ITEM 3. LEGAL PROCEEDINGS
At December 31, 1996, the Company is not a party to any filed or pending litigation.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the Company's security holders during the fourth quarter of the fiscal year ended December 31, 1996.
--------------------
CAUTIONARY STATEMENT FOR THE PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Prima is including the following cautionary statement to take advantage of the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statement made by, or on behalf of, the Company. The factors identified in this cautionary statement are important factors (but not necessarily all of the important factors) that could cause actual results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, the Company. Where any such forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, the Company cautions that, while it believes such assumptions or bases to be reasonable and makes them in good faith, assumed facts or bases almost always vary from actual results, and the differences between assumed facts or bases and actual results can be material, depending upon the circumstances. Where, in any forward-looking statement, the Company, or its management, expresses an expectation or belief as to the future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis, but there can be no assurance that the statement of expectation or belief will result, or be achieved or accomplished. Taking into account the foregoing, the following are identified as important risk factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, the Company:
VOLATILITY OF OIL AND NATURAL GAS PRICES. 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 the control of the Company. To the extent that oil and gas prices decline, the Company's revenues, cash flows, earnings and operations would be adversely impacted. The Company is unable to accurately predict future oil and natural gas prices.
UNCERTAINTY OF OIL AND NATURAL GAS RESERVE ESTIMATES. Estimates of the Company's proved reserves and future net revenues are based on engineering reports prepared by Company personnel. These estimates are based on several assumptions that the Securities and Exchange Commission requires oil and natural gas companies to use, including for example, constant oil and natural gas prices. Such estimates are inherently imprecise indications of future net revenues. Actual future production, revenues, taxes, production costs and development costs may vary substantially from those assumed in the estimates. Any significant variance could materially affect the estimates. In addition, the Company's reserves might be subject to upward or downward adjustment based on future production, results of future exploration and development, prevailing oil and natural gas prices and other factors.
RISKS OF OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION. The search for oil and natural gas often results in unprofitable efforts, not only from dry holes, but also from wells which, though productive, do not produce oil or natural gas in sufficient quantities to return a profit on the costs incurred. No assurance can be given that any oil or natural gas reserves located by the Company in the future will be commercially productive. In addition, the cost of drilling, completing and operating wells is often uncertain, and drilling may be delayed or cancelled as a result of many factors, including unacceptably low oil and natural gas prices, availability of drilling rigs, oil and natural gas property title problems, inclement weather conditions and financial instability of well operators and working interest owners. Furthermore, the availability of a ready market for the Company's oil and natural gas depends on numerous factors beyond its control, including demand for and supply of oil and natural gas, general economic conditions, proximity of natural gas reserves to pipelines, weather conditions and government regulation.
NEED TO REPLACE RESERVES. As is customary in the oil and gas exploration and production industry, the Company's future success depends upon its ability to continue to find, develop or acquire additional oil and gas reserves that are economically recoverable. Unless the Company replaces the reserves that it produces through successful development, exploration or acquisition, the Company's proved reserves will decline. Further, approximately 90% of the Company's proved reserves at December 31, 1996, were located in the Wattenberg area of the Denver-Julesburg Basin, where wells are characterized by relatively rapid decline rates. Additionally, approximately 24% of the Company's total proved reserves at December 31, 1996, were undeveloped. Recovery of such reserves will require significant capital expenditures and successful drilling operations. There can be no assurance that the Company will continue to be successful in its effort to develop or replace its proved reserves.
HEDGING ACTIVITIES. Part of the Company's business strategy is to periodically use both commodity futures contracts and price swaps to hedge the impact of the volatility of oil and natural gas prices on a portion of its production and gas marketing activities. In certain circumstances, significant reductions in production, due to unforeseen events, could require the Company to make payments under the hedge agreements even though such payments are not offset by production. To reduce this risk, the Company strives to keep a percentage of its production unhedged. Hedging will also prevent the Company from receiving the full advantage of increases in oil or natural gas prices above the amount specified in the hedge. Based upon average daily production during 1996, the Company's hedge agreements covered approximately 27% and 0% of the Company's daily average oil and natural gas production, respectively.
COMPETITION. The Company competes with numerous other companies and individuals, including many that have significantly greater resources, in virtually all facets of its business. Such competitors may be able to pay more for desirable leases and to evaluate, bid for and purchase a greater number of properties than the financial or personnel resources of the Company permit. The ability of the Company to increase reserves in the future will be dependent on its ability to select and acquire suitable producing properties and prospects for future exploration and development. The availability of a market for oil and
natural gas production depends upon numerous factors beyond the control of producers, including but not limited to the availability of other domestic or imported production, the locations and capacity of pipelines, and the effect of federal and state regulation on such production. Domestic oil and natural gas must compete with imported oil and natural gas, coal, atomic energy, hydroelectric power and other forms of energy.
OPERATING HAZARDS AND UNINSURED RISKS. The oil and gas business involves a variety of operating risks, including the risk of fire, explosions and blow-outs, as well as risks associated with production, marketing and general economic conditions. The Company maintains insurance against some, but not all, of these risks, any of which could result in substantial losses to the Company. There can be no assurance that any insurance would be adequate to cover any losses or exposure to liability or whether insurance will continue to be available at premium levels that justify its purchase or whether it will be available at all.
GOVERNMENT REGULATION. All aspects of the oil and gas industry are extensively regulated by federal, state and local governments in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, royalty rates and various other matters including taxation. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic and other reasons. These regulations may substantially increase the cost of doing business and sometimes prevent or delay the starting or continuing of any given exploration or development project and may adversely affect the economics of capital projects. At the present time it is impossible to predict what effect current and future proposals or changes in existing laws or regulations will have on operations, estimates of oil and natural gas reserves, or future revenues. The costs of complying, monitoring compliance and dealing with the agencies that administer these regulations can be significant.
PART II
ITEM 5.

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
(a) PRINCIPAL MARKET OR MARKETS. Prima's common stock trades on the Nasdaq National Market tier of the Nasdaq Stock Market under the symbol "PENG." The following table sets forth the Nasdaq high and low sales prices for Prima's common stock for each quarterly period during the Company's years ended December 31, 1996 and 1995. These prices have been restated to reflect the effect of the three for two split of Prima's common stock of March 4, 1997.
Year Ended December 31, 1996 HIGH LOW ---------------------------- ------- -------
Quarter Ended March 31, 1996............ $ 9.333 $ 7.500 Quarter Ended June 30, 1996............. 10.833 7.667 Quarter Ended September 30, 1996........ 11.667 9.750 Quarter Ended December 31, 1996......... 18.500 11.167
Year Ended December 31, 1995 ----------------------------
Quarter Ended March 31, 1995............ $ 9.500 $ 7.167 Quarter Ended June 30, 1995............. 10.333 8.917 Quarter Ended September 30, 1995........ 10.000 7.833 Quarter Ended December 31, 1995......... 9.833 8.833
On March 7, 1997 the closing sale price for the Company's common stock was $17.00 per share.
The above quotations are from sources believed to be reliable. They do not include any retail mark-ups, mark-downs or commissions and may not represent actual transactions.
(b) APPROXIMATE NUMBER OF HOLDERS OF COMMON STOCK. The number of holders of record of Prima's common stock at March 7, 1997 was 1,239.
