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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 September 30, 2002

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 [  ]

As of November 1, 2002 the Registrant had 12,761,385 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 September 30, 2002 and for the nine-month periods ended September 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 September 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. 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.

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     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 Rocky Mountains Colorado Interstate Gas (“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 nine months of 2002, Prima recognized aggregate net losses of $3,193,000 relating to oil and gas derivatives. This total was comprised of $413,000 of hedging losses reported within oil and gas sales and $2,780,000 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 nine months of the prior year, $2,825,000 of realized hedging gains were included in oil and gas sales and $5,552,000 of additional gains, including mark-to-market adjustments, were reported on positions not qualifying for hedge accounting.

     During the third quarter of 2002, Prima recognized aggregate net losses of $397,000 relating to oil and gas derivatives. This total was comprised of $254,000 of hedging losses reported within oil and gas sales and $143,000 of reported losses on positions not qualifying for hedge accounting. In the third quarter of 2001, $1,575,000 of realized hedging gains were included in oil and gas sales and $5,552,000 of gains, including mark-to-market adjustments, were reported on positions not qualifying for hedge accounting.

     As of September 30, 2002, Prima had recorded a net current liability of $512,000, representing the aggregate unrealized mark-to-market losses for its open derivative positions at that date. These positions are summarized below:

     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.

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3. 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 nine months ended September 30, 2002 and 2001.

4. SALE OF ASSETS

     On March 5, 2002, Prima sold all of its producing wells in the Stone’s Throw coal bed methane 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 $13,527,000 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.

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5. 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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     The following discussion is intended to assist in understanding Prima’s financial position at September 30, 2002, its results of operations for the three- and nine- month periods ended September 30, 2002 and September 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 nine months of 2002, net cash provided by Prima’s operating activities before changes in operating assets and liabilities totaled $14,524,000, and we also received cash proceeds totaling approximately $13,544,000 from the sale of certain oil and gas properties. Our new investments in oil and gas properties during the period aggregated approximately $12,160,000. Reflecting these developments, Prima’s net working capital increased from $28,122,000 at the end of 2001 to $37,446,000 at September 30, 2002. Net working capital at the end of September 2002 included cash equivalents and short-term investments totaling $38,941,000, 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 nine months 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 $512,000 at the end of September 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. 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 and third quarters 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 coal bed methane (“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 $12,160,000 invested in oil and gas properties during the first nine months of 2002 included $10,653,000 on well costs and other development activities and $1,507,000 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, 31 (28.9 net) CBM wells in the Powder River Basin and one (0.1 net) well in the Cave Gulch Field in the Wind River Basin; refracturing or recompleting 29 (25.7 net) wells in the Denver Basin; and building infrastructure for the Porcupine-Tuit CBM project. All of the drilling, refracturing and recompletion operations conducted in 2002 through September have been successful and the wells have been placed or re-placed on production, or are

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scheduled for hook-up. During the nine months of 2002, the Company also expended $496,000 for other property and equipment and $1,669,000 for the purchase of approximately 81,000 shares of treasury stock.

     We deferred some 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 generally remained weak until colder weather developed recently. The EIS issuance date is now expected to be delayed until February 2003 to allow more time to consider public comments related to the draft statement. We presently anticipate that current year capital investments for oil and gas operations will approximate $25 million, excluding proved property acquisitions, which are pursued without an established budget.

     Approximately one-half of Prima’s planned 2002 investment activities are scheduled for the final quarter of the year. These include participating in drilling approximately 12 development wells in the Denver Basin, 27 CBM wells in the Powder River Basin, four exploitation wells in the Cave Gulch Field in the Wind River Basin, and one exploratory well on the Wasatch Plateau. Additional activities planned for the fourth quarter include expansion of infrastructure on the Porcupine-Tuit CBM project in the Powder River Basin, and conducting approximately 10 refracturing or recompletion operations in the Denver Basin.

     Prima commenced production in late July 2002 from the 27 Wyodak coal bed wells that had been drilled through mid-year in the Porcupine-Tuit project area. Production rates from these wells, which comprised the first phase of development at Porcupine-Tuit, have generally increased as de-watering has occurred and compression capacity has been added. The Porcupine-Tuit wells produced an aggregate 317 MMcf of gross gas (222 MMcf net) in the quarter ended September 30, 2002, and at the end of October were producing at a combined average gross rate of approximately 10 MMcf per day. We have also now completed drilling all 35 wells planned for phase two of this project and plan to hook up 31 of these wells in the current quarter. We intend to hook-up the remaining four wells during the first half of 2003, along with wells scheduled to be drilled during the third phase of development at Porcupine-Tuit. This next phase will commence as soon as practicable after approvals are received for 26 drilling permits for which applications have been submitted. We anticipate that these permits will be issued near the end of the year. Prima’s net working and revenue interests in the 88 wells that will comprise these three development phases at Porcupine-Tuit average approximately 91% and 77%, respectively.

