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SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

Commission file number 0-9408

PRIMA ENERGY CORPORATION

(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 [  ]

As of August 2, 2002, the Registrant had 12,774,985 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 INCOME
(UNAUDITED)

See accompanying notes to unaudited consolidated financial statements.

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PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)

See accompanying notes to unaudited consolidated financial statements.

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PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

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 June 30, 2002 and for the six-month periods ended June 30, 2002 and 2001 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 June 30, 2002. Results for interim periods are not necessarily indicative of results to be expected for our full fiscal year ending December 31, 2002.

     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, 2001.

2. CEILING LIMIT

     On a quarterly basis, Prima is required to review the carrying value of its oil and gas properties under the full cost accounting rules of the Securities and Exchange Commission, and a non-cash impairment charge is required if the capitalized costs of the Company’s proved oil and gas properties exceed a “ceiling” calculated in accordance with such rules. Application of this ceiling test generally requires calculating the present value of future net revenues from estimated proved reserves using a 10% discount rate and unescalated “spot” prices in effect as of the last day of each quarter. At June 30, 2002, spot prices applicable to Prima’s natural gas sales were temporarily depressed to a level whereby its capitalized costs exceeded the ceiling by approximately $8 million. This calculation was based on a spot price for gas delivered into the Colorado Interstate Gas (“CIG”) system of $1.05 per MMBtu. However, the CIG spot price had increased to a level above $1.50 per MMBtu at the time these financial statements were completed. Using this higher price without escalation, the calculated present value of projected future net revenues, discounted at 10%, from Prima’s estimated proved oil and gas reserves once again exceeded its capitalized costs and, as a result, a write-down as of June 30, 2002 was not required. Longer-term quotations on futures markets for CIG gas have remained well above recent price levels, with a three-year market quote of approximately $3.00 per MMBtu as of August 1, 2002. However, short-term natural gas prices are highly volatile and a write-down may be a required at a future date, including, potentially, at the end of the current quarter, depending on then-current spot prices. A ceiling limit write-down, if recorded, would not affect Prima’s historical or future cash flows and would have the effect of reducing subsequently-reported depletion expense.

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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 or reductions in basis differentials.

     Prima adopted Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), effective January 1, 2001. SFAS 133 established accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts. SFAS 133 prescribes that the fair value of all derivatives should be recognized as either assets or liabilities in the statement of financial position. If a cash flow hedge qualifies for hedge accounting under SFAS 133, and is designated as such by Prima management when the contract is initiated, changes in the fair value of the derivative are recorded in other comprehensive income until the hedged item affects earnings, at which time any realized gain or loss is recognized in the income statement. If a cash flow hedge does not qualify for hedge accounting under SFAS 133, or if we so elect when the contract is initiated, changes in the fair value of the derivative are immediately recognized in earnings.

     Pursuant to SFAS 133 requirements, and based on 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 cash flow hedges. Derivatives based on NYMEX gas prices will not so 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.

     Our adoption of SFAS 133 as of January 1, 2001 resulted in the recognition of a current asset of $1,241,000, a current liability of $549,000, and net-of-tax cumulative effect adjustments reducing other comprehensive income by $129,000 and increasing net income by $611,000. The $611,000 is reflected as the cumulative effect of a change in accounting principle in financial statements for the first quarter of 2001.

     During the first six months of 2002, Prima recognized aggregate net losses of $2,796,000 relating to oil and gas derivatives. This total was comprised of $158,000 of hedging losses reported within oil and gas sales and $2,638,000 of reported losses, including mark-to-market adjustments, on positions not qualifying for hedge accounting. The losses recognized on positions not qualifying for hedge accounting primarily represented reversals of previously recorded mark-to-market gains, following improvements in NYMEX gas prices since the end of 2001. In the first six months of the prior year, $1,250,000 of realized hedging gains were included in oil and gas sales.

     During the second quarter of 2002, Prima recognized aggregate net losses of $87,000 relating to oil and gas derivatives. This total was comprised of $157,000 of hedging losses reported within oil and gas sales and $70,000 of reported gains on positions not qualifying for hedge accounting. In the second quarter of 2001, $828,000 of hedging gains were included in oil and gas sales.

     As of June 30, 2002, Prima had recorded a current liability of $829,000, 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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     Oil and gas prices are volatile and the market value of these derivatives will change as the underlying commodity futures prices change. Mark-to-market adjustments could result in significant earnings volatility. The actual gains or losses realized will depend on the applicable futures prices in effect at the time such positions expire or are closed.

