ITEM 3. LEGAL PROCEEDINGS
The Company is engaged from time to time in legal proceedings in the normal course of its daily business. At December 31, 1998, Prima was not a party to any legal proceedings which it believed would have a material impact on the Company.
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, 1998.
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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. The Company does not undertake to update, revise or correct any of the forward-looking information. 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. During 1998, lower oil and natural gas prices adversely impacted revenues, earnings and cash flows. 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 independent engineers. 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 canceled 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, government regulation, 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, availability and terms for pipeline space, 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 64% of the Company's proved reserves at December 31, 1998, were located in the Wattenberg Area of the Denver Basin, where wells are characterized by relatively rapid decline rates. Additionally, approximately 26% of the Company's total proved reserves at December 31, 1998, were undeveloped. Recovery of such reserves will require significant capital expenditures and successful drilling and/or recompletion 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 agreement. Based upon average daily production during 1998, the Company's hedge agreements covered approximately 0% and 44% 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 commencement or continuance 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.
YEAR 2000 ISSUE. The failure to correct a material Year 2000 problem could result in an interruption in, or failure of, certain normal business activities or operations. Such failures could materially and adversely affect the Company's results of operations, liquidity and financial condition. The Company has not yet determined the potential adverse effect that Year 2000 risks may have on its financial condition, liquidity or results of operations. The Company's program is expected to significantly reduce the Company's level of uncertainty about Year 2000 issues and, in particular, about Year 2000 compliance and readiness of its third party vendors and associates. The Company believes that, with the modification of its business systems and completion of its assessment program as scheduled, the possibility of significant interruptions of normal operations should be reduced. The cost of Year 2000 compliance has not been specifically tracked but is not anticipated to be material to the Company's financial position or results of operations in any given year.
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, 1998 and 1997. These prices have been restated to reflect the effect of the three for two split of Prima's common stock on March 4, 1997.
On March 11, 1999 the closing sale price for the Company's common stock was $15.00 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 11, 1999 was 1,166.
(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 per common share payable to stockholders of record as of the close of business August 26, 1996. The dividend was paid August 30, 1996. No dividends were declared or paid in 1998 or 1997. 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 estimates of future net cash flows attributable to proved reserves and other such matters. The words "anticipates," "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 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 16.
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, 1998. 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 $16,789,000 for the year ended December 31, 1998, compared to $14,685,000 for the year ended December 31, 1997 and $12,156,000 for the year ended December 31, 1996. Net working capital at December 31, 1998 was $5,467,000 as compared to $7,952,000 at December 31, 1997. Current assets were $10,673,000 at December 31, 1998 compared to $14,256,000 at December 31, 1997. Current liabilities were $5,206,000 at December 31, 1998 compared to $6,304,000 at December 31, 1997. The Company had proceeds from the sales of oil and gas properties and other equipment and sales of securities of $158,000 in 1998.
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. On January 21, 1999, Prima closed on the sale of all of its interest in the Bonny Field acreage, wells, and gathering system for $26 million. Prima placed the proceeds from this sale in a like-kind exchange escrow account with a qualified intermediary with the intent of identifying and closing on certain qualifying properties pursuant to like-kind exchange provisions of Section 1031 of the Internal Revenue Code. These qualifying properties include oil and gas properties and other real estate properties. In the event the Company is unable to close on qualifying properties pursuant to these requirements, the proceeds will be taxable. In that event, the Company intends to invest the after tax proceeds of approximately $20 million in opportunities that meet its criteria.
The Company invested $18,147,000 in additions to oil and gas properties during the year ended December 31, 1998, compared to $15,250,000 during the year ended December 31, 1997 and $7,942,000 during the year ended December 31, 1996. During 1998, $11,502,000 was paid for the Company's share of development well costs and recompletions, $1,082,000 for exploratory costs, $5,169,000 for acquisitions of unproved properties and $394,000 for purchases of proved properties. Other uses of funds in 1998 included $1,275,000 for purchases of oilfield service equipment and facilities and office equipment, $540,000 for purchases of marketable securities and $10,000 for treasury stock purchases.