     During July 2002, we drilled the first four of 14 wells scheduled to be drilled in the current year within the Kingsbury CBM project area. In October, we commenced drilling the remaining ten wells included in this program, which represents Prima’s first deep-coal pilot project, designed to begin testing two coals found at depths between 1,500 feet and 2,000 feet. We anticipate having all 14 of these wells, and two similar test wells drilled at Kingsbury in 2001, on pump by year-end, but do not expect to see gas production for some period of time as de-watering occurs. These deeper coals have not yet been extensively developed in the area.

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     During the third quarter of 2002, a third-party drilled and set pipe on the Miller Federal #7-4 test well on the Merna Prospect in Sublette County, Wyoming. Operations were then temporarily suspended pending completion and hook-up of the well to a sales line. This well targeted the Cretaceous Lance and Mesaverde formations, which are under extensive development on the Pinedale Anticline, located ten to 30 miles to the southeast. The operator of the well recently completed installation of a 35-mile natural gas pipeline to facilitate extended production testing of the well, and has resumed operations to complete the well with a series of fracture stimulations. Production is expected to commence before year-end. Prima owns a 3% overriding royalty and a 12.5% after-payout reversionary interest in the Miller Federal #7-4 exploratory well and also retains interests ranging from 12.5% to 50% in approximately 72,000 gross undeveloped acres in the greater Merna area.

     Prima owns approximately 74,000 gross (71,000 net) acres within its Coyote Flats Prospect, located on the Wasatch Plateau, 15 to 25 miles northwest of Price, Utah. The primary exploratory objectives at Coyote Flats are coal bed sequences in the Emery formation, and the Ferron sandstone, both found in the Cretaceous section. Prima commenced drilling the Scofield-Thorpe #22-41, a 100%-owned exploratory test well on the Coyote Flats Prospect, on September 13. Difficulties encountered while drilling have significantly extended the drilling time for the well and approximately doubled the projected cost of the completed well from the initial estimate of $900,000. As of November 10, the well had been drilled to a total depth of 4,192 feet and had encountered 17 Emery coal seams ranging in thickness from four feet to 18 feet, and aggregating approximately 120 net feet of coal. Based on mud-log gas shows and very preliminary analyses of data from cores samples taken while drilling, approximately 40 total feet of coals in six seams in the Emery section appear to have higher gas content and greater prospectivity at this location than the other 80 feet of coals found. Additional work will be required to assess whether the Emery coal can be commercially developed. Current plans are to continue drilling to a total depth of approximately 6,200 feet to evaluate the Ferron sand.

     With respect to current quarter operations, the Company is projecting that oil and gas production will increase from levels reported for the quarter ended September 30, 2002 by between 5% and 9%, primarily due to increased contributions expected from the Porcupine-Tuit property. This estimate is dependent upon achieving projections for commencement dates for production from new wells at Porcupine-Tuit, performance of the new wells, and other production estimates. Prima is also expecting improved average price realizations for oil and gas sales in the current period, relative to the recent quarter, based upon substantial recent improvements in Rocky Mountain gas prices, coincident with colder weather. The CIG index has improved from an average of $1.29 per MMBtu for the three months in the quarter ended September 30, 2002 and $1.20 per MMBtu in October, to $2.96 per MMBtu in November 2002. Lease operating expenses per unit of production are also expected to increase in the current quarter to between $0.30 and $0.35 per Mcfe, due to start-up expenses on Porcupine-Tuit and increased discretionary repairs and maintenance in response to improved gas markets.

     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 81,187 treasury shares in the first nine months of 2002 at a cost of $1,669,000. No shares have been acquired in the current quarter through November 8th. As of the close of business on November 8, 2002, there remained authorization to acquire approximately 403,000 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.

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     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 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 approximately $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 $2.44 discount (October 2002). This basis differential widened considerably this year during the months from May through October, resulting in depressed regional prices for Rocky Mountain gas despite relatively strong gas prices in other areas of the country. Recent spot market prices and commodity futures markets reflect improved basis differentials for the upcoming winter months, when cold weather would be expected to increase natural gas consumption within the Rocky Mountain region, reducing the need for pipeline capacity to move gas to other markets. Commodity futures markets also reflect expectations that after this coming winter season, basis differentials will remain significantly improved relative to markets during the past May-October period, due in part to anticipated pipeline capacity expansion projects that would improve access to higher-priced gas markets. 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, the timing, size and location of changes in regional gas deliverability and changes in regional gas demand.