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 and six months ended June 30, 2002 and 2001.

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5. SALE OF ASSETS

     On March 5, 2002, Prima sold all of its producing wells in the Stone’s Throw CBM project in the northern Powder River Basin, along with associated gathering system facilities and approximately 35,000 net undeveloped acres in the Stone’s Throw area. Net proceeds from the transaction totaled $13,539,000 after normal closing adjustments and were credited to the carrying value of oil and gas properties. These properties accounted for approximately 6.1% of Prima’s total estimated proved oil and gas reserves and 4.5% of the related estimated present value of future net cash flows before income taxes, as of the end of 2001. The producing wells sold accounted for approximately 17% of Prima’s net oil and gas production and 8% of its total oil and gas sales revenue before hedging effects during the first two months of 2002.

6. NEW ACCOUNTING PRONOUNCEMENTS

     In June 2001, the FASB issued SFAS No. 142, “Goodwill and Other Intangible Assets.” This statement applies to intangibles and goodwill acquired after June 30, 2001, as well as goodwill and intangibles previously acquired. Under this statement, goodwill as well as other intangibles determined to have an infinite life will no longer be amortized. These assets will be reviewed for impairment on a periodic basis. This statement was effective for the Company in the first quarter of 2002. The adoption of this statement has not had a material effect on our financial position or results of operations.

     In June 2001, the FASB issued SFAS No. 143 “Accounting for Asset Retirement Obligations.” SFAS No. 143 provides the accounting requirements for retirement obligations associated with long-lived assets and requires the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset

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retirement costs are capitalized as part of the carrying costs of the asset. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002, and early adoption is permitted. We are currently assessing, but have not yet determined, the impact of SFAS No. 143 on our financial position, results of operations, or cash flows.

     In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 requires that long-lived assets be measured at the lower of carrying amount or fair value less costs to sell, whether reported in continuing operations or in discontinued operations. Therefore, discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. SFAS No. 144 is effective for financial statements issued for fiscal years beginning after December 15, 2001 and generally is to be applied prospectively. The adoption of this statement has not had a material effect on our financial position or results of operations.

     In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” FASB No. 4 required all gains or losses from extinguishment of debt to be classified as extraordinary items net of income taxes. SFAS No. 145 requires that gains and losses from extinguishment of debt be evaluated under the provisions of Accounting Principles Board Opinion No. 30, and be classified as ordinary items unless they are unusual or infrequent or meet the specific criteria for treatment as an extraordinary item. This statement is effective January 1, 2003. We do not anticipate that the adoption of this statement will have a material effect on our financial position or results of operations.

     In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated With Exit or Disposal Activities.” This Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” This Statement requires recognition of a liability for a cost associated with an exit or disposal activity when the liability is incurred, as opposed to when the entity commits to an exit plan under EITF No. 94-3. SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. We do not anticipate that the adoption of this statement will have a material effect on our financial position or results of operations.

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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 June 30, 2002, its results of operations for the three- and six- month periods ended June 30, 2002 and June 30, 2001, and our assessments of Prima’s liquidity and capital resources.

Liquidity and Capital Resources

     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.

     During the first six months of 2002, net cash provided by Prima’s operating activities before changes in operating assets and liabilities totaled $10,916,000, and we also received cash proceeds totaling approximately $13,553,000 from the sale of certain oil and gas properties. Our new investments in oil and gas properties during the period aggregated approximately $6,713,000. Prima’s net working capital increased from $28,122,000 at the end of 2001 to $39,379,000 at June 30, 2002. Net working capital at the end of June 2002 included cash equivalents and short-term investments totaling $40,019,000, compared to $25,755,000 at the end of 2001, and Prima was free of long-term debt at both dates.

     The overall increase in net working capital in the first half of 2002 occurred despite a swing in the mark-to-market value of our derivatives positions from a net asset of $4,472,000 at the end of 2001 to a net liability of $829,000 at the end of June 2002. These derivatives positions have primarily represented exchanges of floating for fixed prices for natural gas and oil, as traded on the New York Mercantile Exchange. We received net proceeds of approximately $2,052,000 from derivatives positions that were closed during the first six months of 2002, including $2,450,000 collected in the first quarter and $398,000 paid in the second quarter, while the value of the remaining positions was reduced by increases in oil and gas prices quoted in futures markets. Generally, higher market prices for oil and gas decrease the value of our commodity derivatives but increase the prices we receive for the sales of our production. As further discussed below, the differentials between market prices for natural gas sold in the Rocky Mountain region and in other major markets, such as the Gulf Coast, widened significantly in the second quarter of 2002, negatively impacting our gas sales revenue and reducing the effectiveness of our NYMEX gas derivatives in offsetting the decline.