(c) DIVIDENDS. Holders of common stock are entitled to receive such dividends as may be declared by Prima's Board of Directors. The Board declared a special dividend of $0.17 (restated) per common share payable to stockholders of record as of the close of business August 26, 1996. The dividend was paid August 30, 1996. Future dividends, if any, will be evaluated based among other things, on operating results and financial condition of the Company at the time.
ITEM 6.

ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth a summary of selected consolidated financial data. This data should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations and the Consolidated Financial Statements and notes thereto.
ITEM 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This Item 7 contains "forward-looking statements" and 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, continued volatility of oil and natural gas prices and estimate of future net cash flows attributable to proved undeveloped reserves and other such matters. The words "believes," "expects" or "estimates" and similar expressions identify forward-looking statements. Prima does not undertake to update, revise or correct any of the forward-looking information. Readers are cautioned that such forward-looking statements should be read in connection and in conjunction with Prima's disclosures under the heading: "Cautionary Statement for the Purposes of the 'Safe Harbor' Provisions of the Private Securities Litigation Reform Act of 1995" beginning on page 14.
The following discussion is intended to assist in understanding the Company's financial position and results of operations for each year in the three year period ended December 31, 1996. The Consolidated Financial Statements and notes thereto should be referred to in conjunction with this discussion.
LIQUIDITY AND CAPITAL RESOURCES
The Company's principal internal sources of liquidity are cash flows generated from operations and existing cash and cash equivalents. Net cash provided by operating activities totaled $12,157,000 for the year ended December 31, 1996 compared to $8,906,000 for the year ended December 31, 1995 and $10,090,000 for the year ended December 31, 1994. Net working capital at December 31, 1996 was $7,863,000 as compared to $4,292,000 at December 31, 1995. Current assets were $15,011,000 at December 31, 1996 compared to $8,792,000 at December 31, 1995. Current liabilities were $7,148,000 at December 31, 1996 compared to $4,500,000 at December 31, 1995. Current assets increased from December 31, 1995 levels by $6,219,000 and current liabilities increased by $2,648,000 for the same period. The increase in working capital of $3,571,000 was primarily generated by cash flows from operations during the year. The Company also sold undeveloped acreage for $831,000 and available for sale securities for $418,000 during 1996.
The Company has external borrowing capacity of $8,000,000 through an unsecured line of credit with a commercial bank, all of which is available to be drawn.
The Company invested $7,942,000 in additions to oil and gas properties during the year ended December 31, 1996, compared to $5,182,000 during the year ended December 31, 1995 and $10,620,000 during the year ended December 31, 1994. During 1996, $6,605,000 was paid for the Company's share of development well costs and recompletions, $401,000 for exploratory costs, $873,000 for acquisitions of unproved properties and $63,000 for purchases of proved properties. Other uses of funds in 1996 included $970,000 for dividend payments, $640,000 for purchases of office equipment and oilfield service equipment and facilities, $744,000 for purchases of marketable securities and $383,000 for treasury stock purchases.
The standardized measure of estimated discounted future net cash flows of the Company's proved oil and natural gas reserves increased to $68,965,000 at December 31, 1996 as compared to $39,180,000 at December 31, 1995 and $38,095,000 at December 31, 1994. Estimated future net cash flows from proved oil and natural gas reserves rose to $176,437,000 at December 31, 1996 compared to $85,028,000 at December 31, 1995 and $83,316,000 at December 31, 1994. Oil reserve volumes at December 31, 1996 increased 11% and natural gas reserve volumes increased 9% compared to December 31, 1995. The
weighted average natural gas price received at December 31, 1996 on Company production was $3.76 per Mcf, an increase of $1.88 per Mcf compared to December 31, 1995. The year end weighted average oil price was $24.69 per barrel, an increase of $5.96 per barrel compared to December 31, 1995.
In late 1990, the Company began deliveries of gas to the cogeneration facility in Brush, Colorado, per its contract with the project owner. At December 31, 1996, the contract price of $2.64 per MMBtu, escalated annually at 3% pursuant to the pricing provisions of the contract, was used to value gas reserves equivalent to one half of the minimum contract quantity or 6.7% of the Company's estimated proved natural gas reserves, based on the Company's estimate of the percentage of the minimum contract requirement that will be fulfilled from its existing reserves.
During 1996, the Company adopted Statement of Financial Accounting Standards No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121"). SFAS 121 provides the standards for accounting for the impairment of various long-lived assets. Substantially all of the Company's long-lived assets consist of oil and gas properties, which are accounted for using the full cost method of accounting, which requires an impairment to be recorded when total capitalized costs exceed the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves. Therefore, the adoption of SFAS 121 did not have a material effect on the financial position or results of operations of Prima.
At December 31, 1996, the Company estimates that capital expenditures of $17,548,000 will be required to develop the Company's proved undeveloped and proved developed non-producing reserves over the next several years. Approximately $14,038,000, net of future development costs, of the estimated future net cash flows of the Company's proved oil and gas reserves at December 31, 1996 were proved undeveloped reserves.
The Board of Directors of Prima approved a three for two stock split of the Company's common stock, to shareholders of record on February 20, 1997, distributed March 4, 1997. As a result, the number of shares of common stock outstanding increased from 3,860,396 to 5,790,556 on the distribution date. All share and per share amounts included in this report on Form 10-K have been restated to show the retroactive effects of the stock split.
The Company regularly reviews opportunities for acquisition of assets or companies related to the oil and gas industry which could expand or enhance its existing business. The Company expects its operations, including acquisitions and drilling prospects, will be financed by funds provided from operations, working capital, various cost-sharing arrangements, borrowings under its line of credit or from other financing alternatives.
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 the control of the Company. To the extent that oil and gas prices decline, the Company's revenues, cash flows, earnings and operations would be adversely impacted. The Company is unable to accurately predict future oil and natural gas prices.
RESULTS OF OPERATIONS
1996 VS 1995
For the year ended December 31, 1996, the Company earned net income of $6,669,000, or $1.14 per share, on revenues of $28,621,000, compared to net income of $4,492,000, or $0.77 per share, on revenues of $19,048,000 for the year ended December 31, 1995. Operating expenses were $19,667,000 for the 1996 year compared to $13,186,000 for 1995. Revenues increased $9,573,000 or 50.3%, expenses increased $6,481,000 or 49.2% and net income increased $2,177,000 or 48.5% in 1996.
Oil and gas sales for the year ended December 31, 1996 were $14,657,000 compared to $11,502,000 for the year ended December 31, 1995, an increase of $3,155,000 or 27.4%. This increase was due primarily to increased product prices for both oil and natural gas. The Company's net natural gas production was 4.65 Bcf for 1996 compared to 4.30 Bcf in 1995, an increase of .35 Bcf or 8.1%. Its net oil production was 233,000 barrels compared to 266,000 barrels for the same periods, a decrease of 33,000 barrels or 12.4%. On a BOE basis, the Company's production for 1996 increased 24,000 BOE or 2.4%. The average price received per Mcf of natural gas sold was $2.11 for the year ended December 31, 1996 compared to $1.61 per Mcf for the year ended December 31, 1995, an increase of $.50 per Mcf or 31.1%. Approximately 5.5% and 4.3% of the natural gas production for the years ended December 31, 1996 and 1995, respectively, was attributable to production sold under a fixed contract price of $5.90 per MMBtu. The average price for the Company's natural gas production exclusive of the fixed price contract gas was $1.89 per Mcf for the year ended December 31, 1996 and $1.43 per Mcf for the year ended December 31, 1995. The average price received per barrel of oil sold was $20.84 for 1996 compared to $17.19 for 1995, an increase of $3.66 per barrel or 21.3%.
