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SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

For the quarterly period ended June 30, 2003

OR

For the transition period from         to         

Commission file number 0-9408

PRIMA ENERGY CORPORATION

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

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

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

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.         Yes   [X]   No   [   ]

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

As of July 31, 2003, the Registrant had 12,720,442 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.” All significant intercompany transactions have been eliminated.

     Financial information presented herein as of June 30, 2003 and for the six-month periods ended June 30, 2003 and 2002 is unaudited but reflects all adjustments that we believe are necessary to fairly present Prima’s financial position, results of operations and cash flows for the periods shown. Such adjustments consist only of normal recurring accruals. Certain prior-year amounts have also been reclassified to conform to classifications reflected as of June 30, 2003. Results for interim periods are not necessarily indicative of results to be expected for our full fiscal year ending December 31, 2003.

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

2. ASSET RETIREMENT OBLIGATIONS

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

     Our asset retirement obligation primarily represents the estimated present value of the amount we project will be incurred to plug, abandon and remediate our oil and gas properties at the end of their productive lives, in accordance with applicable laws and regulations. Our adoption of SFAS No. 143 as of January 1, 2003 resulted in the recognition of an increase in the carrying value of our oil and gas

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properties of $2,252,000, an increase in our deferred tax liability of $217,000, an increase in other non-current liabilities of $1,632,000, and a net-of-tax adjustment increasing net income by $403,000, which was recorded as the cumulative effect of a change in accounting principle. The estimated pro forma effect of January 1, 2002 adoption of SFAS No. 143 on net income and earnings per share for interim and annual periods in 2002 is not material. A reconciliation of Prima’s liability for the six months ended June 30, 2003 is as follows:

3. DERIVATIVES TRANSACTIONS

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

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

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

     In the first half of 2003, $359,000 of losses on derivative transactions that qualified for hedge accounting were included in oil and gas sales, compared to $158,000 of losses for the same period of 2002. In addition, we recognized net gains on derivatives instruments not qualifying for hedge accounting in the first six months of 2003 totaling $1,306,000 and net losses on such instruments in the first half of 2002 aggregating $2,638,000. These non-hedge derivatives primarily related to NYMEX gas swaps for which we did not elect to enter into corresponding swaps for Rocky Mountain basis differentials.

     As of June 30, 2003, Prima had recorded a net current asset of $806,000, representing the aggregate unrealized mark-to-market gains for its open derivative positions at that date. These positions are summarized below:

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4. EARNINGS PER SHARE

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

     The following table reconciles the net earnings and common shares outstanding that were used in the calculations of basic and diluted net income per share for the quarter and six months ended June 30, 2003 and 2002.

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5. STOCK-BASED COMPENSATION

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

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

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

6. INDUSTRY SEGMENT INFORMATION

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

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

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7. RECENT ACCOUNTING PRONOUNCEMENTS

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

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

     In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” to improve the accounting for certain financial instruments that, under previous guidance, issuers could account for as equity. SFAS No. 150 requires that those instruments be classified as liabilities in statements of financial position. SFAS No. 150 does not apply to features embedded in a financial instrument that is not a derivative in its entirety. In addition to its requirements for the classification and measurement of financial instruments within its scope, SFAS No. 150 also requires disclosures about alternative ways of settling the instruments and the capital structure of entities, all of whose shares are mandatorily redeemable. Most of the guidance in Statement 150 is effective for all financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. As we have no such financial instruments, we do not anticipate any impact on our financial position or results of operations upon adoption.

     The FASB and representatives of the accounting staff of the Securities and Exchange Commission (“SEC”) are currently engaged in discussions regarding the application of certain provisions of SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets,” to companies in the extractive industries, including oil and gas companies. The FASB and the SEC staff are considering whether the provisions of SFAS No. 141 and SFAS No.142 require registrants to classify costs associated with mineral rights, including both proved and unproved lease acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, Prima has included oil and gas lease acquisition costs as a component of oil and gas properties. In the event the FASB and SEC staff determine that costs associated with mineral rights are required to be classified as intangible assets, a portion of our oil and gas property costs incurred since the June 30, 2001 effective date of SFAS Nos. 141 and 142 would be separately classified on our balance sheets as intangible assets. However, our results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with full cost accounting rules.

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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, 2003, its results of operations for the three- and six- month periods ended June 30, 2003 and June 30, 2002, and our assessments of Prima’s liquidity and capital resources. For a summary of our critical accounting policies and estimates, please refer to our Annual Report on Form 10-K, page 30, for the year ended December 31, 2002.

Liquidity and Capital Resources

     Historically, Prima’s principal sources of liquidity have been the internal generation of cash flow from operations, proceeds from occasional asset sales, and existing net working capital. Additional potential sources of capital include borrowings and issuances of common stock or other securities. Our revenues and cash flows are substantially derived from oil and gas sales, which are dependent upon oil and gas production volumes and sales prices.