     The assets sold consisted primarily of our Stones Throw CBM project in the northern Powder River Basin, the associated gathering system and approximately 35,000 net undeveloped acres in the Stones Throw area. These properties accounted for approximately 6.1% of Prima’s total estimated proved oil and gas reserves and 4.5% of the related estimated present value of future net cash flows before income taxes, as of the end of 2001. The transaction was closed on March 5, 2002. The producing wells sold accounted for approximately 17% of Prima’s net oil and gas production and 8% of its total oil and gas sales revenue before hedging effects during the first two months of 2002.

     The $6,713,000 invested in oil and gas properties during the first six months of 2002 included $5,729,000 on well costs and other development activities and $984,000 for undeveloped acreage, principally in Utah and the Powder River Basin. Well costs and other development expenditures were incurred principally in drilling four (3.4 net) wells in the Denver Basin and four (2.85 net) CBM wells in the Powder River Basin, refracturing or recompleting 21 (18.0 net) wells in the Denver Basin, and

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building infrastructure in the Porcupine-Tuit CBM area. All of the drilling, refracturing and recompletion operations were successful and the wells have been placed or re-placed on production. During the first half of 2002, the Company also expended $277,000 for other property and equipment and $966,000 for the purchase of approximately 39,000 shares of treasury stock.

     We deferred certain investments earlier in the year to benefit from anticipated improvements in gas prices and service costs. Certain investments in the Powder River Basin CBM play were also delayed to take advantage of developing infrastructure, activities of other operators, and the expected issuance by October 2002 of a Bureau of Land Management record of decision concerning an environmental impact statement (EIS) for area-wide CBM development in the Powder River Basin. Approximately 82% of Prima’s Powder River Basin acreage is federal and access to federal lands has been limited pending completion of the EIS. The pace of our expenditures has continued to be moderated by these factors and ongoing efforts to coordinate development of CBM properties with other operators to realize efficiencies. Although gas prices in other regions of the country have recovered since early in the year, natural gas prices in the Rocky Mountain region have generally remained weak, and the EIS issuance date is now expected to be delayed until December 2002 or early 2003 to allow more time to consider public comments related to the draft statement. We presently anticipate that current year capital investments, excluding acquisitions which are unbudgeted, will be near the lower end of our previously announced target range of $25 million and $30 million, but such investments could be further increased or decreased depending on market conditions.

     Activities currently planned for the second half of 2002 include drilling approximately ten development wells in the Denver Basin, 60 CBM wells in the Powder River Basin, and one exploratory well in Utah. Additional planned 2002 activities provide for investments in various hook-up and infrastructure facilities, including expansion of the Porcupine-Tuit CBM project in the Powder River Basin, and conducting approximately 20 refracturing or recompletion operations in the Denver Basin. A portion of the 2002 budget has also been reserved for acquisition of additional acreage for future exploration or exploitation, or for other opportunities identified during the year.

     Prima commenced production in late July 2002 from the 27 Wyodak coal wells that had been drilled through mid-year in the Porcupine-Tuit project area. Initial rates have been in line with expectations, with aggregate gas production averaging approximately 2,300 Mcf (gross) per day, while the wells are continuing to de-water. Water production rates confirm favorable permeability in the coals. An additional 61 locations have been identified in this project area for near-term drilling, including 35 for which drilling permits were recently obtained. We anticipate having approximately 60 wells on production in the Porcupine-Tuit project area by the end of the year, with all 88 planned wells on-line by the end of the second quarter of 2003. Production reported for wells in the Porcupine-Tuit area owned by other operators has generally been averaging 150 to 250 Mcf per day, with several wells averaging in excess of 350 Mcf per day, after typical de-watering periods of six to nine months. Although projections at this early stage are tentative, Prima expects its wells in this area to exhibit similar production performance.