Depreciation, depletion and amortization ("DD&A") rates are affected by production levels and changes in reserve estimates. Total DD&A expense was $4,544,000 in 1996 compared to $4,372,000 for 1995, an increase of $172,000 or 3.9%. The Company's depletion of oil and gas properties was $4,210,000 or $4.18 per BOE on 1,007,000 equivalent barrels produced in 1996, compared to $4,058,000 or $4.13 per BOE on 983,000 equivalent barrels produced in 1995. Included in DD&A expense for 1996 and 1995 is $334,000 and $314,000, respectively, attributable to depreciation of service equipment, furniture and equipment and buildings.
Lease operating expenses ("LOE") were $1,511,000 for the year ended December 31, 1996 compared to $1,432,000 for the year ended December 31, 1995. Ad valorem and production taxes were $981,000 and $736,000 for the same periods. Total lifting costs ( LOE plus ad valorem and production taxes) were 17% of oil and gas revenues and $2.47 per equivalent barrel of production for 1996 compared to 19% and $2.21 for 1995.
Trading revenues and cost of trading represented the marketing of third party gas by Prima Natural Gas Marketing, Inc., a wholly owned subsidiary. Trading revenues were $10,001,000 for 1996 compared to $4,604,000 for 1995, an increase of $5,397,000 or 117.2%. The Company marketed 5,252,000 MMBtu's of third party gas in 1996 compared to 2,295,000 MMBtu's in 1995, an increase of 2,957,000 MMBtu's or 128.8%. Costs of trading were $9,060,000 for 1996 compared to $3,613,000 for 1995, an increase of $5,447,000 or 150.8%. Trading activities fluctuate with natural gas markets and the Company's ability to develop markets that meet the Company's trading criteria. The increased trading revenues and costs for 1996 were attributable to purchasing larger volumes of natural gas at fixed or indexed prices, for resale at slightly higher fixed or indexed prices, realizing a known margin.
Oilfield service revenues of $2,269,000 and $1,487,000 for the years ended December 31, 1996 and 1995, respectively, represented the revenues earned by Action Oilfield Services, Inc., a wholly owned subsidiary. These revenues include well servicing fees from five completion rigs, a swab rig, trucking, water hauling, dozer and roustabout work, rental equipment and other related activities. Activity in the Wattenberg Field Area where the service company is active had declined significantly in 1995 due to low natural gas prices. In 1996, Wattenberg Area activity improved due to higher oil and natural gas prices, application of new drilling technologies, and an increased level of well reworks and recompletions. Revenues increased $782,000, or 52.6% for 1996. Cost of oilfield services were $1,759,000 for the year ended December 31, 1996 compared to $1,170,000 for the year ended December 31, 1995, an increase of $589,000 or 50.3%. For the years ended December 31, 1996 and 1995, 21.6% and 24.5% of the gross fees billed by Action were for Company owned wells. The Company's share of fees paid to Action on owned wells and the costs associated with providing the services are eliminated in consolidation. The services performed for the Company increased in 1996 because the Company drilled more Wattenberg wells than in 1995, but the percentage is lower due to increased business with third party operators.
Management and operator fees for the years ended December 31, 1996 and 1995 were $1,003,000 and $1,084,000, respectively, a decrease of $81,000 or 7.5%. Management and operator fees are earned pursuant to the Company's roles as operator for approximately 334 oil and gas wells located primarily in the Wattenberg Area of Weld County, Colorado and as managing venturer of a joint venture which owns gas gathering and pipeline facilities in the Bonny Field in Yuma County, Colorado. The Company is a working interest owner in each of the operated wells. The Company is paid operating fees by the other working interest owners in the properties. Fees fluctuate with the number of wells operated, the percentage working interest in a property owned by third parties, and the amount of drilling activity during the period. Fees decreased in 1996 due to reduced third party ownership in operated wells.
General and administrative expense ("G&A") totaled $1,812,000 for the year ended December 31, 1996 compared to $1,863,000 for the year ended December 31, 1995. G&A costs decreased by $51,000 or 2.7%. The Company's G&A expense has been relatively consistent from 1995 to 1996 because personnel levels and facility costs have not materially changed.
The provision for income taxes was $2,285,000 for the year ended December 31, 1996 compared to $1,370,000 for the year ended December 31, 1995. The effective tax rate was 25.5% in 1996 compared to 23.4% in 1995. Effective tax rates are affected by amounts of permanent differences in financial and taxable income, consisting primarily of statutory depletion deductions and Section 29 tax credits.
1995 VS 1994
For the year ended December 31, 1995, the Company earned net income of $4,492,000, or $0.77 per share, on revenues of $19,048,000, compared to net income of $5,231,000, or $0.90 per share, on revenues of $20,084,000 for the year ended December 31, 1994. Operating expenses were $13,186,000 for the 1995 year compared to $13,281,000 for 1994. Revenues decreased $1,036,000 or 5%, expenses decreased $95,000 or 1% and net income decreased $739,000 or 14% in 1995. The revenues, net income and earnings per share for 1994 include $1,200,000, $750,000 and $.13, respectively, for proceeds received from a non-recurring lawsuit settlement.
Oil and gas sales for the year ended December 31, 1995 were $11,502,000 compared to $11,558,000 for the year ended December 31, 1994, a decrease of $56,000 or .5%. The Company's net natural gas production was 4.30 Bcf for 1995 compared to 4.07 Bcf in 1994, an increase of .23 Bcf or 5.7%. Its net oil production was 266,000 barrels compared to 296,000 barrels for the same periods, a decrease
of 30,000 barrels or 10.1%. On a BOE basis, the Company's production for 1995 increased 9,000 BOE or 0.9%. The average price received per Mcf of natural gas sold was $1.61 for the year ended December 31, 1995 compared to $1.76 per Mcf for the year ended December 31, 1994, a decrease of $.15 per Mcf or 8.5%. Approximately 4% of the natural gas production for the year ended December 31, 1995 was attributable to production sold under a fixed contract price of $5.90 per MMBtu. The average price for the Company's natural gas production exclusive of the fixed price contract gas was $1.43 per Mcf for the year ended December 31, 1995. The average price received per barrel of oil sold was $17.19 for 1995 compared to $14.90 for 1994, an increase of $2.29 per barrel or 15%.
DD&A expense was $4,372,000 in 1995 compared to $4,313,000 for 1994, an increase of $59,000 or 1.4%. The Company's depletion of oil and gas properties was $4,058,000 or $4.13 per BOE on 983,000 equivalent barrels produced in 1995, compared to $3,974,000 or $4.08 per BOE on 974,000 equivalent barrels produced in 1994. Included in DD&A expense for 1995 and 1994 is $314,000 and $339,000, respectively, attributable to depreciation of service equipment, furniture and equipment and buildings.
LOE was $1,432,000 for the year ended December 31, 1995 compared to $1,512,000 for the year ended December 31, 1994. Ad valorem and production taxes were $736,000 and $863,000 for the same periods. Total lifting costs were 19% of oil and gas revenues and $2.21 per equivalent barrel of production for 1995 compared to 21% and $2.44 for 1994.