     Cash flow from operations before changes in operating assets and liabilities totaled $20,883,000 in the first six months of 2003, compared to $10,864,000 in the first six months of 2002. (This is a non-GAAP financial measure derived from net cash provided by operating activities; see “Reconciliation of Non-GAAP Financial Measure” in table below.) We also received cash proceeds totaling $1,436,000 from the sale of certain oil and gas properties, while our investments in oil and gas properties during the first half aggregated $9,513,000. Prima’s net working capital increased from $35,954,000 at the end of 2002 to $46,722,000 at June 30, 2003. Net working capital at the end of June 2003 included cash equivalents and short-term investments totaling $42,177,000, compared to $38,007,000 at the end of 2002, and we were free of long-term debt at both dates. Our contractual obligations for operating leases for office rent and compressor rentals at June 30, 2003 were as follows: within one year, $335,000; from one to three years, $634,000; and after three years, $449,000.

     Our investments during the first six months of 2003 included $426,000 for acquisitions of undeveloped acreage and $9,087,000 for well costs and other development activities. Well operations included drilling seven (6.6 net) wells in the Denver Basin, 23 (16.1 net) coalbed methane (CBM) wells in the Powder River Basin, and 6 (0.5 net) wells in the Cave Gulch area in the Wind River Basin. Additional development costs were also incurred in re-fracturing 19 (18 net) wells in the Denver Basin, completing two Denver Basin wells drilled in late 2002, and installing infrastructure facilities for early-stage projects in the CBM area. Of the asset sales proceeds realized during the period, $1,200,000 related to the sale of 1,120 gross and net acres in our Kingsbury project area in the Powder River Basin, which included eight shallow-coal CBM wells that were producing an aggregate of approximately 150 Mcf per day net to Prima when sold.

     During the six months ended June 30, 2003, Prima also utilized $632,000 for other property and equipment and $2,111,000 for the purchase of approximately 112,000 shares of treasury stock at an average cost of $18.87 per share. Approximately 291,000 additional shares of Prima’s common stock may be repurchased under an existing authorization from our Board of Directors.

     As previously reported, Prima has established a range of $25 million to $30 million for current-year investments in property and equipment, excluding acquisitions which are unbudgeted. Powder River Basin CBM activities planned for 2003 have been weighted toward the second half of the year. One factor influencing that schedule was the timing of a record of decision (ROD) issued by the Bureau of Land Management (BLM), to finalize an environmental impact statement (EIS) for the area. The ROD was issued on April 30, 2003 and is expected, ultimately, to significantly improve access to federal lands

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in the Powder River Basin for CBM development. However, as anticipated, various challenges to the ROD have been filed in federal courts and there may be delays in its implementation pending resolution of these challenges. While some of Prima’s planned activities for the balance of 2003 may be affected by the status of the BLM’s implementation of the EIS, drilling activity conducted during the year will also be dependent on other factors. These include the timing and conditions of approvals required for certain water management plans, completion of agreements with various surface owners, and conclusion of negotiations with certain working interest owners regarding potential acreage swaps.

     Our planned activities for the second half of 2003 include drilling 75 to 100 CBM wells and investing in infrastructure facilities to enable hook-up of up to 200 wells in the Powder River Basin by early 2004. Activities are planned for several of our project areas in this CBM play. At Porcupine-Tuit, we are planning on drilling 24 and hooking-up 28 wells, including the new wells and four that were previously-drilled. In mid-July, Prima received some of the first permits issued under the new EIS for these Porcupine-Tuit wells, and we initiated drilling on August 1. In the area encompassing our North Shell Draw and Cedar Draw projects, where Prima has 59 previously-drilled wells awaiting hook-up, we are planning to deepen 16 of these wells to lower coals, drill 30 to 50 additional wells, and install (or arrange for installation of) gathering and compression facilities to tie these wells into a sales line. Current year plans also call for drilling 20 to 30 additional wells in the Kingsbury area, where Prima has a pilot program with 16 wells on pump to begin evaluating two coals at depths between 1,600 feet and 2,000 feet. We anticipate tying-in 60 to 70 wells in the Kingsbury area by early 2004, including the wells currently on pump, 25 other wells presently shut-in pending hook-up, and the additional wells planned for the second half of this year. We expect to postpone drilling some or all of the wells previously planned for the Wild Turkey area in 2003, due to delays in obtaining required regulatory approvals. Our plans for the second half of 2003 also provide for drilling approximately 15 (14 net) wells and re-fracturing approximately ten (9 net) wells in the Denver Basin, and participating in drilling up to eight (0.5 net) wells at Cave Gulch. If regulatory approvals are obtained and other conditions facilitate undertaking all of these activities, we anticipate that our capital budget will be raised to a level above the previously-indicated range of $25 million to $30 million, by up to 25%.

     We are currently projecting that our total oil and gas production in 2003 will be between 14,500,000 Mcfe and 15,000,000 Mcfe. This target range represents between a 37% and 42% increase over total net production reported in 2002, and has been increased since our initial forecast of 12,500,000 Mcfe to 13,000,000 Mcfe due to the continued strong performance of 58 Porcupine-Tuit wells on production since the 3rd quarter of 2002 and the recent receipt of permits to drill additional wells in the area.

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

Reconciliation of Non-GAAP Financial Measure

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

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principles. A reconciliation of cash flow from operations before changes in operating assets and liabilities to net cash provided by operating activities is shown below: