849,000, compared to $38,007,000 at the end of 2002, and we were free of long-term debt at both dates. Our contractual obligations for operating leases for office rent and compressor rentals at March 31, 2003 were as follows: within one year, $346,000; from one to three years, $951,000; and after three years, $211,000.

     Our investments during the first quarter of 2003 included $251,000 for acquisitions of undeveloped acreage and $3,701,000 for well costs and other development activities, primarily relating to exploitation and development activities in the Denver Basin, in the Cave Gulch Field in the Wind River Basin, and on CBM properties in the Powder River Basin. Denver Basin operations included re-fracturing 8 gross (7.4 net) wells, completing two gross (1.9 net) wells that were drilled in 2002, and commencing drilling operations on three gross (3.0 net) wells that were completed in April. In the Cave Gulch Field, Prima participated in drilling two gross (0.3 net) wells and recompleting one gross (0.2 net) well during the first quarter of 2003. Production operations have been, or are expected to be, established or resumed on all of these wells. Powder River Basin activities were largely confined to permitting and infrastructure investments made to facilitate future drilling and development operations. Of the asset sales proceeds realized during the period, $1,200,000 related to the sale of 1,120 gross and net acres in our Kingsbury project area in the Powder River Basin, which included eight shallow-coal CBM wells that were producing an aggregate of approximately 150 Mcf per day net to Prima when sold.

     During the recent quarter, Prima also utilized $252,000 for other property and equipment and $858,000 for the purchase of approximately 46,000 shares of treasury stock at an average cost of $18.75 per share. Subsequent to quarter-end through May 7th, we acquired approximately 59,000 additional shares of treasury stock at an average cost of $18.90 per share. Approximately 297,000 additional shares of Prima’s common stock may be repurchased under an existing authorization from our Board of Directors.

     As previously reported, Prima anticipates investing between $25 million and $30 million on property and equipment during 2003, excluding acquisitions which are unbudgeted. Currently projected drilling activities for the full year include 60 to 90 CBM wells in the Powder River Basin, 15 to 25 wells

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in the Denver Basin, and participation in up to ten wells in the Cave Gulch area. The CBM wells planned for 2003 include extension of the Porcupine-Tuit field, which produces from Wyodak coals, and activities to evaluate and develop deeper, unproved coals within our Kingsbury, Wild Turkey and Cedar Draw project areas. Current plans also include re-stimulating approximately 30 producing wells in the Denver Basin.

     Powder River Basin CBM activities planned for 2003 have been weighted toward the second half of the year. One factor influencing that timing has been a pending record of decision (ROD) to be issued by the Bureau of Land Management (BLM), to finalize an environmental impact statement (EIS) for the area. The ROD was issued on April 30, 2003 and is expected, ultimately, to significantly improve access to federal lands in the Powder River Basin for CBM development. However, as anticipated, various challenges to the ROD have already been filed in federal courts and there may be delays in its implementation pending resolution of these challenges. While some of Prima’s planned activities for 2003 may be affected by the status of the BLM’s implementation of the EIS, drilling activity conducted during the year will also be dependent on other factors. These include the timing and conditions of approvals required for certain water management plans, completion of agreements with various surface owners, conclusion of negotiations with certain working interest owners regarding potential acreage swaps, and Forest Service approvals required for planned drilling at Porcupine-Tuit. We are also in the process of negotiating an agreement for installation of gas gathering and compression facilities that will, if completed, enable hook-up of up to 90 previously drilled CBM wells in addition to planned future wells in several of Prima’s CBM project areas in the general vicinity of the Kingsbury project.

     We are currently projecting that our total oil and gas production in 2003 will be toward the higher end of our previously indicated target range of 12,500,000 Mcfe to 13,000,000 Mcfe. We plan to reassess this target range after the close of the second quarter and will likely raise it if the Porcupine-Tuit property continues to outperform initial projections and we are able to obtain permits to drill additional wells at Porcupine-Tuit in the second half of the year.

