PENG Prima Energy (MM)

Prima Energy Corporation Reports Financial Results For 2003 Fourth Quarter and Full Year, And Execution of Gas Gathering Agreement DENVER, March 10 /PRNewswire-First Call/ -- Prima Energy Corporation ("Prima" or "the Company"), a Denver based independent oil and gas company, today reported its results for the quarter and year ended December 31, 2003. The Company also announced that it has entered into a gas gathering agreement covering a substantial portion of its acreage in the Powder River Basin prospective for development of coal bed methane reserves. Results of Operations for the Quarter and Year Ended December 31, 2003 Quarter Ended December 31, 2003 Prima's fourth quarter 2003 net income of $6,557,000 represented a 123% increase over net income of $2,936,000 reported for the fourth quarter of 2002. On a per-diluted-share basis, net income increased by 127% to $0.50 in the 2003 quarter compared to $0.22 in the final quarter of 2002. Cash flows from operating activities before changes in operating assets and liabilities increased by 95%, with $12,735,000 in the fourth quarter of 2003 comparing to $6,540,000 in the fourth quarter of 2002. Cash flow from operations before changes in operating assets and liabilities is a non-GAAP financialmeasure derived from net cash provided by operating activities -- see "Reconciliation of Non-GAAP Financial Measure" in a table below. The improvements were attributable to revenue growth, primarily derived from oil and gas sales. Prima's revenues totaled $19,875,000 in the 2003 quarter compared to $10,233,000 in the final three months of 2002. Oil and gas sales reported for the fourth quarter of 2003 totaled $17,017,000, compared to $8,325,000 for the same quarter in 2002, representing an increase of 104%. The growth was due to a 41% year-over-year increase in production volumes and a 45% increase in average realized oil and gas prices. Prima's production mix in the fourth quarter of 2003 was 84% natural gas and 16% oil, compared to 82% gas and 18% oil in the prior-year period. The Company's gas production increased by 45% to 3,637,000 Mcf in the latest quarter, from 2,509,000 Mcf in the fourth quarter last year. Oil production totaled approximately 116,000 barrels in the fourth quarter of 2003, compared to 94,000 barrels in the same quarter of 2002, for an increase of 23%. On an equivalent unit basis, production expanded from 3,073,000 Mcfe in the final quarter of 2002 to 4,333,000 Mcfe in the recent quarter. This improvement was primarilydue to Powder River Basin CBM operations, which generated net gas production of 1,971,000 Mcf in the fourth quarter of 2003 compared to 790,000 Mcf in the fourth quarter of 2002. CBM production in both periods was primarily attributable to the Porcupine-Tuit property, which began producing during the third quarter of 2002. In addition, higher oil production in the recent quarter was realized from increased drilling and refrac activity in the D-J Basin. The average price received for natural gas production during the last quarter of 2003 was $3.65 per Mcf, compared to $2.24 per Mcf in the final quarter of 2002, representing an increase of $1.41 or 63%. Average prices received for oil in the same periods were $32.24 and $28.81 per barrel, respectively, for a year-over-year increase of $3.43 or 12%. On an Mcf equivalent basis, the average price received was $3.93 per Mcfe for the 2003 quarter compared to $2.71 per Mcfe for the same quarter in 2002. Net hedging effects included in oil and gas saleswere not significant in the final quarter of 2002, but increased revenues in the recent quarter by $422,000, boosting average price realizations by $0.09 per Mcf of natural gas, $0.68 per barrel of oil and $0.10 per Mcfe. Prima also recorded $334,000 of gains on non-hedge derivatives in the fourth quarter of 2003, compared to $137,000 of net losses on such positions in the final quarter of 2002. Non-hedge derivatives consisted of NYMEX gas forward sales without corresponding Rocky Mountain basis-differential swaps. Depletion expense was $1.06 per Mcfe in the fourth quarter of 2003 and $0.96 in the comparable period of 2002. The increase in the