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Quarters Ended September 30, 2002 and 2001

     Prima reported third quarter 2002 net income of $1,026,000, or $0.08 per diluted share, compared to third quarter 2001 net income of $7,067,000, or $0.54 per diluted share. The Company reported cash flows from operating activities before changes in operating assets and liabilities totaling $3,608,000 in the third quarter of 2002, compared to $9,214,000 in the comparable quarter of 2001.

     Operating results for the third quarter of 2002 included a $143,000 net loss on derivatives that were not accounted for as hedges. This amount was comprised of $332,000 of net payments on settled positions and $189,000 of unrealized gains recorded on mark-to-market adjustments. By comparison, due to a sizable NYMEX gas forward-sale position and low futures prices at the end of September 2001, $5,552,000 of gains on derivatives instruments were recorded in the third quarter of 2001, comprised of $577,000 of realized gains and an additional $4,975,000 of unrealized gains from mark-to-market adjustments. Including the respective gains and losses on derivatives, revenues totaled $7,432,000 in the three months ended September 30, 2002 and $17,175,000 in the comparable quarter of 2001.

     Oil and gas sales reported for the third quarter of 2002 totaled $5,455,000, compared to $9,163,000 for the same quarter in 2001, for a decrease of 40%. The decline was attributable to the combined effects of a 16% year-over-year decline in production volumes and a 29% reduction in average realized oil and gas prices (including the impact of derivatives accounted for as hedges).

     Prima’s natural gas production declined by 18% year-over-year, from 2,456,000 Mcf in the third quarter of 2001 to 2,002,000 Mcf in the latest quarter. The 2001 quarter included a contribution of 476,000 Mcf from the Company’s Stones Throw coal bed methane (“CBM”) property, which was sold in March 2002. After giving effect to the Stones Throw sale, gas production increased modestly. Oil production totaled 96,000 barrels in the third quarter of 2002, compared to 105,000 barrels in the same quarter of 2001, for a decrease of 9%. On an equivalent unit basis, the Company’s production declined from 3,088,000 Mcfe in the third quarter of 2001 to 2,577,000 Mcfe in the recent quarter. The declines reflected the sale of the Stones Throw CBM property, a relatively high level of activity last year in response to a strong commodity price environment during the first half of 2001, and a reduced level of drilling and re-stimulation activities since mid-2001 due to lower gas prices. In comparison to the preceding quarter, which was the first full period after the Stones Throw sale, third quarter 2002 production increased by 13%, due to initial production from the Porcupine-Tuit CBM property and higher net production from wells in the Denver Basin resulting from recent well activities and reduced line pressures.

     The average price received for natural gas production during the three months ended September 30, 2002 was $1.50 per Mcf, compared to $2.57 per Mcf in the three months ended September 30, 2001, representing a decrease of $1.07 per Mcf or 42%. Average prices received for oil during the same periods were $25.50 and $26.96 per barrel, respectively, for a year-over-year decrease of $1.46 per barrel or 5%. On an Mcf equivalent basis, the average price received for the Company’s production was $2.12 for the three months ended September 30, 2002 compared to $2.97 for the three months ended September 30, 2001. Hedging losses on oil of $254,000 were included in oil and gas revenues in the third quarter of 2002 and had the effect of decreasing average price realizations by $2.66 per barrel or $0.10 per Mcfe. Gains on oil and gas hedges aggregating $1,575,000 were included in oil and gas revenues during the third quarter of 2001, and had the effect of increasing average price realizations during the period by $0.61 per Mcf of natural gas, $0.57 per barrel of oil and $0.51 per Mcfe.

     Prima’s total production was 78% natural gas and 22% oil in 2002, compared to 80% gas and 20% oil in the prior-year period. Approximately 55% of the Company’s total oil and gas revenues in the third quarter of 2002 were derived from natural gas sales, compared to 69% in the third quarter of 2001.

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     Depletion expense for oil and gas properties was $2,320,000 in the third quarter of 2002, compared to $2,779,000 in same quarter of 2001. The rate was $0.90 per Mcfe in both periods. Depreciation of other fixed assets, which include service equipment, office furniture and equipment, and buildings, was $323,000 for 2002 and $462,000 in 2001, respectively, for a decrease of $139,000, or 30%. The lower depreciation in 2002 was attributable to the sale of certain assets that were subject to depreciation in 2001.

     Lease operating expenses averaged $0.27 per Mcfe produced in the 2002 quarter and $0.28 per Mcfe in the 2001 quarter. Production taxes per Mcfe were $0.17 and $0.21, respectively, in the 2002 and 2001 quarters, reflecting higher product prices in 2001. Total lifting costs (LOE plus production taxes) equaled 21% of oil and gas revenues in the third quarter of 2002 compared to 16% in the third quarter of 2001.

     General and administrative expenses (“G&A”), net of third party reimbursements and amounts capitalized, were $772,000 for the three months ended September 30, 2002 compared to $815,000 for the three months ended September 30, 2001. Net G&A decreased $43,000 or 5%, due to lower field office expense in Wyoming following the sale of the Stones Throw property in March 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 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 $1,964,000 in the quarter ended September 30, 2002 compared to $2,223,000 in the quarter ended September 30, 2001, for a decrease of $259,000, or 12%. The decline in revenues was attributable to reduced demand for oilfield services in the current year, which impacted both equipment utilization and billing rates. The decline was partially offset by an increase in the portion of activities conducted for third parties, to 78% in the recent quarter, compared to 66% in the same period last year. Costs of oilfield services provided to third parties were $1,642,000 in 2002 compared to $1,373,000 in 2001, for an increase of $269,000, or 20%. The increase in costs was due to the larger portion of service company operations that were conducted on behalf of third parties.

     The provision for income taxes recorded in the current quarter was equivalent to 16% of income before income taxes, compared to 31% in the prior year’s quarter, due primarily to permanent differences, such as Section 29 tax credits and statutory depletion, that did not decline proportionately with pre-tax income.

Nine Months Ended September 30, 2002 and 2001

     For the nine months ended September 30, 2002, Prima reported net income of $2,294,000, or $0.17 per diluted share, compared to net income of $21,414,000, or $1.62 per diluted share, for the nine months ended September 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 totaled $14,524,000 in the first nine months of 2002 compared to $33,523,000 in the first nine months of 2001. A large reversal of book-tax timing differences reported earlier this year resulted in the current income tax provision for the nine months ended September 30, 2002 of $1,163,000 significantly exceeding the total tax provision of $340,000.

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     The results for the first nine months of 2002 included a $2,780,000 net loss on derivatives not accounted for as hedges, comprised of $1,720,000 of net receipts on settled positions and $4,500,000 of losses recorded on mark-to-market adjustments. By comparison, results for the first nine months of 2001 included an aggregate $5,552,000 net gain on such derivatives, comprised of $577,000 of realized gains and an additional $4,975,000 of unrealized gains from mark-to-market adjustments. A substantial portion of the mark-to-market gains recorded in the third quarter of 2001 related to derivatives contracts maturing in 2002, and at the end of last year Prima’s derivatives positions had a fair value of $4,472,000. As NYMEX gas prices subsequently recovered, some previously recorded mark-to-market gains were reversed giving rise to a large portion of the unrealized mark-to-market losses reported in 2002. Including the respective gains and losses on derivatives, revenues totaled $21,557,000 in the nine months ended September 30, 2002 and $49,833,000 in the comparable period of 2001.

     Oil and gas sales reported for the first nine months of 2002 totaled $17,460,000, compared to $37,429,000 for the same period in 2001, for a decrease of 53%. The decline was attributable to the combined effects of a 14% year-over-year decline in production volumes and a 46% decrease in average prices realized per equivalent unit of oil and gas production (including the impact of derivatives accounted for as hedges).

     Prima’s net natural gas production during the first nine months of 2002 and 2001 totaled 5,834,000 Mcf and 6,775,000 Mcf, respectively, reflecting a decrease of 941,000 Mcf, or 14%. The Stones Throw CBM property contributed 768,000 Mcf of production in the 2001 period and 298,000 Mcf of production in 2002 before its sale in March. Net oil production was 279,000 barrels and 328,000 barrels for the same nine-month periods, representing a decrease of 49,000 barrels or 15%. On an equivalent unit basis, Prima’s production decreased from 8,745,000 Mcfe in the first nine months of 2001 to 7,507,000 Mcfe during the same period in 2002. The decreases reflect the impact of the Stones Throw property disposition, and reduced drilling and recompletion activities during the second half of 2001 and first half of 2002.