     We expect to fund our planned current year exploration, development, and exploitation operations, the expansion of our service companies, and any re-purchases of common stock with cash provided by operating activities and existing working capital. We also regularly review opportunities for acquisition of assets or companies related to the oil and gas industry that could expand or enhance our existing business. If a sufficiently large transaction is consummated, it could involve the incurrence of debt or issuance of equity securities.

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Reconciliation Of Non-GAAP Financial Measure

Cash flow from operations before changes in operating assets and liabilities is presented because of its acceptance as an indicator of the ability of an oil and gas exploration and production company to internally fund exploration and development activities. This measure should not be considered as an alternative to net cash provided by operating activities as defined by generally accepted accounting principles. A reconciliation of cash flow from operations before changes in operating assets and liabilities to net cash provided by operating activities is shown below:

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 more than three-quarters 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 began to approach 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.

     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 averaged approximately $0.57 per MMBtu less than the average for gas at Henry Hub, but the amount of this discount ranged on an annual basis between $0.26 (1999) and $1.37 (2002). Monthly variances in index prices during this period ranged between an $0.11 premium (January 1993) and a $2.44 discount (October 2002).

     Basis differentials widened considerably starting in May 2002, as gas supply in the region began to outstrip available pipeline capacity. Although Rocky Mountain gas prices improved during this past winter, basis differentials remained unusually wide, as prices in other regions increased as much or more. The differential between the Henry Hub and CIG indices in the first quarter of 2003 averaged $2.82 per MMBtu, compared to $0.45 per MMBtu in the first three months of 2002. Due in part to pipeline capacity

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expansion projects that have recently improved access to higher-priced gas markets, commodity futures markets as of May 7, 2003 reflected expectations of improving basis differentials, to $1.35 per MMBtu for the period from June through October 2003, and $0.94 per MMBtu for the winter of 2003-2004. The largest of these expansions is the Kern River Pipeline, which commenced operations at the beginning of May 2003 with an additional 900,000 Mcf per day of capacity to 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:

     For the quarter ended March 31, 2003, Prima reported net income of $5,382,000, or $0.41 per diluted share, including a gain of $403,000, or $0.03 per diluted share, resulting from the cumulative effect of change in accounting principle pursuant to adoption of SFAS 143. These operating results compare to a first quarter 2002 net loss of $722,000, or $0.06 per diluted share. Total revenues increased $10,203,000, from $5,407,000 in the first quarter of 2002 to $15,610,000 in the latest quarter. Total expenses, other than income taxes, increased $1,712,000 to $8,181,000 in the recent quarter, compared to $6,469,000 in the first three months of 2002. These year-over-year changes represent an overall 189% increase in revenue and a 26% increase in expenses.

     Oil and gas sales totaled $12,212,000 in the first quarter of 2003, compared to $5,884,000 in the prior-year period, for a 108% increase. This growth was attributable to the combined effects of a 27% improvement in oil and gas production volumes and 63% higher average price realizations per equivalent unit of production. The year-over-year improvement in revenues also reflected a $4,062,000 net increase in gains/losses on derivative instruments, from a $2,708,000 loss in 2002 to a $1,354,000 gain in the recent quarter

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     Prima’s total production in the first quarter of 2003 of 3,353,000 Mcfe, or approximately 37,300 Mcfe per day, represents record levels for Prima, and a 27% improvement from the 2,644,000 Mcfe produced in the same quarter of 2002. Our production mix in the first quarter of 2003 was 83% natural gas and 17% oil, compared to 80% gas and 20% oil in the prior-year period. Natural gas production in the latest quarter of 2,795,000 Mcf was 33% greater than the 2,103,000 Mcf produced in the first three months of 2002. Oil production in the initial quarters of 2003 and 2002 totaled 93,000 barrels and 90,000 barrels, respectively, for an increase of 3,000 barrels, or 3%. The overall year-over-year increase was due to Powder River Basin CBM operations, which generated net gas production of 1,144,000 Mcfe in the first quarter of 2003, compared to 382,000 Mcfe in the first quarter of 2002. Current year CBM production was primarily attributable to continued strong performance of Prima’s Porcupine-Tuit property, which began producing in the third quarter of 2002. CBM production in the comparable quarter last year was primarily attributable to two months’ contribution from the Stones Throw property, which was sold in March 2002. Since installation of a sixth screw compressor in mid-April, gross production from the 58 completed wells at Porcupine-Tuit has approximated 23,000 Mcf per day, or more than 17,000 Mcf per day net to Prima.