Trading revenues were $4,604,000 for 1995 compared to $3,790,000 for 1994, an increase of $814,000 or 21%. The Company marketed 2,295,000 MMBtu's of third party gas in 1995 compared to 1,678,000 MMBtu's in 1994. Costs of trading were $3,613,000 for 1995 compared to $3,334,000 for 1994, an increase of $279,000 or 8%.
Oilfield service revenues were $1,487,000 for the year ended December 31, 1995 compared to $2,102,000 for the year ended December 31, 1994. Fees decreased by $615,000 or 29.3%. Cost of oilfield services were $1,170,000 for the year ended December 31, 1995 compared to $1,334,000 for the year ended December 31, 1994. Costs decreased by $164,000 or 12.3%. These decreases were attributable to decreased activity in the Wattenberg Field Area where the service company is active. This decline in activity was due at least in part to the decline in natural gas prices incurred during the latter part of 1994 which continued into 1995 and resulted in a significant decline in drilling activity in the area. For the years ended December 31, 1995 and 1994, 25% and 35% of the gross fees billed by Action were for Company owned wells. The services performed for the Company declined in 1995 because the Company reduced the size of its 1995 Wattenberg drilling program compared to previous years programs.
Management and operator fees for the years ended December 31, 1995 and 1994 were $1,084,000 and $1,014,000, respectively. The Company operated approximately 310 oil and gas wells during 1995 compared to 300 for 1994. Fees also increased in 1995 due to increased management fees earned as managing venturer of the gas gathering system.
Other revenues for 1994 included $1,200,000 in net proceeds from the settlement of prior litigation. The settlement proceeds were received and the income recognized in the fourth quarter of 1994. The proceeds increased the Company's net income by approximately $750,000 or $0.13 per share.
G&A totaled $1,863,000 for the year ended December 31, 1995 compared to $1,925,000 for the year ended December 31, 1994. G&A costs decreased by $62,000 or 3%. The Company reduced its G&A costs as less wells were drilled based on management's decision to defer drilling due to low natural gas prices.
The provision for income taxes was $1,370,000 for the year ended December 31, 1995 compared to $1,572,000 for the year ended December 31, 1994. The effective tax rate was 23.4% in 1995 compared to 23.1% in 1994.
ITEM 8.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Consolidated Financial Statements and schedules that constitute Item 8 are attached at the end of this Annual Report on Form 10-K. An index to these Consolidated Financial Statements and Schedules is also included in Item 14(a) of this Annual Report on Form 10-K.
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
Since the Company's inception, there has not been any Form 8-K filed under the Securities Exchange Act of 1934 reporting a change in accountants in which there was a reported disagreement on any matter of accounting principles or practices or financial statement disclosure.
PART III
ITEM 10.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
ITEM 13.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12, and 13 are omitted because the Company will file a definitive proxy statement pursuant to Regulation 14A under the Securities Exchange Act of 1934 not later than 120 days after the close of the fiscal year. The information required by such Items will be included in the definitive proxy statement to be so filed for the Company's annual meeting of stockholders scheduled for May 16, 1997 and is hereby incorporated by reference.
PART IV
ITEM 14.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) (1) FINANCIAL STATEMENTS
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE ---- Independent Auditors' Report................................................ 26 Consolidated Balance Sheets at December 31, 1996 and 1995................... 27 Consolidated Statements of Income for the years ended December 31, 1996, 1995 and 1994.......................................... 29 Consolidated Statements of Stockholders' Equity for the years ended December 31, 1996, 1995 and 1994.......................................... 30 Consolidated Statements of Cash Flows for the years ended December 31, 1996, 1995 and 1994.......................................... 31 Notes to Consolidated Financial Statements for the years ended December 31, 1996, 1995 and 1994.......................................... 32
(a) (2) FINANCIAL STATEMENT SCHEDULES
Financial statement schedules have been omitted because they are not applicable or the information required therein is included elsewhere in the financial statements or notes thereto.
(a) (3) EXHIBITS
The following Exhibits are filed herewith pursuant to Rule 601 of the Regulation S-K or are incorporated by reference to previous filings.
EXHIBIT NO. DOCUMENT
10.1 Extension of Line of Credit Letter Agreement (Incorporated by reference as Exhibit 10-96.1 to Form 10-Q filed May 6, 1996) 21 Subsidiaries of the Registrant 27 Financial Data Schedules
(b) REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the Registrant's fiscal quarter ended December 31, 1996. A Form 8-K was filed February 10, 1997, announcing the approval by Prima's Board of Directors of a three for two split of the Company's $0.015 par value common stock, payable to stockholders of record on February 20, 1997, payable on March 4, 1997.
INDEPENDENT AUDITORS' REPORT
Prima Energy Corporation:
We have audited the accompanying consolidated balance sheets of Prima Energy Corporation ("Company") and subsidiaries as of December 31, 1996 and 1995, and the related consolidated statements of income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 1996. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company and subsidiaries at December 31, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
March 14, 1997 Denver, Colorado
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS DECEMBER 31, 1996 AND 1995
ASSETS ------ 1996 1995 ------------ ------------ CURRENT ASSETS Cash and cash equivalents........................... $ 6,704,000 $ 3,977,000 Available for sale securities, at market............ 1,503,000 1,180,000 Receivables (net of allowance for doubtful accounts: 1996, $45,000; 1995, $43,000).......... 5,921,000 3,087,000 Tubular goods inventory............................. 311,000 217,000 Deferred tax asset.................................. 0 101,000 Other current assets................................ 572,000 230,000 ------------ ------------ Total current assets.......................... 15,011,000 8,792,000 ------------ ------------ OIL AND GAS PROPERTIES, at cost, accounted for using the full cost method................... 52,885,000 45,774,000 Less accumulated depreciation, depletion and amortization....................... (21,940,000) (17,730,000) ------------ ------------ Oil and gas properties - net.................. 30,945,000 28,044,000 ------------ ------------ PROPERTY AND EQUIPMENT, at cost Oilfield service equipment.......................... 2,387,000 1,888,000 Furniture and equipment............................. 652,000 518,000 Field office, shop and land......................... 341,000 334,000 ------------ ------------ 3,380,000 2,740,000 Less accumulated depreciation....................... (2,000,000) (1,666,000) ------------ ------------ Property and equipment - net.................. 1,380,000 1,074,000 ------------ ------------ OTHER ASSETS Cash, designated.................................... 325,000 326,000 Other............................................... 345,000 329,000 ------------ ------------ Total other assets............................ 670,000 655,000 ------------ ------------ $48,006,000 $38,565,000 ------------ ------------ ------------ ------------
See accompanying notes to consolidated financial statements.
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS (CONT'D.) DECEMBER 31, 1996 AND 1995
LIABILITIES AND STOCKHOLDERS' EQUITY ------------------------------------
1996 1995 ----------- ----------- CURRENT LIABILITIES Accounts payable.................................... $ 2,526,000 $ 1,746,000 Amounts payable to oil and gas property owners...... 2,831,000 1,086,000 Ad valorem and production taxes payable............. 1,094,000 1,239,000 Accrued and other liabilities....................... 476,000 429,000 Deferred tax liability.............................. 221,000 0 ----------- ----------- Total current liabilities..................... 7,148,000 4,500,000
AD VALOREM TAXES, non-current....................... 984,000 1,012,000
DEFERRED TAX LIABILITY.............................. 4,601,000 3,137,000 ----------- ----------- Total liabilities............................. 12,733,000 8,649,000 ----------- ----------- STOCKHOLDERS' EQUITY Preferred stock, $0.001 par value, 2,000,000 shares authorized; no shares issued or outstanding.................. 0 0 Common stock, $0.015 par value, 8,000,000 shares authorized; 5,820,556 shares issued ...... 87,000 87,000 Additional paid-in capital.......................... 4,222,000 4,222,000 Retained earnings................................... 31,383,000 25,684,000 Unrealized loss on available for sale securities.... (36,000) (77,000) Treasury stock, 30,000 shares at cost............... (383,000) 0 ----------- ----------- Stockholders' equity - net.................... 35,273,000 29,916,000 ----------- ----------- $48,006,000 $38,565,000 ----------- ----------- ----------- -----------
See accompanying notes to consolidated financial statements.