     During July 2002, we drilled the first four of 14 wells scheduled for the current year in the Kingsbury CBM project area. These wells are part of the Prima’s first deep coal pilot project, intended to begin testing two coals found at depths between 1,500 feet and 2,000 feet. We expect to have all 14 of these wells on pump by year-end.

     Another company is drilling a third-quarter 2002 test well on the Merna Prospect, located in Sublette County, Wyoming, to evaluate the Cretaceous Lance and Mesaverde formations, which are under extensive development on the Pinedale Anticline ten to 30 miles to the southeast. The operator of this test

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well has indicated that it plans to install a 35-mile six-inch diameter natural gas pipeline later this year to facilitate extended production testing of the well. Prima owns approximately 72,000 gross (28,000 net) undeveloped acres in the prospect area, subject to a farmout agreement covering a portion of the acreage, which includes the drill site for the current well. Prima has a 3% overriding royalty and a 12.5% after-payout reversionary interest in this exploratory well, and its working interest in the remainder of the project area varies from 12.5% to 50%.

     Prima plans to commence drilling a 100%-owned exploratory test well on the Coyote Flats Prospect in September 2002. Prima owns approximately 74,000 gross (71,000 net) acres within this prospect area, which is located on the Wasatch Plateau, 15 to 25 miles northwest of Price, Utah. Our objectives at Coyote Flats will be to test the hydrocarbon potential of sandstone and coal bed reservoirs in the Blackhawk, Emery, Ferron and Dakota members of the middle to lower Cretaceous section. The well is projected to cost approximately $900,000 to drill, test and complete.

     Prima’s average daily net production in the first quarter of 2002 totaled approximately 29,400 Mcfe, or 25,800 Mcfe excluding amounts contributed by the Stones Throw property that was sold in early March. During the second quarter of 2002, our average daily net production totaled approximately 25,100 Mcfe. In the absence of an acquisition, we do not expect significant production from new sources in the near-term other than potentially from our Porcupine-Tuit CBM project noted above, where a typical well’s expected production profile would reflect an increase in gas production to peak rates over a period of several months as coals de-water.

     In January 2001, Prima’s Board of Directors approved a repurchase program of up to 5% of the Company’s common stock then outstanding, or approximately 640,000 shares. Pursuant to this program, Prima acquired 39,387 treasury shares in the first six months of 2002 at a cost of $966,000 and an additional 25,200 shares in the third quarter of 2002 through August 5, for $426,000. As of the close of business on August 5, 2002, there remained authorization to acquire approximately 420,000 additional shares of Prima’s outstanding common stock under this buyback program.

     We expect to fund our 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. Although a specific budget for such acquisitions has not been established, Prima continues to pursue these opportunities on an ongoing basis. If a sufficiently large transaction is consummated, it could involve the incurrence of debt or issuance of equity securities.

Results of Operations

     As noted above, Prima’s 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, operating results for any period are not necessarily indicative of future operating results.

     Historically, oil and natural gas prices have been volatile and are likely to continue to be volatile. Prices are affected by, among other things, market supply and demand factors, market uncertainty, and actions of the United States and foreign governments and international cartels. These factors are beyond our control. Prima’s revenues, cash flows, earnings and operations are adversely affected when oil and gas prices decline. Gas prices declined significantly after reaching record high levels early in 2001, which has unfavorably impacted our operating results year to date in 2002, compared to the prior year, as further discussed below. We cannot accurately predict future oil and natural gas prices, but historically oil and

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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. Since 1991, CIG gas prices have averaged $0.51 per MMBtu less than the average for gas at Henry Hub, but the amount of this discount has ranged on an annual basis between $0.26 (1999) and $1.10 (1996), and monthly variances in index prices have ranged between an $0.11 premium (January 1993) and a $2.19 discount (July 2002). Since May of this year this basis differential has widened considerably, resulting in depressed regional prices for Rocky Mountain gas despite relatively strong gas prices in other areas of the country. Recent commodity futures markets quotations indicate expectations that basis differentials will significantly improve during the coming winter months, when cold weather typically increases natural gas consumption within the Rocky Mountain region and reduces the need for pipeline capacity to move gas to other markets. These commodity futures markets also reflect expectations that basis differentials will remain significantly improved relative to current markets after this coming winter season, based, in part, on anticipated implementation of pipeline capacity expansion projects that are expected to improve access to higher priced markets when completed. Future basis differentials, which we expect to have an important impact on Prima’s 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.

Quarters Ended June 30, 2002 and 2001

     Prima reported second quarter 2002 net income of $1,990,000, or $0.15 per diluted share. This compares to second quarter 2001 net income of $5,671,000, or $0.43 per diluted share. Cash flows from operating activities before changes in operating assets and liabilities totaled $3,978,000 in the second quarter of 2002, compared to $10,606,000 in the comparable quarter of 2001. Cash flows before working capital changes for the recent quarter reflect a current tax provision of $973,000, which exceeded the total income tax provision for the quarter of $480,000, due to the reversal of various timing differences, including gains on derivatives and asset sales.

     Our operating results for the second quarter of 2002 included an aggregate $87,000 net loss on derivatives. This amount includes settlement gains and losses on positions accounted for as hedges, which are included in oil and gas sales, and amounts related to other oil and gas derivatives (including mark-to-market adjustments) reported as net gains or losses on derivatives instruments. The net loss on derivatives was comprised of $635,000 of settlement costs on positions related to production months during the quarter and $548,000 of mark-to-market gains. In the second quarter of 2001, $828,000 of hedging gains were included in oil and gas sales.

     Revenues for the 2002 quarter totaled $8,718,000 compared to $14,188,000 in the second quarter of 2001. Oil and gas sales reported for the second quarter of 2002 totaled $6,121,000, compared to $11,909,000 for 2001, for a decrease of 49%. This decline was attributable to the combined effects of a 21% year-over-year decline in production volumes and a 35% reduction in average oil and gas price realizations.

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     Prima’s natural gas production declined by 22%, from 2,220,000 Mcf in the second quarter of 2001 to 1,729,000 Mcf in the latest quarter. The 2001-quarter included a contribution of 200,000 Mcf from the Stones Throw CBM property, which was sold in March 2002. Oil production totaled 93,000 barrels in the second quarter of 2002, compared to 112,000 barrels in the same quarter of 2001, for a decrease of 17%. On an equivalent unit basis, Prima’s production declined from 2,892,000 Mcfe in the second quarter of 2001 to 2,286,000 Mcfe in the recent quarter. The declines reflected a high level of activity last year in a strong commodity price environment, a reduced level of drilling and re-stimulation activities since mid-2001 due to lower gas prices, the sale of the Stones Throw CBM project in the first quarter of 2002, and recent high line pressures in the Denver Basin which have constricted production.

     Average sales prices received for natural gas production were $2.23 per Mcf in the second quarter of 2002 and $3.97 per Mcf in the 2001 quarter, representing a year-over-year decrease of $1.74 per Mcf, or 44%. Average prices received per barrel of oil were $24.47 in the recent quarter and $27.55 in the same period last year, for a decrease of $3.08 per barrel or 11%. On an energy equivalent basis, the average price received was $2.68 per Mcfe in the latest quarter compared to $4.12 per Mcfe in the prior year period.

     Prima’s total production was 76% natural gas and 24% oil in 2002, compared to 77% gas and 23% oil in the prior-year period. Approximately 63% of Prima’s total oil and gas revenues in the second quarter of 2002 was derived from natural gas sales, compared to 74% in the second quarter of 2001.

     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 $2,354,000 in the quarter ended June 30, 2002 compared to $2,006,000 in the quarter ended June 30, 2001, for an increase of $348,000, or 17%. Costs of oilfield services provided to third parties were $1,745,000 in 2002 compared to $1,379,000 in 2001, for an increase of $366,000, or 27%. Higher revenues and costs in the current year reflect increases in the amount of equipment placed in service and a greater portion of services provided to third parties. Service fees and costs associated with Prima-owned property interests represented 14% of the service companies’ activities in 2002 compared to 39% in 2001. The year-over-year decline in operating margins for Prima’s oilfield service operations reflects lower equipment utilization and rate reductions in 2002 due to reduced overall market demand for such services.

     Depletion expense for oil and gas properties was $2,058,000, or $0.90 per Mcfe, in 2002, compared to $1,852,000, or $0.64 per Mcfe, in 2001. The depletion rate per Mcfe was increased mid-year 2001, due to a number of factors, including: significant declines in oil and gas prices, which, under the methodology prescribed, affects estimates of oil and gas reserves that can be economically recovered through future production; increases in oilfield service costs, which impacted the assumptions required to be used in estimating future development costs; and use of more conservative assumptions for estimating undeveloped CBM reserves, pending additional performance-related data.