     The average price received for natural gas production during the nine months ended September 30, 2002 was $1.85 per Mcf, compared to $4.18 per Mcf for the nine months ended September 30, 2001, representing a decrease of $2.33 per Mcf or 56%. Average prices received for oil during the same periods were $23.90 and $27.68 per barrel, respectively, for a year-over-year decrease of $3.78 per barrel or 14%. On an Mcf equivalent basis, the average price received for the Company’s production was $2.33 for the nine months ended September 30, 2002 compared to $4.28 for the nine months ended September 30, 2001. Hedging losses on oil of $413,000 were included in oil and gas revenues for the nine months of 2002 and had the effect of decreasing average price realizations by $1.48 per barrel or $0.05 per Mcfe. Gains on oil and gas hedges aggregating $2,825,000 were included in oil and gas revenues for the first nine months of 2001, and had the effect of increasing average price realizations during the period by $0.41 per Mcf of natural gas, $0.26 per barrel of oil and $0.32 per Mcfe.

     Prima’s total production in the first nine months of 2002 was 78% natural gas and 22% oil, compared to 77% gas and 23% oil in the prior-year period. Approximately 62% of total oil and gas revenues in 2002 were derived from natural gas sales, compared to 76% in 2001.

     Depletion expense for oil and gas properties was $6,757,000, or $0.90 per Mcfe, in 2002, compared to $6,399,000, or $0.73 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 was $966,000 and $1,040,000 for 2002 and 2001, respectively.

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     LOE incurred during the nine months ended September 30, 2002 averaged $0.30 per Mcfe produced, compared to $0.27 per Mcfe for the nine months ended September 30, 2001. Production taxes per Mcfe averaged $0.19 and $0.33, respectively, for the same periods, reflecting higher product prices in 2001. Total lifting costs (combining LOE and production taxes) equaled 21% of oil and gas revenues and $0.49 per Mcfe for the first nine months of 2002, compared to 14% and $0.60 per Mcfe for the same 2001 period.

     G&A, net of third party reimbursements and amounts capitalized, was $2,388,000 for the nine months ended September 30, 2002 compared to $2,823,000 for the nine months ended September 30, 2001. Net G&A decreased $435,000 or 15% due to higher reimbursements from third parties and increased amounts capitalized. Capitalized G&A increased from $1,087,000 in 2001 to $1,458,000 in 2002, reflecting additional costs associated with our exploration, development and acquisition activities.

     Reflecting an increased portion of activities conducted for third parties, oilfield service revenues grew by 7%, from $6,005,000 in the first nine months of 2001 to $6,403,000 during the latest nine-month period, despite lower equipment utilization and billing rates. Costs of oilfield services were $5,122,000 for the nine months ended September 30, 2002, compared to $3,886,000 for the same period of 2001, an increase of $1,236,000 or 32%, due to the higher portion of costs incurred associated with operations for third parties. For the nine months ended September 30, 2002, 84% of fees billed by the service companies were for third parties, compared to 63% during the nine months ended September 30, 2001.

     The provision for income taxes in the first nine months of 2002 equaled 13% 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

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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.

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.

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     We made cash payments totaling $227,000 to settle derivatives positions that were closed in the fourth quarter of 2002 through November 8. At the close of business on November 8, 2002, a mark-to-market valuation of open oil and gas derivatives positions showed net unrealized losses aggregating $129,000, 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.

     During the first nine months of 2002, Prima sold 279,000 barrels of oil. A hypothetical decrease of $2.82 per barrel (10% of average prices for the period excluding hedging transactions) would have decreased our production revenues by $787,000 for that period. Prima sold 5,834,000 Mcf of natural gas during the first nine months of 2002. A hypothetical decrease of $0.19 per Mcf (10% of average prices for the period excluding hedging transactions) would have decreased our production revenues by $1,108,000 for that period.

ITEM 4. CONTROLS AND PROCEDURES

     Prima’s principal executive officer and principal financial officer have 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”
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

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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.

PART II. OTHER INFORMATION

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

     During the nine months ended September 30, 2002, Prima issued options to acquire a total of 194,000 common shares that were not registered under the Securities Act of 1933, as amended. The options were issued as follows:

•

Options to acquire a total of 22,500 common shares were granted by Prima to directors of Prima under the terms of Prima’s Non-Employee Directors’ Stock Option Plan.

•

Options to acquire a total of 171,500 common shares were granted to certain 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 filed S-8 registration statements with the Securities and Exchange Commission for the Prima Energy Corporation Non-Employee Directors’ Stock Option Plan and the Prima Energy Corporation 2001 Stock Incentive Plan on November 7, 2002.

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 September 30, 2002, the Company filed the following reports on Form 8-K:

•

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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•

Report dated August 14, 2002 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.

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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CERTIFICATIONS

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.

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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.

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