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
1996 1995 1994 ----------- ----------- ----------- REVENUES Oil and gas sales.................... $14,657,000 $11,502,000 $11,558,000 Trading revenues..................... 10,001,000 4,604,000 3,790,000 Oilfield services.................... 2,269,000 1,487,000 2,102,000 Management and operator fees......... 1,003,000 1,084,000 1,014,000 Interest and dividend income......... 411,000 154,000 143,000 Other................................ 280,000 217,000 1,477,000 ----------- ----------- ----------- 28,621,000 19,048,000 20,084,000 ----------- ----------- ----------- EXPENSES Depreciation, depletion and amortization........................ 4,544,000 4,372,000 4,313,000 Lease operating expense.............. 1,511,000 1,432,000 1,512,000 Ad valorem and production taxes...... 981,000 736,000 863,000 Cost of trading...................... 9,060,000 3,613,000 3,334,000 Cost of oilfield services............ 1,759,000 1,170,000 1,334,000 General and administrative........... 1,812,000 1,863,000 1,925,000 ----------- ----------- ----------- 19,667,000 13,186,000 13,281,000 ----------- ----------- ----------- INCOME BEFORE INCOME TAXES........... 8,954,000 5,862,000 6,803,000 PROVISION FOR INCOME TAXES........... 2,285,000 1,370,000 1,572,000 ----------- ----------- ----------- NET INCOME........................... $ 6,669,000 $ 4,492,000 $ 5,231,000 ----------- ----------- ----------- ----------- ----------- ----------- NET INCOME PER COMMON SHARE AND COMMON SHARE EQUIVALENT........ $ 1.14 $ 0.77 $ 0.90 ----------- ----------- ----------- ----------- ----------- ----------- WEIGHTED AVERAGE COMMON SHARES OUTSTANDING AND COMMON SHARE EQUIVALENTS........................ 5,848,001 5,824,764 5,828,117 ----------- ----------- ----------- ----------- ----------- -----------
See accompanying notes to consolidated financial statements.
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
See accompanying notes to consolidated financial statements.
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
See accompanying notes to consolidated financial statements.
PRIMA ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
BUSINESS
Prima Energy Corporation ("Prima") is an independent oil and gas company primarily engaged in the exploration for, acquisition, development and production of, crude oil and natural gas. Through its wholly owned subsidiaries, Prima is also engaged in oil and gas property operations, oilfield services and natural gas gathering, marketing and trading. Prima's current activities are principally conducted in the Rocky Mountain region.
BASIS OF PRESENTATION
The accompanying consolidated financial statements include the accounts of Prima and its wholly owned subsidiaries, herein collectively referred to as the "Company." The Company's proportionate share of capital expenditures, production revenue and operating expenses from working interests in oil and gas properties is included in the consolidated financial statements. The Company's interest in an unincorporated joint venture, Bonny Gathering Company, is accounted for by the equity method. All significant intercompany transactions have been eliminated. Certain amounts in prior years have been reclassified to conform with the classifications at December 31, 1996.
USE OF ESTIMATES
The preparation of the financial statements for the Company in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash in excess of daily requirements is invested in money market accounts and commercial paper with maturities of three months or less. Such investments are deemed to be cash equivalents for purposes of the consolidated statements of cash flows.
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Years Ended December 31, ----------------------------- 1996 1995 1994 -------- ------- -------- Income taxes............ $693,000 $ 0 $584,000 Interest................ 0 29,000 59,000
AVAILABLE FOR SALE SECURITIES
The Company classifies all securities as "available for sale," states them at market value and reports unrealized gains and losses, net of income tax effect, as an adjustment to stockholders' equity. Available for sale securities are readily marketable and used routinely in operations, therefore the Company has classified its portfolio as a current asset. Realized gains and losses are determined on the specific identification method.
INVENTORY
Inventory consists of tubular goods stated at the lower of cost or market value using the specific identification method.
OIL AND GAS PROPERTIES
The Company utilizes the full cost method of accounting for oil and gas activities. Under this method, subject to a limitation based on estimated value, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration, are capitalized within a cost center. The Company's oil and gas properties are located within the United States, which constitutes one cost center. No gain or loss is recognized upon normal sale or abandonment of undeveloped or producing oil and gas properties unless the gain significantly alters the relationship between capitalized costs and proved oil and gas reserves of the cost center. Depreciation, depletion and amortization of oil and gas properties is computed on the units of production method based on proved reserves. Amortizable costs include estimates of future development costs of proved undeveloped reserves.
Capitalized costs of oil and gas properties may not exceed an amount equal to the present value, discounted at 10%, of the estimated future net cash flows from proved oil and gas reserves plus the cost, or estimated fair market value, if lower, of unproved properties. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net cash flows is computed by applying year end prices of oil and natural gas to estimated future production of proved oil and gas reserves as of year end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions.
The Company does not accrue costs for future site restoration, dismantlement and abandonment costs related to proved oil and gas properties because the Company estimates that such costs will be offset by the salvage value of the equipment sold upon abandonment of such properties. The Company's estimates are based upon its historical experience and upon review of current properties and restoration obligations.
During 1996, the Company adopted Statement of Financial Accounting Standards No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121"). SFAS 121 provides the standards for accounting for the impairment of various long-lived assets. Substantially all of the Company's long-lived assets consist of oil and gas properties which are evaluated for impairment as described above. Because the new standard does not apply to costs capitalized pursuant to the full cost method, the adoption of SFAS 121 did not have a material effect on the financial position or results of operations of Prima.
PROPERTY AND EQUIPMENT
Property and equipment is recorded at cost. Renewals and betterments which substantially extend the useful lives of the assets are capitalized. Maintenance and repairs are expensed when incurred. Depreciation is provided using the straight-line method over the estimated useful lives, 3 to 10 years, of the assets.
TRADING
The Company recognizes revenues and costs on natural gas trading transactions at the point in time when gas is delivered to the purchaser. At December 31, 1996, the Company had delivered 13,000 MMBtu's to the purchaser which had not been delivered into the pipeline. This gas is valued at the lower of cost or market value. Market value for this purpose is deemed to be the sales price specified in the contract under which the Company intends to sell the gas. Included in amounts payable to oil and gas property owners at December 31, 1996 is $48,000 representing the cost of gas which had been delivered to the purchaser but not delivered into the pipeline.
At December 31, 1995, the Company had delivered 48,000 MMBtu's into the pipeline which had not been delivered to the purchaser. This gas is also valued at the lower of cost or market value. Included in other current assets at December 31, 1995, is $60,000 representing the cost of gas which had been delivered into the pipeline but not delivered to the purchaser.