     Depreciation of other fixed assets, which include service equipment, office furniture and equipment, and buildings, was $321,000 and $296,000 for 2002 and 2001, respectively. The increase of $25,000, or 8%, was due primarily to acquisitions of oilfield service equipment in 2001.

     Lease operating expenses (“LOE”) totaled $771,000 for the three months ended June 30, 2002 compared to $651,000 for the three months ended June 30, 2001, an increase of $120,000 or 18%. LOE averaged $0.34 per Mcfe produced in the 2002 quarter compared to $0.23 per Mcfe in the 2001 quarter. The increased LOE per unit reflected fewer current year additions of high-rate new wells or re-stimulation

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operations, which generally lower average costs per unit of production, as well as the negative impact on production of high line pressure in the Denver Basin late in the quarter, and the smaller production base in Wyoming over which to spread field office expenses after the Stones Throw asset sale. Ad valorem and other production taxes totaled $509,000 and $869,000 for the same periods, a decrease of $360,000 or 41%. Production taxes fluctuate with revenues and changing mill levy rates, and the year-over-year decline was primarily attributable to lower oil and gas sales. Production taxes averaged $0.22 and $0.30 per Mcfe in the 2002 and 2001 quarters, respectively. Total lifting costs (LOE plus ad valorem and production taxes) were 20% of oil and gas revenues in the second quarter of 2002 compared to 13% in the second quarter of 2001.

     General and administrative expenses (“G&A”), net of third party reimbursements and amounts capitalized, were $844,000 for the three months ended June 30, 2002 compared to $920,000 for the three months ended June 30, 2001. Net G&A decreased $76,000 or 8% due primarily to increased amounts capitalized. Capitalized G&A increased from $300,000 in 2001 to $486,000 in 2002, reflecting additional costs associated with our exploration, development and acquisition activities.

     The provision for income taxes in the second quarter of 2002 represented 19% of income before income taxes, compared to 31% in the comparable quarter last year, due primarily to permanent differences, such as Section 29 tax credits and statutory depletion, that did not decline proportionately with pre-tax income. Although $11,746,000 of proceeds from the Stones Throw asset sale were closed into an escrow account with a qualifying intermediary to preserve the opportunity to consummate a tax-free like-kind exchange, we do not currently expect to satisfy the requirement that such properties be acquired on or before September 5, 2002 in order to defer the tax gain. The tax provision for the period ended June 30, 2002 reflects that expectation in the determination of current income taxes.

Six Months Ended June 30, 2002 and 2001

     For the six months ended June 30, 2002, Prima reported net income of $1,268,000, or $0.10 per diluted share, compared to net income of $14,347,000, or $1.08 per diluted share, for the six months ended June 30, 2001. The prior year included $611,000 of net income ($0.05 per diluted share) from the cumulative effect of adoption of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities.” Cash flows from operating activities before changes in operating assets and liabilities aggregated $10,916,000 for the first six months of 2002 compared to $24,309,000 for the first six months of 2001. A large reversal of book-tax timing differences in the first half of 2002 resulted in a current income tax provision for the period of $1,073,000, which significantly exceeded the total tax provision of $140,000.

     Prima’s operating results for the first half of 2002 included an aggregate $2,796,000 net loss on derivatives. This amount includes settlement gains and losses on positions accounted for as hedges, which are included in oil and gas sales, and amounts related to other oil and gas derivatives (including mark-to-market adjustments) reported as net gains or losses on derivatives instruments. The net loss on derivatives was comprised of $1,815,000 of net cash receipts on settlements of positions related to production months during the six-month period and $4,611,000 of mark-to-market losses. Revenue related to the net cash received during the period had mostly been included in revenues reported in 2001, through “marking to market” the carrying value of the derivatives positions at the end of December 2001. The net losses recognized in the 2002 period reflected declines in the fair value of Prima’s derivatives positions due to increases in oil and gas prices since the end of 2001. In the first half of 2001, $1,250,000 of hedging gains were included in oil and gas sales.

     Revenues for the 2002 period, which were reduced by the reported $2,796,000 loss on derivatives, totaled $14,125,000, compared to $32,658,000 for the first six months of 2001. Oil and gas

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sales reported for the first half of 2002 totaled $12,005,000, compared to $28,266,000 for 2001, for a decrease of 58%. The decline was attributable to the combined effects of a 51% decrease in average prices realized per equivalent unit of oil and gas production and a 13% year-over-year decline in production volumes.