per-unit depletion rate reflected higher average costs per Mcfe for 2003 reserve additions than our historical average and increased estimates for future development costs for period-end proved reserves. Lease operating expenses averaged $0.24 per Mcfe of production in the 2003 quarter and $0.26 per Mcfe in the 2002 quarter. Production taxes were $0.41 and $0.23 per Mcfe in the 2003 and 2002 quarters, respectively, primarily reflecting higher product prices in 2003. Oilfield services provided on Prima-managed properties are eliminated in consolidation, and represented approximately 25% and 28% of the Company's total oilfield services activities in the fourth quarters of 2003 and 2002, respectively. Billings to third parties in the final quarter of 2003 totaled $2,242,000 compared to $1,923,000 in the fourth quarter of 2002, for an increase of $319,000, or 17%. Costs of oilfield services provided to third parties totaled $1,593,000 in the 2003 quarter compared to $1,296,000 in the 2002 period, for an increase of $297,000, or 23%. These increases were primarily attributable to greater demand for oilfield services in the D-J Basin in 2003. Income taxes totaled 33% of pre-tax income in the recent quarter, compared to 14% in the prior year's quarter, due to permanent differences that did not increase proportionately with pre-tax income and the cessation of Section 29 tax credits at the end of 2002. Year Ended December 31, 2003 For the year ended December 31, 2003, we reported net income of $23,795,000, or $1.82 per diluted share, on revenues of $70,154,000. These amounts compare to net income of $5,230,000, or $0.40 per diluted share, on revenues of $31,790,000, for the year ended December 31, 2002. Total expenses, other than income taxes, were $35,247,000 in 2003 compared to $25,735,000 in 2002. Revenues increased $38,364,000 or 121%, expenses increased $9,512,000 or 37%, and net income increased $18,565,000 or 355% in 2003. Cash flows from operating activities before changes in operating assets and liabilities increased by 124% year-over-year, from $21,063,000 in 2002 to $47,158,000 in 2003. The primary drivers in these results were increased oil and gas sales and changes in amounts reported on derivatives not qualifying for hedge accounting treatment. Oil and gas sales reported for 2003 totaled $58,622,000 compared to $25,785,000 for 2002, for an increase of 127%. The large improvement was due to a 46% year-over-year growth in production volumes and a 56% increase in the average price realized per equivalent unit of production. Prima's production was 84% natural gas and 16% oil in 2003, compared to 79% gas and 21% oil in the prior year. Natural gas production totaled 13,015,000 Mcf in 2003 compared to 8,343,000 Mcf in 2002, for an increase of 4,672,000 Mcf, or 56%. Oil production totaled 401,000 barrels and 373,000 barrels in 2003and 2002, respectively, for an increase of 28,000 barrels, or 8%. On an equivalent unit basis, production grew from 10,580,000 Mcfe in 2002 to 15,421,000 Mcfe in 2003. This increase was primarily due to Powder River Basin CBM operations, which generated net gas production of 6,474,000 Mcf in 2003 compared to 1,576,000 Mcf in 2002. The Company's CBM production to date has been largely attributable to the Stones Throw property, which was sold March 5, 2002, and the Porcupine-Tuit property, which beganproducing from 27 wells during the third quarter of 2002. Production from Porcupine-Tuit increased in the second half of 2002 and in 2003 as de-watering occurred, new wells were drilled and brought on-line, and additional compression capacity was installed by the gathering company. At the end of 2003, Prima had 85 wells on-line at Porcupine-Tuit producing at a combined net daily rate of approximately 19,500 Mcf. The average price received on natural gas sales in 2003 was $3.53 per Mcf, compared to $1.97 per Mcf in 2002, for an increase of $1.56 per Mcf, or 79%. The average price received per barrel of oil was $31.71 in 2003 compared to $25.14 in 2002, representing an increase of $6.57 per barrel or 26%. On an Mcf equivalent basis, the average price received was $3.80 per Mcfe in 2003 compared to $2.44 per Mcfe in