HEDGING TRANSACTIONS
The Company periodically uses both commodity futures contracts and price swaps to hedge the impact of natural gas and oil price fluctuations on a portion of its production and gas marketing activities. Gains and losses on hedging transactions are deferred until the physical transaction occurs for financial reporting purposes. Deferred gains and losses are evaluated in connection with the physical transaction underlying the hedge position. Gains or losses on hedging activities are recorded in the income statement as adjustments of the revenue or cost of the underlying physical transaction. Hedging activities are reported as operating activities in the statements of cash flows.
When the Company enters into price swaps or commodities transactions that do not correspond to scheduled physical transactions (scheduled physical transactions include committed gas marketing activities or production from producing wells), the transactions would not qualify for hedge accounting. In that event, the Company records the instruments at fair value and gains or losses are recorded as fair values fluctuate compared to cost. At December 31, 1996, the Company had no transactions that did not correspond to scheduled physical transactions. For the years ended December 31, 1996, 1995 and 1994, gains or losses for these transactions were not significant to the Company's results of operations.
GOVERNMENT REGULATION
All aspects of the oil and gas industry are extensively regulated by federal, state and local governments in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, royalty rates and various other matters including taxation. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic and other reasons. As of December 31, 1996, the Company had not been fined or cited for any violations of governmental regulations which would have a material adverse effect upon the financial condition, capital expenditures, earnings or competitive position of the Company in the oil and gas industry.
MANAGEMENT, OPERATOR AND OILFIELD SERVICE FEES
The Company receives management fees for services performed as the managing venturer and operator for a gas gathering and pipeline joint venture. Such fees are included in income. Income from operating wells for third parties is recognized pursuant to the applicable operating agreements when the services are performed. Oilfield services fees are recognized as income when the services are performed for third parties.
INCOME TAXES
Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently due plus deferred taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. The deferred tax assets and liabilities represent the future tax consequences of those differences, which will either be taxable or deductible when the assets and liabilities are recovered or settled. Deferred tax assets are also recognized for tax credits that are available to offset future federal income taxes. These deferred taxes are measured by applying currently enacted tax rates.
EARNINGS PER SHARE
Net income per common share and common share equivalents is computed using the weighted average number of shares of common stock and common stock equivalents outstanding during each year. Options to purchase stock are included as common stock equivalents, when dilutive, using the treasury stock method.
2. SUBSEQUENT EVENT
The Board of Directors of Prima approved a three for two stock split of the Company's common stock, to shareholders of record on February 20, 1997, distributed March 4, 1997. As a result, the number of shares of common stock outstanding increased from 3,860,396 to 5,790,556 on the distribution date. All share and per share amounts included in these financial statements have been restated to show the retroactive effects of the stock split.
3. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
Cash in excess of daily requirements is invested in money market accounts and commercial paper with maturities of three months or less. The carrying amount of cash equivalents approximates fair value because of the short maturity of those investments.
Oil hedge contracts are not recorded on the balance sheet at December 31, 1996. The Company estimates the fair value of these contracts to be $(23,000). The estimated fair value of the oil hedge contracts is determined by multiplying the difference between year end oil prices and the hedge contract price by the quantities under contract.
4. AVAILABLE FOR SALE SECURITIES
The Company's investments are comprised of marketable equity securities. For the year ended December 31, 1996, the Company sold securities with a market value of $418,000 which resulted in realized losses of $70,000. No securities were sold in 1995. The net unrealized loss on securities at December 31, 1996 and 1995 is included as a separate component of stockholders' equity, net of deferred income taxes of $20,000 and $45,000, respectively. The change in net unrealized gain or loss on securities for the years ended December 31, 1996 and 1995 was determined as follows:
1996 1995 ---------- ---------- Net unrealized loss, beginning of year ...... $ 122,000 $ 226,000 Net unrealized loss, end of year............. 56,000 122,000 ---------- ---------- Net change in unrealized loss................ $ 66,000 $ 104,000 ---------- ---------- ---------- ----------
The components of fair value as of December 31, 1996 and 1995 are as follows:
1996 1995 ---------- ---------- Cost (including reinvested distributions).... $1,559,000 $1,302,000 Gross unrealized gains....................... 5,000 1,000 Gross unrealized losses...................... (61,000) (123,000) ---------- ---------- Fair value................................... $1,503,000 $1,180,000 ---------- ---------- ---------- ----------
5. LINE OF CREDIT
Prima maintains an $8,000,000 unsecured line of credit with a commercial bank. The line of credit, which matures on May 1, 1998, bears interest at the bank's prime rate (8.25% at December 31, 1996), with interest payable monthly. At December 31, 1996 and 1995, there were no amounts outstanding under the line of credit.
6. HEDGING ACTIVITIES
The Company's marketing and trading activities consist of marketing the Company's own production, marketing the production of others from wells operated by the Company, and natural gas trading activities that consist of the purchase and resale of natural gas. Crude oil and natural gas futures, options and swaps are used from time to time in order to hedge the price of a portion of the Company's production, as well as purchase for resale margins. This is done to mitigate the risk of fluctuating oil and natural gas prices which can adversely affect operating results. These transactions have been entered into with major financial institutions, thereby minimizing credit risk. The Company hedged approximately 27%, 11% and 40% of its oil production in 1996, 1995 and 1994, respectively, and hedged approximately 0%, 34% and 33% of its natural gas production in these same years. Hedging gains and losses are included in oil and gas revenues at the time the hedged volumes are sold. At December 31, 1996, the Company had sold crude oil futures contracts as follows:
Unrealized Price Barrels Term Gain or (Loss) ------- ------- ------------- -------------- $ 25.25 15,000 January, 1997 $ (10,000) 24.55 10,000 February, 1997 (7,000) 23.93 10,000 March, 1997 (6,000)
At December 31, 1996, the Company purchased a swap on 600,000 MMBtu (60,000 MMBtu per month for ten months) to provide for a fixed margin per MMBtu on a sales agreement for a similar volume of natural gas. In a typical "swap" agreement, the Company receives the difference between a fixed price per unit of production and the index price, if the index price is lower. If the index price is higher, the Company pays the difference. Current hedging agreements are settled on a monthly basis. All current contracts specify the third party index to be the "Inside FERC" first of the month spot price for Colorado Interstate Gas Co.