     Prima’s net natural gas production during the first six months of 2002 and 2001 totaled 3,832,000 Mcf and 4,319,000 Mcf, respectively, reflecting a decrease of 487,000 Mcf, or 11%. Net oil production was 183,000 barrels and 223,000 barrels for the same six-month periods, representing a decrease of 40,000 barrels or 18%. On an equivalent unit basis, Prima’s production decreased from 5,657,000 Mcfe in the first half of 2001 to 4,930,000 Mcfe during the same period in 2002.

     The average price received for natural gas production during the six months ended June 30, 2002 was $2.03 per Mcf, compared to $5.10 per Mcf for the six months ended June 30, 2001, representing a decrease of $3.07 per Mcf or 60%. Average prices received for oil during the same periods were $23.06 and $28.03 per barrel, respectively, for a year-over-year decrease of $4.97 per barrel or 18%. On an Mcf equivalent basis, the average price received was $2.44 during the six months ended June 30, 2002 compared to $5.00 in the six months ended June 30, 2001.

     Prima’s total production in the first half of 2002 was 78% natural gas and 22% oil, compared to 76% gas and 24% oil in the prior-year period. Approximately 65% of total oil and gas revenues in 2002 were derived from natural gas sales, compared to 78% in 2001.

     Primarily reflecting increased utilization for third parties, oilfield service revenues grew by 17%, from $3,782,000 in the first half of 2001 to $4,439,000 during the latest six-month period. Costs of oilfield services were $3,480,000 for the six months ended June 30, 2002, compared to $2,513,000 for the same period of 2001, for an increase of $967,000 or 38%. During the six months ended June 30, 2002, 12% of fees billed by the service companies were for Prima-owned property interests, compared to 39% during the six months ended June 30, 2001.

     The following variances in costs and expenses for the six-month period ended June 30, 2002, as compared to the first six months of 2001, were generally attributable to the same causes noted above in discussing results for the quarter ended June 30, 2002.

     Depletion expense for oil and gas properties was $4,437,000, or $0.90 per Mcfe, in 2002, compared to $3,620,000, or $0.64 per Mcfe, in 2001. Depreciation of other fixed assets was $643,000 and $578,000 for 2002 and 2001, respectively.

     LOE totaled $1,576,000 for the six months ended June 30, 2002 compared to $1,450,000 for the six months ended June 30, 2001, an increase of $126,000 or 9%. Lease operating expenses averaged $0.32 per Mcfe produced in the 2002 period compared to $0.26 per Mcfe in the 2001 period. Ad valorem and other production taxes for the six months ended June 30, 2002 and 2001 totaled $965,000 and $2,293,000 respectively, a decrease of $1,328,000 or 58%. Production taxes averaged $0.20 and $0.41 per Mcfe in 2002 and 2001, respectively. Total lifting costs were 21% of oil and gas revenues in the first half of 2002 compared to 13% in the first half of 2001.

     G&A, net of third party reimbursements and amounts capitalized, was $1,616,000 for the six months ended June 30, 2002 compared to $2,008,000 for the six months ended June 30, 2001. Net G&A decreased $392,000 or 20% due primarily to lower bonus costs and increased amounts capitalized. Capitalized G&A increased from $600,000 in 2001 to $972,000 in 2002, reflecting additional costs associated with our exploration, development and acquisition activities.

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     The provision for income taxes in the first half of 2002 equaled 10% of income before income taxes, compared to 32% in the comparable period of 2001, due primarily to permanent differences, such as Section 29 tax credits and statutory depletion, that did not decline proportionately with pre-tax income.

New Accounting Pronouncements

     In June 2001, the FASB issued SFAS No. 142, “Goodwill and Other Intangible Assets.” This statement applies to intangibles and goodwill acquired after June 30, 2001, as well as goodwill and intangibles previously acquired. Under this statement, goodwill as well as other intangibles determined to have an infinite life will no longer be amortized. These assets will be reviewed for impairment on a periodic basis. This statement was effective for the Company in the first quarter of 2002. The adoption of this statement has not had a material effect on our financial position or results of operations.

     In June 2001, the FASB issued SFAS No. 143 “Accounting for Asset Retirement Obligations.” SFAS No. 143 provides the accounting requirements for retirement obligations associated with long-lived assets and requires the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying costs of the asset. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002, and early adoption is permitted. We are currently assessing, but have not yet determined, the impact of SFAS No. 143 on our financial position, results of operations, or cash flows.