the prior year. The portion of our total oil and gas revenues derived from natural gas was 78% in 2003 compared to 64% in 2002. During 2003, we recognized $2,734,000 of total gains relating to oil and gas derivatives, comprised of $414,000 of hedging gains included in reported oil and gas sales and $2,320,000 of separately reported gains on derivative instruments that did not qualify for hedge accounting (these consisted primarily offorward sales of NYMEX gas without corresponding swaps for Rocky Mountain basis differentials). The net gains recognized on derivative instruments that did not qualify for hedge accounting included related mark-to-market adjustments to fair value during the year. By comparison, our revenues for 2002 included $3,376,000 of aggregate losses from oil and gas derivatives, including hedging losses of $458,000 and $2,918,000 of reported losses on derivative instruments not qualifying for hedge accounting.The $2,918,000 of losses on non-qualifying hedges included $4,464,000 of net unrealized losses that primarily represented reversals of unrealized mark-to-market gains recorded in the prior year, as the value of gas futures positions held at December 31, 2001 declined when gas prices escalated in 2002 before the contracts were settled. Our depletion expense for oil and gas properties in 2003 was $14,956,000 or $0.97 per Mcfe, compared to $9,710,000, or $0.92 per Mcfe, in 2002. Lease operating expenses totaled $3,619,000 for the year ended December 31, 2003 compared to $3,076,000 for the year ended December 31, 2002, representing an increase of $543,000 or 18%. The increase was primarily associated with the additional CBM production in 2003 and LOE decreased on a per-unit-of-production basis, from $0.29 in 2002 to $0.23 in 2003. Ad valorem and production taxes were $2,116,000 and $5,783,000 in 2002 and 2003, respectively, for an increase of $3,667,000. Such taxes fluctuate with oil and gas salesrevenues and changing mill levy rates, and averaged 9.9% of total oil and gas sales (excluding hedging effects) in 2003 compared to 8.2% in 2002, reflecting a greater portion of oil and gas sales attributable to properties in Wyoming, which has higher production tax rates than Colorado. Oilfield service revenues from third parties totaled $8,577,000 in 2003 compared to $8,326,000 in the prior year, for an increase of $251,000 or 3%. Costs of oilfield services provided to third parties were $6,510,000 in 2003 compared to $6,490,000 in 2002, for an increase of $20,000 or less than 1%. Approximately 24% of fees billed by the service companies in 2003 were for Prima-owned property interests, compared to 19% in 2002. A 10% year-over-year increase in billings before intercompany eliminations, attributable to stronger demand for services, was partially offset by the increased portion of work performed on Prima-operated properties. General and administrative expenses, net of third party reimbursementsand amounts capitalized, were $3,321,000 in 2003 compared to $3,255,000 in 2002. Net G&A costs increased by $66,000 or 2%. Higher total costs were largely offset by reimbursements of management and operator fees from third parties, which increased from $405,000 in 2002 to $601,000 in 2003. Capitalized G&A was $2,124,000 in both years. Our effective tax rate increased to 33% in 2003 from approximately 14% in 2002, due primarily to the $28,852,000, or 476%, increase in pre-tax income without a proportionate change in permanent differences. The statutory provision under which Section 29 tax credits were generated by production from certain wells expired at the end of 2002. Gas Gathering Agreement Prima also announced that it recently completed anagreement with an independent company that will expand its existing gathering system and install new compression facilities to enable the Company to tie in and market coal bed methane production from acreage covering most of its Kingsbury, Cedar Draw, North Shell Draw, Wild Turkey and Fortification Creek project areas, as well as certain additional nearby lands. These areas account for a substantial portion of Prima's estimated potential reserves in this CBM play and the planned facilities