7. INCOME TAXES
The provision for income taxes consists of the following components:
Years Ended December 31, 1996 1995 1994 ---------- ---------- ---------- Current: Federal.............................. $ 400,000 $ 354,000 $ 199,000 State................................ 124,000 127,000 96,000 ---------- ---------- ---------- 524,000 481,000 295,000 ---------- ---------- ---------- Deferred: Federal.............................. 1,741,000 1,116,000 1,260,000 State................................ 277,000 127,000 232,000 ---------- ---------- ---------- 2,018,000 1,243,000 1,492,000 ---------- ---------- ----------
Tax credits............................ (257,000) (354,000) (215,000) ---------- ---------- ----------
Provision for income taxes............. $2,285,000 $1,370,000 $1,572,000 ---------- ---------- ---------- ---------- ---------- ----------
The significant components of deferred tax assets and deferred tax liabilities included in the balance sheet are as follows: 1996 1995 ---------- ---------- Deferred Tax Assets: Minimum tax credit carryforwards............ $2,736,000 $2,478,000 State deferred income taxes................. 322,000 226,000 Investment in partnerships.................. 42,000 58,000 Other....................................... 52,000 114,000 ---------- ---------- Total Deferred Tax Assets................... 3,152,000 2,876,000 ---------- ----------
Deferred Tax Liabilities: Intangible drilling costs................... 7,351,000 5,340,000 Deferred revenues........................... 82,000 0 Depreciation................................ 61,000 42,000 Other....................................... 480,000 530,000 ---------- ---------- Total Deferred Tax Liabilities.............. 7,974,000 5,912,000 ---------- ----------
$4,822,000 $3,036,000 ---------- ---------- ---------- ----------
The reconciliation of income tax computed at the federal statutory tax rate to the Company's effective tax rate is as follows:
Years Ended December 31, 1996 1995 1994 ------- ------- -------
Statutory income tax rate.................. 34.0% 34.0% 34.0% Percentage depletion....................... (2.7) (3.4) (2.2) Section 29 credits......................... (8.3) (13.7) (8.6) State taxes, net of federal benefit........ 3.0 2.9 3.1 Other...................................... (0.5) 3.6 (3.2) ------- ------- -------
Effective tax rate.................... 25.5% 23.4% 23.1% ------- ------- ------- ------- ------- -------
At December 31, 1996, the Company had minimum tax credit carryforwards of approximately $2,736,000, which may be carried forward indefinitely.
8. MAJOR CUSTOMERS
The following customers have each provided over 10% of the Company's revenues from the identified industry segment. Following is a table summarizing the percentage provided by each customer. Although the loss of any of these customers could have a material adverse effect on the Company, the Company believes it would be able to locate alternate customers for the purchase of its production and would be able to secure additional marketing opportunities.
1996 1995 1994 ---- ---- ---- Oil and Gas Operations: PanEnergy Field Services, Inc........... 19% 21% 26% Total Petroleum......................... 15 20 20 Natural Gas Marketing and Trading: Colorado Power Partnership.............. 11 13 14 KN Gas Marketing, Inc................... 21
9. INDUSTRY SEGMENT INFORMATION
The following table sets forth revenues, operating earnings before income taxes, identifiable assets, depreciation, depletion and amortization expense and capital expenditures for the years ended December 31, 1996, 1995 and 1994 for the Company's two identifiable industry segments.
The Company operates principally in two industries, oil and gas operations and oilfield services. Total revenue by industry segment includes both sales to unaffiliated customers, as reported in the Company's consolidated income statement, and intersegment sales, which are primarily oilfield services provided to Company owned wells and are eliminated in consolidation. Oilfield services revenue includes $624,000, $481,000 and $1,112,000 for the years ended December 31, 1996, 1995 and 1994, respectively, for intersegment sales. Oilfield services revenue are priced and accounted for consistently for both unaffiliated and intersegment sales.
Identifiable assets by industry segment are those assets that are used in the Company's operations in each segment. Corporate assets are principally cash, cash equivalents and available for sale securities.
10. COMMITMENTS AND CONTINGENCIES
OFFICE LEASE
During 1995, the Company entered into an agreement to extend its current operating lease for office space for an additional five years, with a term through November 30, 2000. Rental expense, net of sublease rental income, totaled $109,000, $127,000 and $124,000 for the years ended December 31, 1996, 1995 and 1994, respectively. Future minimum annual rentals are as follows:
Year ending December 31, 1997........................ $126,000 Year ending December 31, 1998........................ 129,000 Year ending December 31, 1999........................ 132,000 Year ending December 31, 2000........................ 124,000 -------- $511,000 -------- --------
DELIVERY COMMITMENT
A participation agreement was executed May 24, 1989 between the Company and an unrelated third party to supply the natural gas required for a 50 megawatt cogeneration facility in Brush, Colorado. The Company has contracted to supply 70% of the committed quantities. Also on May 24, 1989, the Company and the third party signed a Gas Sales Agreement with the owner/operator of the cogeneration facility. The Gas Sales Agreement requires that approximately 1,750,000 MMBtu's per year of natural gas for 15 years be supplied to the cogeneration facility. Under the agreement, the owner/operator is required to take or pay for 80% of the annual contract quantity. The Company has dedicated a substantial portion of its proved reserves in Weld County, Colorado to cover its share of the commitment. The 1997 price for the gas is $2.64 per MMBtu, which escalates annually at the higher of 3% or a sharing of the indexed energy payment rate received by the owner/operator.
11. EMPLOYEE BENEFIT PLANS
STOCK OPTION PLAN
Under the Prima Energy Corporation 1993 Stock Incentive Plan ("the Plan"), 600,000 shares of Prima's common stock are reserved for issuance to key employees at fair market value on the date of grant of a stock option. Options granted under the Plan vest at 20% per year for five years, with a term of 10 years from the date of grant. At December 31, 1996, options to acquire 367,500 shares of the Company's common stock had been granted under the Plan. The exercise prices, which equaled the market price of the stock on the date of grant, ranged from $8.83 to $9.92 per share, with a weighted average price of $9.20 per share. The remaining contractual life of the options outstanding ranged from 6.75 years to 8.5 years.
A summary of options granted, exercised and outstanding during 1994, 1995 and 1996 is as follows:
Number Weighted Average of Shares Exercise Prices --------- ---------------- Balance, December 31, 1993.................. 232,500 $8.83 Granted during 1994......................... 22,500 9.33 Exercised or canceled....................... 0 n/a ------- Outstanding at December 31, 1994............ 255,000 8.88
Granted during 1995......................... 112,500 9.92 Exercised or canceled....................... 0 n/a ------- Outstanding at December 31, 1995............ 367,500 9.20
Granted during 1996......................... 0 n/a Exercised or canceled....................... 0 n/a ------- Balance at December 31, 1996................ 367,500 9.20 ------- -------
Exercisable at December 31, 1994............ 46,500 8.83 Exercisable at December 31, 1995............ 97,500 8.86 Exercisable at December 31, 1996............ 171,000 9.00
The Company has adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"). Accordingly, no compensation cost has been recognized for the Plan. Had compensation expense for the Plan been determined based on the fair value at the grant date for the options awarded in 1995 consistent with the provisions of SFAS 123, the Company's net income and net income per share would have been reduced to the pro forma amounts indicated below:
1996 1995 ---------- ---------- Net income: As reported............ $6,669,000 $4,492,000 Pro forma.............. 6,509,000 4,492,000
Net income per share: As reported.. $1.14 $0.77 Pro forma.... 1.11 0.77
The fair value of the options for disclosure purposes was estimated on the date of the grant using the Black-Scholes Model with the following assumptions:
Expected dividend yield.............. 0% Expected price volatility............ 31% Risk free interest rate.............. 6.6% Expected life of options (in years).. 9
EMPLOYEE STOCK OWNERSHIP PLAN
The Company has an Employee Stock Ownership Plan ("Plan") and a Trust to administer the Plan. The Plan is qualified under Section 401(a) of the Internal Revenue Code of 1986, as amended, and is for the benefit of all eligible employees of the Company. Allocations to participants are made annually as of
the last day of the Plan year, September 30, and are allocated among the participants in proportion to their eligible compensation for the Plan year. Contributions to the plan are payable at a minimum rate of 5% of eligible salaries. Through the Plan year ended September 30, 1993, the Plan provided for contributions to be made quarterly and to be used to purchase Prima common stock on the open market. Effective October 1, 1993, the Plan was amended to allow fully vested employees the option to direct the Plan Trustees to diversify a portion of their Plan investments by selling a limited percent of Prima common stock and investing the proceeds in various investment options. The Plan benefits all full-time employees and includes six year, 100% vesting provisions. For the years ended December 31, 1996, 1995 and 1994, the Company expensed $117,000, $93,000 and $119,000, respectively, of contributions payable to the Plan.