     In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 requires that long-lived assets be measured at the lower of carrying amount or fair value less costs to sell, whether reported in continuing operations or in discontinued operations. Therefore, discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. SFAS No. 144 is effective for financial statements issued for fiscal years beginning after December 15, 2001 and generally is to be applied prospectively. The adoption of this statement has not had a material effect on our financial position or results of operations.

     In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” FASB No. 4 required all gains or losses from extinguishment of debt to be classified as extraordinary items net of income taxes. SFAS No. 145 requires that gains and losses from extinguishment of debt be evaluated under the provisions of Accounting Principles Board Opinion No. 30, and be classified as ordinary items unless they are unusual or infrequent or meet the specific criteria for treatment as an extraordinary item. This statement is effective January 1, 2003. We do not anticipate that the adoption of this statement will have a material effect on our financial position or results of operations.

     In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated With Exit or Disposal Activities.” This Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” This Statement requires recognition of a liability for a cost associated with an exit or disposal activity when the liability is incurred, as opposed to when the entity commits to an exit plan under EITF No. 94-3. SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. We do not anticipate that the adoption of this statement will have a material effect on our financial position or results of operations.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     Our primary market risks relate to changes in prices received on 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.

     We utilize only conventional derivatives instruments and attempt to manage credit risk by entering into derivatives contracts only on the NYMEX or with counterparties that carry an investment-grade rating and which are believed to be reputable. All derivatives transactions are executed by Prima's Chief Executive Officer, Chief Financial Officer, or Vice President of Marketing, in accordance with prescribed trading limits and parameters, including acceptable counterparty credit quality. Prima's CEO approves all transactions before they are executed and significant transactions are approved in advance by the Board of Directors. All derivatives transactions and outstanding positions are reviewed on a regular basis with Prima's Board of Directors.

     We made cash payments totaling $273,000 to settle derivatives positions that were closed during July 2002. At the close of business on July 31, 2002, a mark-to-market valuation of open oil and gas derivatives positions showed net unrealized losses aggregating $226,000, 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 six months of 2002, Prima sold 183,000 barrels of oil. A hypothetical decrease of $2.39 per barrel (10% of average prices for the period excluding hedging transactions) would have decreased our production revenues by $437,000 for that period. Prima sold 3,832,000 Mcf of natural gas during the first half of 2002. A hypothetical decrease of $0.20 per Mcf (10% of average prices for the period excluding hedging transactions) would have decreased our production revenues by $766,000 for that period.

CAUTIONARY STATEMENT FOR PURPOSES OF THE “SAFE HARBOR”
PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

     “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,” “budget,” “project” 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, 2001.

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PART II. OTHER INFORMATION

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

     During the six months ended June 30, 2002, Prima issued options to acquire a total of 177,125 common shares that were not registered under the Securities Act of 1933, as amended. The options were issued as follows:

•		Options to acquire a total of 5,625 common shares were granted by Prima to a director of Prima under the terms of Prima’s Non-Employee Directors’ Stock Option Plan.
•		Options to acquire a total of 171,500 common shares were granted to certain officers of Prima under the terms of Prima’s 2001 Stock Incentive Plan.

     No underwriter was involved in any of the transactions and no sales commissions, fees, or similar compensation were paid by Prima to any person in connection with the issuance of the options. In each case, the options granted become exercisable in 20% annual increments commencing on the first anniversary of the grant date. Prima intends to file an S-8 registration statement for the Prima Non-Employee Directors’ Stock Option Plan and the Prima 2001 Stock Incentive Plan prior to the first date on which these options become exercisable.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     On May 15, 2002, the Company held an annual meeting of stockholders. The following table sets forth certain information relating to each matter voted upon at the meeting.

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 and subsequent to June 30, 2002, the Company filed the following reports on Form 8-K:

•		Report dated May 9, 2002, reporting first quarter 2002 financial results and providing an update of operating activities and commodity hedging transactions.
•		Report dated August 6, 2002 — comprised of two reports. A press release issued August 7, 2002, reporting second quarter 2002 financial results and providing an update of operating activities and commodity hedging transactions and a press release issued August 9, 2002, correcting the previously reported cash flows for the quarter and six months ended June 30, 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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