The standardized measure of discounted future net cash flows of the Company's proved oil and natural gas reserves decreased to $51,426,000 at December 31, 1998 as compared to $58,149,000 at December 31, 1997 and $68,965,000 at December 31, 1996. Estimated future net cash flows from proved oil and natural gas reserves decreased to $115,801,000 at December 31, 1998 compared to $136,391,000 at December 31, 1997 and $176,437,000 at December 31, 1996. Oil reserve volumes at December 31, 1998 decreased 16% and natural gas reserve volumes increased 12% compared to December 31, 1997. On a barrel of oil equivalent basis, 1998 reserves increased 5% to 14,694,000 BOE. The weighted average natural
gas price received at December 31, 1998 on Company production was $2.13 per Mcf, a decrease of $0.27 per Mcf compared to December 31, 1997. The year end weighted average oil price was $10.31 per barrel, a decrease of $6.77 per barrel compared to December 31, 1997.
At December 31, 1998, the Company estimates that capital expenditures of $20,341,000 will be required to develop the Company's proved undeveloped and proved developed non-producing reserves over the next several years. Approximately $12,304,000, net of future development costs, of the estimated future net cash flows of the Company's proved oil and gas reserves at December 31, 1998 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. During 1998, lower oil and natural gas prices adversely impacted revenues, earnings and cash flows. 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.
YEAR 2000 ISSUE
The Year 2000 Issue is the result of computer applications being written using two digits rather than four to define the applicable year. As the year 2000 approaches, such applications may be unable to accurately process certain date-based information. The Company believes it has identified the significant internal computer applications that will require modification to ensure Year 2000 compliance. Internal and external resources are being used to make the required modifications and test compliance. Modification and compliance is proceeding as scheduled and the Company expects that the modifications should be completed by June 30, 1999. At that time, the Company's internal computer applications are expected to be Year 2000 compliant.
An assessment of the readiness of third parties with whom the Company does business, such as customers and vendors, is ongoing. Third parties with whom the Company has material relationships have been contacted regarding their Year 2000 issues and responses are being monitored to determine the potential effect on Prima. The Company's operations would be impacted by various third parties abilities to be Year 2000 compliant.
The failure to correct a material Year 2000 problem could result in an interruption in, or failure of, certain normal business activities or operations. Such failures could materially and adversely affect the Company's results of operations, liquidity and financial condition. The Company has not yet determined the potential adverse effect that Year 2000 risks may have on its financial condition, liquidity or results of operations. The Company's program is expected to significantly reduce the Company's level of uncertainty about Year 2000 issues and, in particular, about Year 2000 compliance and readiness of its third party
vendors and associates. The Company believes that, with the modification of its business systems and completion of its assessment program as scheduled, the possibility of significant interruptions of normal operations should be reduced. The cost of Year 2000 compliance has not been specifically tracked but is not anticipated to be material to the Company's financial position or results of operations in any given year.
To mitigate Year 2000 compliance issues at year end, the Company will back up all internal computer data to ensure the ability to restore that information. The Company will have hard copies of all important internal computer information and hard copies of the detail of any assets held by third parties such as banks and investment brokers. If the Company is unable to produce its wells or transport or sell its production due to Year 2000 compliance issues, wells will be shut-in until normal operations can be resumed.
NEW ACCOUNTING PRONOUNCEMENTS
The Company adopted Statement of Financial Accounting Standards No. 130 "Reporting Comprehensive Income" ("SFAS 130") effective January 1, 1998. SFAS 130 requires that changes in equity during a reporting period, except transactions with owners in their capacity as owners (for example, the issuance of common stock and dividends paid on common stock) and transactions reported as direct adjustments to capital deficit or retained earnings, be reported as a component of comprehensive income. Comprehensive income is required to be reported in a financial statement that is displayed with the same prominence as other financial statements. Statements of comprehensive income for the years ended December 31, 1998, 1997 and 1996 are included in the accompanying financial statements.
The Company adopted Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and Related Information" ("SFAS 131") effective January 1, 1998. SFAS 131 establishes standards for reporting selected information about operating segments and related disclosures about products and services, geographic areas, and major customers. SFAS 131 requires that a public business enterprise report financial and descriptive information about its operating segments which are regularly evaluated by the chief operating decision maker in deciding how to allocate resources and in assessing performance. SFAS 131 also requires that the financial information be reported on the basis that it used internally for evaluating segment performance. The Company's adoption of SFAS 131 in 1998 had no impact on its consolidated financial position, results of operations or cash flows.
During June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 establishes standards for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. SFAS 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. If certain conditions are met, a derivative may be specifically designated as (a) a hedge of the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment, (b) a hedge of the exposure to variable cash flows of a forecasted transaction, or (c) a hedge of the foreign currency exposure of a net investment in a foreign operation, an unrecognized firm commitment, an available-for-sale security, or a foreign-currency- denominated forecasted transaction. The accounting for changes in the fair value of a derivative (gains and losses) depends on the intended use of the derivative and the resulting designation. The Company is required to adopt SFAS 133 on January 1, 2000. The Company has not completed the process of evaluating the impact that will result from adopting SFAS 133.