are integral to the Company's current year plans to drill an estimated 150 CBM wells and hook up most of these and approximately 130 previously-drilled CBM wells. The Company also has more than 1,000 additional prospective CBM well sites on these lands. Under theterms of the agreement, Prima will pay gathering and compression fees based on throughput volumes. We anticipate that we will begin to tie wells into such facilities by the third quarter of this year. Conference Call Prima Energy Corporation (NASDAQ:PENG) has scheduled a conference call for Thursday, March 11, 2004 at 11:00 a.m. Mountain Standard Time (1:00 p.m. Eastern Standard Time), in order to review the Company's fourth quarter 2003 financial results and provide an update on operations. Interested parties may access the conference call by dialing (800) 362- 0571 and providing conference I.D. "PRIMA". Replays will be available from 1:00 p.m. MST, March 11 through 10:00 p.m. MST March 18, 2004, by dialing (800) 934-7615 (no reservation number necessary). In addition, the conference call will be webcast live over the Internet and can be accessed by following the link from Prima Energy's website at http://www.primaenergy.com/. A replay from the Internet site will be available shortly after the call is completed, and will be available for 90 days. This press release contains "forward-looking statements" which are made pursuant to the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995. These include, without limitation, statements relating to future drilling and development plans, production and other such matters. The words "anticipate," "estimate," or "plan" and similar expressions identify forward-looking statements. Such statements are based on certain assumptions and analyses made by the Company in light of its experience and its perception of historical trends, current conditions, expected future developments and other factors it believes are 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 Company's expectations expressed in the forward-looking statements include, but are not limited to, the following: industry conditions; volatility of oil and natural gas prices; operational risks; potential liabilities, delays and associated costs imposed by government regulation (including environmental regulation); the substantial capital expenditures required to fund its 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 the Company's latest Annual Report on Form 10-K filed with the Securities And Exchange Commission. NASDAQ Symbol: PENG Contacts: Richard H. Lewis, President and Chief Executive Officer Neil L. Stenbuck, Executive Vice President and Chief Financial Officer Telephone Number: (303) 297-2100 Website: http://www.primaenergy.com/ Financial data follows. In addition, a copy of the Company's Form 10-K for the year ended December 31, 2003 will be available on the Company's website after it has been filed. PRIMA ENERGY CORPORATION CONSOLIDATED STATEMENTS OF INCOME Three Months Ended Year Ended December 31, December 31, 2003 2002 2003 2002 REVENUES Oil and gas sales $17,017,000 $8,325,000 $58,622,000 $25,785,000 Gains (losses) on derivatives instruments, net 334,000 (137,000) 2,320,000 (2,918,000) Oilfield services 2,242,000 1,923,000 8,577,000 8,326,000 Interest, dividend and other income 282,000 122,000 635,000 597,000 19,875,000 10,233,000 70,154,000 31,790,000 EXPENSES Depreciation, depletion and amortization: Depletion of oil and gas properties 4,598,000 2,953,000 14,956,000 9,710,000 Depreciation of property and equipment 260,000 192,000 1,058,000 1,088,000 Lease operating expense 1,019,000 801,000 3,619,000 3,076,000 Ad valorem and production taxes 1,773,000 703,000 5,783,000 2,116,000 Cost of oilfield services 1,593,000 1,296,000 6,510,000 6,490,000 General and administrative 850,000 867,000 3,321,000 3,255,000 10,093,000 6,812,000 35,247,000 25,735,000 Income Before Income Taxes and Cumulative Effect of Change in Accounting Principle 9,782,000 3,421,000 34,907,000 6,055,000 Provision for income taxes 3,225,000 485,000 11,515,000 825,000 Net Income Before Cumulative Effect of Change in Accounting Principle 6,557,000 2,936,000 23,392,000 5,230,000 