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, 2004

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, 2004, the Registrant had 12,980,192 shares of Common Stock, $0.015 Par Value, outstanding.

PRIMA ENERGY CORPORATION

INDEX

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PRIMA ENERGY CORPORATION

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

See accompanying notes to unaudited consolidated financial statements.

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PRIMA ENERGY CORPORATION

See accompanying notes to unaudited consolidated financial statements.

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PRIMA ENERGY CORPORATION

See accompanying notes to unaudited consolidated financial statements.

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PRIMA ENERGY CORPORATION

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, 2004 and for the three-month periods ended March 31, 2004 and 2003 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, 2004. Results for interim periods are not necessarily indicative of results to be expected for our full fiscal year ending December 31, 2004.

     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, 2003.

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 increase in 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

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SFAS No. 143 as of January 1, 2003 resulted in the recognition of an increase in the carrying value of our oil and gas 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. A reconciliation of Prima’s liability for the three months ended March 31, 2004 and 2003 is as follows:

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 Rocky Mountain 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 Rocky Mountain indices. In addition, stand-alone basis-differential swaps and sales of call options do not qualify for hedge accounting.

     In the first quarter of 2004, $1,174,000 of losses on derivative transactions that qualified for hedge accounting were included in oil and gas sales. In the first quarter of 2003, $638,000 of similar losses were included in oil and gas sales. First quarter 2004 revenues also included $318,000 of net gains recognized on ineffective hedges, including unrealized gains resulting from mark-to-market valuations at the end of the period. In the first quarter of the prior year, we reported net gains of $1,354,000 on similar contracts.

     As of March 31, 2004, Prima had recorded a current liability of $4,503,000, representing the aggregate unrealized mark-to-market losses 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 quarters ended March 31, 2004 and 2003.

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

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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.

     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. INDUSTRY SEGMENT INFORMATION

     Prima organizes its activities into two operating segments consisting of: 1) the acquisition, exploration, development and operation of oil and gas properties; and 2) providing oilfield services for wells that we operate and for third-party operators. Our activities have been conducted primarily in the Rocky Mountain region of the United States, which is one geographic area.

     The information below presents the operating segment data for Prima on the basis used by management in deciding how to allocate resources and in assessing performance, which is the same basis used in the preparation of our consolidated financial statements. Total revenue by operating segment includes both sales to unaffiliated customers, as reported in our consolidated statements of income, and intersegment sales that are eliminated in consolidation, which represent oilfield services provided for Prima-operated wells. Oilfield services are priced and revenues are accounted for consistently for both unaffiliated and intersegment sales.

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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, 2004, its results of operations for the three-month periods ended March 31, 2004 and March 31, 2003, 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 $14,568,000 in the first quarter of 2004, compared to $9,196,000 in the first quarter of 2003. (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 $258,000 from the sale of oil and gas properties. During the first quarter of 2004, we invested $10,131,000 in oil and gas properties, including $9,891,000 for well costs and other development activities, primarily in the D-J Basin and on CBM properties in the Powder River Basin. Our net working capital increased from $56,148,000 at the end of 2003 to $60,890,000 at March 31, 2004, and included $61,397,000 of cash equivalents and short-term investments at the end of March 2004. Prima also continues to be free of long-term debt.

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     We currently anticipate investing approximately $45 million on property and equipment during 2004, excluding acquisitions which are unbudgeted. Projected activities for the full year include: drilling approximately 35 wells and re-fracturing or re-completing approximately 50 wells in the D-J Basin; drilling an estimated 150 CBM wells in the Powder River Basin and hooking up most of these and 130 previously-drilled CBM wells; participation in up to six wells in the Cave Gulch area; and certain exploratory activities, including operations on Prima’s Coyote Flats Prospect in Utah. We intend to focus current year CBM activities on drilling additional wells to further develop the Porcupine-Tuit field, which is producing from a relatively shallow Wyodak coal, and operations to evaluate and develop deeper unproved coals within our Kingsbury, Cedar Draw, North Shell Draw and Wild Turkey project areas.

     During the quarter ended March 31, 2004, our D-J Basin operations included drilling and completing ten gross (10 net) wells, completing two gross (2 net) wells that were drilled last year, and re-fracturing 23 gross (21.8 net) wells. Our Powder River Basin activities included drilling 14 gross (14 net) wells, deepening eight gross (8 net) wells and installing equipment, flow lines and related facilities in the North Shell Draw and Kingsbury project areas in preparation for tie-in to a gathering system later this year. We also installed additional compression equipment to bolster production rates from our 86 producing CBM wells in the Porcupine-Tuit area. Benefits began to be partially realized in April 2004 and gross production at Porcupine-Tuit at the end of that month aggregated approximately 26,000 Mcf per day, compared to an average of 24,000 Mcf per day in the first quarter of 2004 (Prima’s net revenue interests at Porcupine-Tuit average approximately 78%).

     Prima also recently participated with a 6.3% working interest in completion operations to test the over-pressured Lance formation in the Sage Flat Federal #17-20 well on the Merna Prospect, in the northern Green River Basin. Flow rates were uneconomic after the well was stimulated and Prima expects the operator to plug and abandon the well. We own an average 35% working interest in 74,000 gross acres in the greater Merna area and have received recent expressions of interest from other operators for conducting additional drilling in the area to continue to test the play.

     In addition to investments in oil and gas properties, we utilized $253,000 for acquisitions of other property and equipment during the recent quarter. No shares of treasury stock were acquired during the period, but approximately 291,000 shares of Prima’s common stock remain subject to purchase under an existing authorization from our Board of Directors.

     We have previously reported an estimate that our oil and gas production in 2004 will aggregate between 15.6 Bcfe and 16.1 Bcfe. No adjustment of that estimate is believed to be warranted at the present time. Approximately 40% of current year production is projected to come from Powder River Basin CBM properties. Most of this is expected to be derived from currently producing Porcupine-Tuit wells that will exhibit depletion-related declines during the year. Contributions from new wells in the Powder River Basin are expected to begin during the third or fourth quarter and increase as de-watering occurs. Overall, excluding acquisitions or discoveries, Prima’s net production is projected to decline through late this year or early next year, when increasing contributions from new CBM wells are expected to offset declines from other wells, particularly Porcupine-Tuit.

     Natural gas is currently expected to account for more than 80% of Prima’s total oil and gas production in 2004. Gas prices have been strong during the past several months in response to a number of factors, including recent declines in North American natural gas production and relatively high prices for oil, which can be substituted for natural gas in some applications if economically advantageous.

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     As of May 5, 2004, average prices for the CIG monthly index that have been published for 2004 (January through May) plus the average of CIG prices quoted for the remainder of 2004 in futures markets combined to average $5.25 per MMBtu of natural gas. This compares to average closing prices for the CIG monthly index during 2003 of $4.04 per MMBtu of natural gas. There is no assurance, however, that prices reflected in futures markets will actually be realized, except to the extent that fixed price or hedging contracts are entered into.

     As of the close of business on May 5, 2004, we had open contracts for forward sales of 5,050,000 MMBtu of natural gas and 160,000 barrels of crude oil, as well as certain basis differential contracts. These positions relate to the period from June 2004 through March 2005 and are summarized in Item 3, Part I of this report.

     We plan 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.

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 approximately 80% of our total oil and gas production mix. After reaching record high levels early in 2001, gas prices declined significantly until early 2003 when prices again approached record levels, and prices have generally remained at favorable levels into 2004. These price movements

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have significantly impacted our operating results. 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 2003, CIG gas prices averaged approximately $0.65 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)&