RESULTS OF OPERATIONS
1998 VS 1997
For the year ended December 31, 1998, the Company earned net income of $8,065,000, or $1.37 per diluted share, on revenues of $30,092,000, compared to net income of $8,102,000, or $1.37 per diluted share, on revenues of $38,850,000 for the year ended December 31, 1997. Operating expenses were $18,967,000 for 1998 compared to $28,113,000 for 1997. Revenues decreased $8,758,000 or 23%, expenses decreased $9,146,000 or 33% and net income decreased $37,000 or less than 1% in 1998.
Oil and gas sales for the year ended December 31, 1998 were $16,612,000 compared to $17,840,000 for the year ended December 31, 1997, a decrease of $1,228,000 or 7%. This decrease was due to lower product prices, which more than offset increased production. The Company's net natural gas production was 6.48 Bcf for 1998 compared to 5.34 Bcf in 1997, an increase of 1.14 Bcf or 21%. Its net oil production was 286,000 barrels compared to 255,000 barrels for the same periods, an increase of 31,000 barrels or 12%. On a BOE basis, the Company's production for 1998 increased 220,000 BOE or 19%. The average price received per Mcf of natural gas sold was $2.00 for the year ended December 31, 1998 compared to $2.39 per Mcf for the year ended December 31, 1997, a decrease of $.39 per Mcf or 16%. Approximately 4.9% and 5.2% of the natural gas production for the years ended December 31, 1998 and 1997, 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 $1.81 per Mcf for the year ended December 31, 1998 and $2.20 per Mcf for the year ended December 31, 1997. The average price received per barrel of oil sold was $12.71 for 1998 compared to $19.90 for 1997, a decrease of $7.19 per barrel or 36%. During the year ended December 31, 1998, the Company hedged approximately 44% of its natural gas production. The purpose of these hedges is to provide market price protection in the volatile environment of oil and natural gas spot pricing. Hedging losses of $112,000 are included in oil and gas revenues for the year, which decreased the average price received per Mcf of natural gas by $0.02. No oil was hedged during this period. During the year ended December 31, 1997, the Company hedged approximately 29% of its oil production and 37% of its natural gas production. Hedging gains of $140,000 are included in oil and gas revenues for the year, which increased the average price received per barrel of oil by $0.50 and had no material effect on the price received per Mcf of natural gas.
Depreciation, depletion and amortization ("DD&A") rates are affected by production levels and changes in reserve estimates. Total DD&A expense was $6,876,000 in 1998 compared to $5,432,000 for 1997, an increase of $1,444,000 or 27%. The Company's depletion of oil and gas properties was $6,260,000 or $4.58 per BOE on 1,366,000 equivalent barrels produced in 1998, compared to $4,935,000 or $4.31 per BOE on 1,146,000 equivalent barrels produced in 1997. Included in DD&A expense for 1998 and 1997 is $616,000 and $497,000, respectively, attributable to depreciation of service equipment, furniture and equipment and buildings. Depreciation expense on these assets increased $119,000, or 24%, due primarily to acquisitions of oilfield service equipment in 1998.
Lease operating expenses ("LOE") were $2,041,000 for the year ended December 31, 1998 compared to $1,720,000 for the year ended December 31, 1997. Ad valorem and production taxes were $1,272,000 and $1,355,000 for the same periods. Total lifting costs (LOE plus ad valorem and production taxes) were 20% of oil and gas revenues and $2.43 per equivalent barrel of production for 1998 compared to 17% and $2.68 for 1997.
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 $3,956,000 for 1998 compared to $15,999,000 for 1997, a decrease of $12,043,000 or 75%. The Company marketed 1,823,000 MMBtus of third party gas in 1998 compared to 7,105,000 MMBtus in 1997, a decrease of 5,282,000 MMBtus or 74%. Costs of trading were $3,936,000 for 1998 compared to $15,323,000 for 1997, a decrease of $11,387,000 or 74%. Trading activities fluctuate with natural gas markets and the Company's ability to develop markets that meet the Company's trading criteria. These decreases are attributable to the previously announced
termination of the gas supply contract to a co-generation facility and to certain other buy-for-resale contracts which terminated in the fall of 1997 and were not renewed.