12. DESIGNATED CASH AND RELATED AD VALOREM TAXES PAYABLE
The Company has designated a portion of its cash balance for payment of ad valorem taxes withheld from third party revenue interest owners. The non-current portion of ad valorem taxes payable relates to those taxes collected and accrued for production through December 1996 which is not payable until fiscal 1998 or later. The related cash collected from third party revenue interest owners designated for payment of non-current ad valorem taxes is reflected as a non-current asset.
13. TRANSACTIONS WITH RELATED PARTIES
The Company is a 6% limited partner in a real estate limited partnership which currently owns approximately 22 acres of undeveloped land in Phoenix, Arizona for investment and capital appreciation. The partnership owns the 22 acres free and clear. One of the general partners of the partnership is a company controlled by the brother of the Company's president. The Company participated on the same basis as the other limited partners. This transaction was approved by the disinterested members of the Company's Board of Directors.
Certain of the Company's directors and officers have participated, either individually or through entities which they control, in oil and gas prospects or properties in which the Company has an interest. These participations, which have been on a working interest basis, have been in prospects or properties originated or acquired by the Company. In some cases, the interests sold to affiliated and non-affiliated participants were sold on a promoted basis requiring these participants to pay a disproportionate share of well costs. Each of the participations by directors and officers has been on terms no less favorable to the Company than it could have obtained from non-affiliated participants. It is expected that joint participations with the Company will continue to occur from time to time in the future. All participations by the officers and directors have and will continue to be approved by the disinterested members of the Company's Board of Directors.
At any point in time, there are receivables and payables with officers and directors that arise in the ordinary course of business. These amounts are not significant.
14. SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED)
Costs incurred in oil and gas property acquisition, exploration and development activities are as follows:
Years Ended December 31, ------------------------------------ 1996 1995 1994 ---------- ----------- ---------- Acquisition costs: Unproved properties..................... $ 873,000 $1,319,000 $ 688,000 Proved properties....................... 63,000 27,000 402,000 Exploration costs......................... 401,000 202,000 0 Development costs......................... 6,605,000 3,634,000 9,530,000 ---------- ---------- ----------- Total.................................. $7,942,000 $5,182,000 $10,620,000 ---------- ---------- ----------- ---------- ---------- ----------- Amortization per equivalent barrel of production.................... $ 4.18 $ 4.13 $ 4.08 ---------- ---------- ----------- ---------- ---------- -----------
Results of operations for oil and gas producing activities are as follows:
Years Ended December 31, ------------------------------------ 1996 1995 1994 ---------- ----------- ---------- Revenues Oil and gas sales....................... $14,657,000 $11,502,000 $11,588,000 ----------- ----------- ----------- Expenses Lease operating expense................. 1,511,000 1,432,000 1,512,000 Ad valorem and production taxes......... 981,000 736,000 863,000 Depreciation, depletion and amortization 4,210,000 4,058,000 3,974,000 ----------- ----------- ----------- 6,702,000 6,226,000 6,349,000 ----------- ----------- ----------- Income before income taxes................ 7,955,000 5,276,000 5,239,000 Income tax expense........................ 2,029,000 1,233,000 1,048,000 ----------- ----------- ----------- Income from oil and gas producing properties.............................. $ 5,926,000 $ 4,043,000 $ 4,191,000 ----------- ----------- ----------- ----------- ----------- -----------
The reserve information presented below has been prepared by the Company's personnel. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimates is a function of the quality of available data and engineering and geological interpretation and judgment. Results of drilling, testing and production after the date of the estimate may justify revisions. Accordingly, reserve estimates are often materially different from the quantities of oil and natural gas that are ultimately produced.
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those proved reserves expected to be recovered through existing wells with existing equipment and operating methods.
Proved oil and gas reserves of the Company, all of which are located in the United States, are as follows:
Years Ended December 31, ---------------------------------------------- 1996 1995 1994 --------------- -------------- -------------- Oil Gas Oil Gas Oil Gas (MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF) ------- ------ ------- ------ ------- ------ Proved reserves: Beginning of year.............. 2,734 47,711 3,009 46,202 2,702 42,638 Purchases of oil and gas reserves in place........ 14 231 14 123 4 345 Revisions of previous estimates.................... 130 2,444 (39) (218) (90) (2,624) Extensions, discoveries and other additions.............. 392 6,372 17 5,924 689 9,915 Production..................... (233) (4,646) (266) (4,298) (296) (4,072) Sales of oil and gas reserves in place..................... 0 0 (1) (22) 0 0 ------- ------ ------ ------ ------ ------ End of Year.................... 3,037 52,112 2,734 47,711 3,009 46,202 ------- ------ ------ ------ ------ ------ ------- ------ ------ ------ ------ ------ Proved developed reserves: Beginning of year.............. 1,853 38,076 2,080 35,664 1,724 30,422 End of year.................... 2,087 41,107 1,853 38,076 2,080 35,664
Standardized measures of discounted future net cash flows relating to proved oil and gas reserves are as follows:
Years Ended December 31, ---------------------------------------- 1996 1995 1994 ------------ ------------ ------------ Future cash inflows................... $271,196,000 $148,101,000 $144,215,000 Future production costs............... (77,211,000) (47,648,000) (47,347,000) Future development costs.............. (17,548,000) (15,425,000) (13,552,000) ------------ ------------ ------------ Future net cash flows................. 176,437,000 85,028,000 83,316,000 10% discount factor................... (84,991,000) (37,243,000) (35,645,000) Discounted future income taxes........ (22,481,000) (8,605,000) (9,576,000) ------------ ------------ ------------ Standardized measure of discounted future net cash flows.............. $ 68,965,000 $ 39,180,000 $ 38,095,000 ------------ ------------ ------------ ------------ ------------ ------------
The principal sources of change in the standardized measure of discounted future net cash flows are as follows:
15. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of the unaudited financial data for each quarter for the years ended December 31, 1996 and 1995.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Prima Energy Corporation has duly caused this Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized, in Denver, Colorado on the 14th day of March, 1997.
PRIMA ENERGY CORPORATION
By: /s/ RICHARD H. LEWIS --------------------------- Richard H. Lewis, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report on Form 10-K has been signed below by the following persons in the capacities indicated and on the dates indicated.
SIGNATURE TITLE DATE --------- ----- ----
/s/ RICHARD H. LEWIS March 14, 1997 - -------------------------- Richard H. Lewis Chairman, President, Treasurer, (Principal Executive and Financial Officer)
/s/ ROBERT E. CHILDRESS - -------------------------- March 14, 1997 Robert E. Childress Director
/s/ DOUGLAS J. GUION March 14, 1997 - -------------------------- Douglas J. Guion Director
/s/ JOHN P. LOCKRIDGE March 14, 1997 - -------------------------- John P. Lockridge Director
/s/ GEORGE L. SEWARD March 14, 1997 - -------------------------- George L. Seward Director
/s/ SANDRA J. IRLANDO March 14, 1997 - -------------------------- Sandra J. Irlando Vice President of Accounting and Controller