Cumulative effect of change in accounting principle -- -- 403,000 -- NET INCOME $6,557,000 $2,936,000 $23,795,000 $5,230,000 Basic Net Income per Share Before Cumulative Effect of Change in Accounting Principle $0.51 $0.23 $1.82 $0.41 Cumulative effect of change in accounting principle -- -- 0.03 -- BASIC NET INCOME PER SHARE $0.51 $0.23 $1.85 $0.41 Diluted Net Income per Share Before Cumulative Effect of Change in Accounting Principle $0.50 $0.22 $1.79 $0.40 Cumulative effect of change in accounting principle -- -- 0.03 -- DILUTED NET INCOME PER SHARE $0.50 $0.22 $1.82 $0.40 Weighted Average Common Shares Outstanding 12,925,172 12,777,716 12,824,123 12,770,716 Weighted Average Common Shares Outstanding Assuming Dilution 13,207,781 13,233,947 13,062,345 13,221,376 PRODUCTION: Natural gas (Mcf) 3,637,000 2,509,000 13,015,000 8,343,000 Oil (barrels) 116,000 94,000 401,000 373,000 Net equivalent units (Mcfe) 4,333,000 3,073,000 15,421,000 10,580,000 AVERAGE PRICES: Natural gas (per Mcf) $3.65 $2.24 $3.53 $1.97 Oil (per barrel) $32.24 $28.81 $31.71 $25.14 Net equivalent units (per Mcfe) $3.93 $2.71 $3.80 $2.44 PRIMA ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 2003 2002 OPERATING ACTIVITIES Net income $23,795,000 $5,230,000 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 16,014,000 11,001,000 Deferred income taxes 6,416,000 (977,000) Cumulative effect of change in accounting principle (403,000) -- Unrealized losses (gains) on derivatives instruments (685,000) 4,464,000 Tax benefits from stock option plans 1,913,000 1,250,000 Other 108,000 95,000 Net changes in operating assets and liabilities (1,009,000) 461,000 Net cash provided by operating activities 46,149,000 21,524,000 INVESTING ACTIVITIES Additions to oil and gas properties (26,856,000) (22,252,000) Proceeds from sales of oil and gas properties 1,765,000 14,577,000 Purchases of other property, net (1,213,000) (768,000) Proceeds from sales of available for sale securities, net 625,000 658,000 Net cash used in investing activities (25,679,000) (7,785,000) NET FINANCING ACTIVITIES (815,000) (813,000) INCREASE IN CASH AND CASH EQUIVALENTS 19,655,000 12,926,000 CASH AND CASH EQUIVALENTS, beginning of year 36,263,000 23,337,000 CASH AND CASH EQUIVALENTS, end of year $ 55,918,000 $ 36,263,000 PRIMA ENERGY CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS December 31, December 31, 2003 2002 ASSETS Current assets $69,901,000 $47,257,000 Oil and gas properties, net 101,414,000 88,538,000 Property and equipment, net 4,718,000 4,839,000 Other assets 1,184,000 1,293,000 $177,217,000 $141,927,000 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities $13,753,000 $11,303,000 Ad valorem taxes, non-current 3,634,000 2,077,000 Asset retirement obligations 1,903,000 -- Deferred income taxes 27,251,000 21,281,000 Stockholders' equity 130,676,000 107,266,000 $177,217,000 $141,927,000 RECONCILIATION OF NON-GAAP FINANCIAL MEASURE Cash flow from operations before changes in operating assets and liabilities is presented because of its acceptance as an indicator of the ability of an oil and gas exploration and production company to internally fund exploration and development activities. This measure should not be considered as an alternative to net cash provided by operating activities as defined by generally accepted accounting principles. A reconciliation of cash flow from operations before changes in operating assets and liabilities to net cash provided by operating activities is shown below: Three Months Ended Year Ended December 31, December 31, 20032002 2003 2002 Net cash provided by operating activities $13,779,000 $8,078,000 $46,149,000 $21,524,000 Net changes in operating assets and liabilities (1,044,000) (1,538,000) 1,009,000 (461,000) Cash flow from operations before changes in operating assets and liabilities $12,735,000 $6,540,000 $47,158,000 $21,063,000 DATASOURCE: Prima Energy Corporation CONTACT: Richard H. Lewis, President and Chief Executive Officer, or Neil L. Stenbuck, Executive Vice President and Chief Financial Officer, both of Prima Energy Corporation, +1-303-297-2100 Web site: http://www.primaenergy.com/

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