Oilfield service revenues of $4,148,000 and $3,214,000 for the years ended December 31, 1998 and 1997, respectively, represent the revenues earned by Action Oilfield Services, Inc., a wholly owned subsidiary. These revenues include well servicing fees from seven completion rigs, two swab rigs, trucking, water hauling, rental equipment and other related activities. Revenues increased $934,000, or 29% for 1998. Cost of oilfield services were $2,701,000 for the year ended December 31, 1998 compared to $2,368,000 for the year ended December 31, 1997, an increase of $333,000 or 14%. Utilization levels in the Wattenberg Area, where the service company is active, increased above 1997 levels. The Company also purchased additional equipment which contributed to the increase in revenues. For the years ended December 31, 1998 and 1997, 21% and 22%, respectively, 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.
Management and operator fees for the years ended December 31, 1998 and 1997 were $1,044,000 and $1,035,000, respectively, an increase of $9,000 or 1%. Management and operator fees are earned pursuant to the Company's roles as operator for approximately 375 oil and gas wells located primarily in the Wattenberg Area of Weld County, Colorado and as managing venturer of a joint venture which owned 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. In January 1999, the Company sold its interest in the Bonny Field assets and will no longer serve as managing venturer and operator. Management and operator fees attributable to the Bonny Field system were $406,000 for each of 1998 and 1997.
General and administrative expense ("G&A") totaled $2,141,000 for the year ended December 31, 1998 compared to $1,915,000 for the year ended December 31, 1997. G&A costs increased by $226,000 or 12%. The Company's G&A expense has increased due to expansion of the Company's area of operations. During 1998, the company capitalized geological and geophysical costs of $180,000 compared to $120,000 in 1997. Additionally, the Company capitalized G&A costs of $380,000 in 1998 related primarily to its expansion in the Powder River Basin.
The provision for income taxes was $3,060,000 for the year ended December 31, 1998 compared to $2,635,000 for the year ended December 31, 1997. The effective tax rate was 27.5% in 1998 compared to 24.5% in 1997. Effective tax rates are affected by amounts of permanent differences between financial and taxable income, consisting primarily of statutory depletion deductions and Section 29 tax credits.
1997 VS 1996
For the year ended December 31, 1997, the Company earned net income of $8,102,000, or $1.37 per diluted share, on revenues of $38,850,000, compared to net income of $6,669,000, or $1.14 per diluted share, on revenues of $28,621,000 for the year ended December 31, 1996. Operating expenses were $28,113,000 for 1997 compared to $19,667,000 for 1996. Revenues increased $10,229,000 or 36%, expenses increased $8,446,000 or 43% and net income increased $1,433,000 or 21% in 1997.
Oil and gas sales for the year ended December 31, 1997 were $17,840,000 compared to $14,657,000 for the year ended December 31, 1996, an increase of $3,183,000 or 22%. This increase was due primarily to increased production of both oil and natural gas and to increased natural gas prices. The Company's net natural gas production was 5.34 Bcf for 1997 compared to 4.65 Bcf in 1996, an increase of .69 Bcf or 15%. Its net oil production was 255,000 barrels compared to 233,000 barrels for the same periods, an increase of 22,000 barrels or 9%. On a BOE basis, the Company's production for 1997 increased 139,000 BOE or 14%. The average price received per Mcf of natural gas sold was $2.39 for the year ended
December 31, 1997 compared to $2.11 per Mcf for the year ended December 31, 1996, an increase of $.28 per Mcf or 13%. Approximately 5.2% and 5.5% of the natural gas production for the years ended December 31, 1997 and 1996, 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 $2.20 per Mcf for the year ended December 31, 1997 and $1.89 per Mcf for the year ended December 31, 1996. The average price received per barrel of oil sold was $19.90 for 1997 compared to $20.84 for 1996, a decrease of $0.94 per barrel or 5%. During the year ended December 31, 1997, the Company hedged approximately 29% of its oil production and 37% of its natural gas production. The purpose of these hedges is to provide market price protection in the volatile environment of oil and natural gas spot pricing. Hedging gains of $140,000 are included in oil and gas revenues for the year, which increased the average price received per barrel of oil by $0.50 and had no material effect on the price received per Mcf of natural gas. During the year ended December 31, 1996, the Company hedged approximately 25% of its oil production. Hedging losses of $116,000 reduced the price received per barrel of oil by $0.50. No natural gas production was hedged in 1996.