     Average prices received for natural gas production in the first quarter of 2003 aggregated $3.22 per Mcf, compared to $1.87 per Mcf in the first three months of 2002, for a year-over-year increase of $1.35 per Mcf or 72%. Average sales prices received per barrel of oil were $34.60 in the recent quarter and $21.61 in the same period last year, for an increase of $12.99 per barrel or 60%. On an energy equivalent basis, the average price received in the latest quarter was $3.64 per Mcfe, or 63% above the $2.23 per Mcfe realized in the prior year period. Approximately 74% of Prima’s total oil and gas revenues in the 2003-quarter were derived from natural gas sales, compared to 67% in the first quarter of 2002. First quarter 2003 price realizations incorporate the effects of hedges that reduced average gas price realizations by $0.24 per Mcf, increased the average oil price by $0.44 per barrel, and decreased the average price per Mcfe by $0.19. Price realizations in the comparable period of 2002 did not include any hedging effects.

     First quarter 2003 revenues included $1,354,000 of net gains recognized on ineffective hedges, including unrealized gains resulting from mark-to-market valuations at the end of the period. These ineffective hedges consisted of contracts for forward sales of NYMEX natural gas, which do not qualify as effective cash flow hedges since corresponding basis differential hedges were not entered into. In the first quarter of the prior year, we reported net losses of $2,708,000 on similar contracts, though Prima realized net cash receipts of $2,450,000 from derivatives positions that were closed out during the quarter. The disparity in 2002 between net receipts and reported losses occurred because mark-to-market gains on open positions had been included in prior period revenues and a subsequent improvement in gas prices reduced the amount of gains ultimately realized when such contracts were settled.

     Depletion expense reported for 2003 was $3,135,000, including $32,000 of accretion expense for estimated future asset retirement obligations, in accordance with SFAS 143. The rate of $0.93 per Mcfe of oil and gas production in 2003 compares to $0.90 per Mcfe in 2002. Depreciation of other fixed assets, which include service equipment, office furniture and equipment, and buildings, totaled $284,000 and $302,000 for the first quarters of 2003 and 2002, respectively.

     Lease operating expenses (“LOE”) totaled $941,000 for the three months ended March 31, 2003 compared to $797,000 for the three months ended March 31, 2002, an increase of $144,000 or 18%. Additional costs were largely attributable to new production from CBM wells, and LOE decreased per-unit-of-production, from $0.30 per Mcfe in the first quarter of 2002 to $0.28 per Mcfe in recent quarter. Ad valorem and other production taxes totaled $1,234,000 and $456,000 for the same periods, an increase of $778,000. Production taxes averaged $0.37 and $0.17 per Mcfe in the 2003 and 2002 quarters, respectively, reflecting both higher product prices in 2003 and an increased portion of sales attributable to

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properties in Wyoming, where severance tax rates are higher than in Colorado. Total lifting costs (LOE plus ad valorem and production taxes) were 18% of oil and gas revenues in the first quarter of 2003 compared to 21% in the first quarter of 2002.

     Oilfield services include the operations of Action Oilfield Services, Inc. (Colorado) and Action Energy Services (Wyoming), wholly owned subsidiaries. Related revenues include well servicing fees from completion and swab rigs, CBM drilling rigs, trucking, water hauling, equipment rentals, and other related activities. Services are provided to both Prima and unaffiliated third parties, but intercompany billings are eliminated in consolidation. Oilfield service revenues from third parties totaled $1,939,000 in the three months ended March 31, 2003 compared to $2,085,000 in the three months ended March 31, 2002, for a decrease of $146,000, or 7%. Costs of oilfield services provided to third parties were $1,739,000 in 2003 compared to $1,763,000 in 2002, for a decrease of $24,000, or 1%. Service revenues and costs associated with Prima-operated property interests represented 17% of the service companies’ activities in 2003 compared to 10% in 2002.

     General and administrative expenses (“G&A”), net of third party reimbursements and amounts capitalized, were $848,000 for the three months ended March 31, 2003 compared to $772,000 for the three months ended March 31, 2002. Net G&A increased $76,000 or 10% due to lower reimbursements from third parties and higher employment costs. Third-party reimbursements of management and operator fees decreased from $146,000 in 2002 to $114,000 in 2003 because Prima operated wells at Stones Throw in March 2002 on behalf of the successor owner and was reimbursed.

     We recorded an income tax provision of $2,450,000 for the three months ended March 31, 2003 compared to an income tax benefit of $340,000 for the three months ended March 31, 2002. Prima’s effective tax rates were 33% in 2003 and 32% in 2002. The effective tax rates in both years were less than statutory rates due to permanent differences in financial and taxable income, consisting primarily of statutory depletion deductions for both years and Section 29 tax credits in 2002. Permanent differences declined in 2003 as the result of the expiration of Section 29 tax credits at the end of 2002.

New Accounting Pronouncements

     In June 2002, the FASB issued SFAS No. 148 “Accounting for Stock-Based Compensation— Transition and Disclosure — an amendment of FASB Statement No. 123”, effective for the fiscal years beginning after December 31, 2002. SFAS 148 amends FASB Statement No. 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. We continue to follow the intrinsic value method prescribed by APB 25 in accounting for stock options, recognizing no compensation expense for options granted at or above market price. We adopted the provisions of SFAS 148 effective for the fiscal year ended December 31, 2002 and have complied with the amended disclosure requirements.

     In April 2003, the FASB issued SFAS No. 149 “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” to amend and clarify financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. The changes in this statement require that contracts with comparable characteristics be accounted for similarly to achieve more consistent reporting of contracts as either derivative or hybrid instruments. SFAS 149 is effective for contracts entered into or modified after June 30, 2003 and will be applied prospectively. We do not anticipate any significant impact on our financial position or results of operations upon adoption.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     Our primary market risks relate to changes in prices received on our sales of natural gas and oil production. We periodically enter into derivatives contracts to mitigate a portion of this commodity price risk. Such derivatives consist of commodity futures or price swaps (agreements with counterparties to exchange floating prices for fixed prices), and options on such futures or price swaps. These instruments reduce our exposure to decreases in gas and oil prices, or increases in differentials between NYMEX and Rocky Mountain gas prices, but they also generally limit the benefits realized from increases in prices or narrowing of basis differentials. By hedging only a portion of our exposure to changes in prices, we are able to benefit from increases in gas and oil prices or improvements in basis differentials, but we remain exposed to market risk on the portion of our production not covered by such derivatives. Prima also retains risks related to the ineffective portion of its derivatives instruments, when applicable.

     We have entered into derivatives contracts that are intended to offset risks associated with downward price movements in benchmark NYMEX gas and oil prices, and basis swaps to offset risks of increases in the differential between NYMEX and Rocky Mountain gas prices. These derivatives positions represent cash flow hedges that are determined to be qualifying or non-qualifying for hedge accounting treatment in accordance with the provisions of SFAS 133. See Derivatives Transactions in Notes to Consolidated Financial Statements for additional information with respect to our derivatives and related accounting policies.

     Personnel who have appropriate skills, experience and supervision execute all derivatives transactions. The personnel involved in these activities must follow prescribed trading limits and parameters that are regularly reviewed by Prima’s Chief Executive Officer. Prima’s Chief Executive Officer approves all derivatives transactions before being entered into and significant transactions are reviewed by Prima’s Board of Directors. We utilize only conventional derivatives instruments and attempt to manage credit risk by entering into derivatives contracts only with financial institutions that are believed to be reputable and which carry an investment grade rating.

     We closed certain derivative instruments between April 1, 2003 and May 7, 2003, for net realized gains totaling $298,000. As of the close of business on May 7, 2003, open oil and gas derivative instruments showed net unrealized gains of $101,000, as follows:

     Certain information regarding our market risks is provided below. Investors and other users are cautioned to avoid simplistic use of these disclosures. Users should realize that the actual impact of future commodity price movements would likely differ from the amounts disclosed below due to ongoing changes in risk exposure levels and concurrent adjustments to positions. It is not possible to accurately predict future movements in natural gas and oil prices.

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     During the first quarter of 2003, Prima sold 93,000 barrels of oil. A hypothetical decrease of $3.42 per barrel (10% of average first quarter prices excluding hedging transactions) would have decreased our production revenues by $318,000 for that period. Prima sold 2,795,000 Mcf of natural gas during the first quarter of 2003. A hypothetical decrease of $0.35 per Mcf (10% of average first quarter prices excluding hedging transactions) would have decreased our production revenues by $978,000 for that period.

ITEM 4. CONTROLS AND PROCEDURES

     Prima’s principal executive officer and principal financial officer evaluated the effectiveness of Prima’s “disclosure controls and procedures,” as such term is defined in Rule 13a-14(c) and 15d-14(c) of the Securities Exchange Act of 1934, as amended, within 90 days of the filing date of this Quarterly Report on Form 10-Q. Based upon their evaluation, the principal executive officer and principal financial officer concluded that Prima’s disclosure controls and procedures were effective. There were no significant changes in Prima’s internal controls or in other factors that could significantly affect these controls since the date the controls were evaluated.

CAUTIONARY STATEMENT FOR PURPOSES OF THE “SAFE HARBOR”

     “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in Item 2 of this Report 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, capital expenditures budget (both the amount and the source of funds), continued volatility of oil and natural gas prices, future drilling plans and other such matters. The words “anticipate,” “expect,” “plan” or “intend” and similar expressions identify forward-looking statements. Such statements are based on certain assumptions and analyses made by Prima’s management in light of their experience and perceptions of historical trends, current conditions, expected future developments and other factors that are believed to be appropriate in the circumstances. Prima does not undertake to update, revise or correct any of the forward-looking information. Factors that could cause actual results to differ materially from the expectations expressed in the forward-looking statements include, but are not limited to, the following: industry conditions; volatility of oil and natural gas prices; hedging activities; operational risks (such as blowouts, fires and loss of production); insurance coverage limitations; potential liabilities, delays and associated costs imposed by government regulation (including environmental regulation); the need to develop and replace Prima’s oil and natural gas reserves; the substantial capital expenditures required to fund operations; risks related to exploration and developmental drilling; and uncertainties about oil and natural gas reserve estimates. For a more complete explanation of these various factors, see “Cautionary Statement for the Purposes of the ‘Safe Harbor’ Provisions of the Private Securities Litigation Reform Act of 1995” included in Prima’s Annual Report on Form 10-K for the year ended December 31, 2002, beginning on page 23.

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PART II. OTHER INFORMATION

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

     (a)  Exhibits

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     (b)  Reports on Form 8-K

     During the quarter ended March 31, 2003, the Company filed the following reports on Form 8-K:

•		Report dated March 10, 2003, reporting year-end 2002 reserves and production, year 2003 estimated capital expenditures, and an update of commodity hedging transactions.
•		Report dated March 19, 2003, reporting year-end 2002 financial results and providing an update of operating activities and commodity hedging transactions.
•		Report dated March 31, 2003 submitting certifications by the Chief Executive Officer and the Chief Financial Officer of Prima Energy Corporation pursuant to 18 U.S.C. § 1350 as adopted by § 906 of the Sarbanes-Oxley Act of 2002.

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SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

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CERTIFICATION

I, Richard H. Lewis, certify that:

1.		I have reviewed this quarterly report on Form 10-Q of Prima Energy Corporation;
2.		Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
3.		Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;
4.		The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

	a)		designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
	b)		evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and
	c)		presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

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

	a)		all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
	b)		any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6.

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

Date: May 14, 2003

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CERTIFICATION

I, Neil L. Stenbuck, certify that:

1.		I have reviewed this quarterly report on Form 10-Q of Prima Energy Corporation;
2.		Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
3.		Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;
4.		The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

	a)		designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
	b)		evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and
	c)		presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

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

	a)		all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
	b)		any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6.

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

Date: May 14, 2003

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EXHIBIT INDEX