DD&A expense was $5,432,000 in 1997 compared to $4,544,000 for 1996, an increase of $888,000 or 20%. The Company's depletion of oil and gas properties was $4,935,000 or $4.31 per BOE on 1,146,000 equivalent barrels produced in 1997, compared to $4,210,000 or $4.18 per BOE on 1,007,000 equivalent barrels produced in 1996. Included in DD&A expense for 1997 and 1996 is $497,000 and $334,000, respectively, attributable to depreciation of service equipment, furniture and equipment and buildings. Depreciation expense on these assets increased $163,000, or 49%, due primarily to acquisitions of oilfield service equipment in 1997.
LOE was $1,720,000 for the year ended December 31, 1997 compared to $1,511,000 for the year ended December 31, 1996. Ad valorem and production taxes were $1,355,000 and $981,000 for the same periods. Total lifting costs were 17% of oil and gas revenues and $2.68 per equivalent barrel of production for 1997 compared to 17% and $2.47 for 1996. The increased rate for 1997 was due to workover expenses and additional production taxes resulting from higher product prices.
Trading revenues were $15,999,000 for 1997 compared to $10,001,000 for 1996, an increase of $5,998,000 or 60%. The Company marketed 7,105,000 MMBtu's of third party gas in 1997 compared to 5,252,000 MMBtu's in 1996, an increase of 1,853,000 MMBtu's or 35%. Costs of trading were $15,323,000 for 1997 compared to $9,060,000 for 1996, an increase of $6,263,000 or 69%. The increased trading revenues and costs for 1997 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 were $3,214,000 for the year ended December 31, 1997 compared to $2,269,000 for the year ended December 31, 1996. Revenues increased $945,000, or 42% for 1997. Cost of oilfield services were $2,368,000 for the year ended December 31, 1997 compared to $1,759,000 for the year ended December 31, 1996, an increase of $609,000 or 35%. Utilization levels in the Wattenberg Area, where the service company is active, increased above 1996 levels. The Company also purchased additional equipment which contributed to the increase in revenues. For both the years ended December 31, 1997 and 1996, 22% of the gross fees billed by Action were for Company owned wells.
Management and operator fees for the years ended December 31, 1997 and 1996 were $1,035,000 and $1,003,000, respectively, an increase of $32,000 or 3%. G&A totaled $1,915,000 for the year ended December 31, 1997 compared to $1,812,000 for the year ended December 31, 1996. G&A costs increased by $103,000 or 6%. The Company's G&A expense has increased due to expansion of the Company's area of operations. During 1997, the Company capitalized $120,000 of geological and geophysical costs while no geological and geophysical costs were capitalized in 1996.
The provision for income taxes was $2,635,000 for the year ended December 31, 1997 compared to $2,285,000 for the year ended December 31, 1996. The effective tax rate was 24.5% in 1997 compared to 25.5% in 1996.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's primary market risks relate to changes in the prices received from sales of oil and natural gas. The Company's primary risk management strategy is to partially mitigate the risk of adverse changes in its cash flows caused by deceases in oil and natural gas prices by entering into derivative commodity instruments, including commodity futures contracts and price swaps. By hedging only a portion of its market risk exposures, the Company is able to participate in the increased earnings and cash flows associated with increases in oil and natural gas prices; however, it is exposed to risk on the unhedged portion of its oil and natural gas production.
Historically, the Company has attempted to hedge the exposure related to its forecasted oil and natural gas production in amounts which it believes are prudent based on the prices of available derivatives and, in the case of production hedges, the Company's deliverable volumes. The Company does not use or hold derivative instruments for trading purposes nor does it use derivative instruments with leveraged features. The Company's derivative instruments are designed and effective as hedges against its identified risks, and do not of themselves expose the Company to market risk because any adverse change in the cash flows associated with the derivative instrument is accompanied by an offsetting change in the cash flows of the hedged transaction.
Notes 1 and 5 to the financial statements provide further disclosure with respect to derivatives and related accounting policies.
All derivative activity is carried out by personnel who have appropriate skills, experience and supervision. The personnel involved in derivative activity must follow prescribed trading limits and parameters that are regularly reviewed by the Company's Chief Executive Officer. All hedges or open positions are reviewed by the Chief Executive Officer before they are committed to, and significant positions are reviewed by the Company's Board of Directors. The Company uses only well-known, conventional derivative instruments and attempts to manage its credit risk by entering into financial contracts with reputable financial institutions.
Following are disclosures regarding the Company's market risk instruments. Investors and other users are cautioned to avoid simplistic use of these disclosures. Users should realize that the actual impact of future commodity price movements will likely differ from the amounts disclosed below due to ongoing changes in risk exposure levels and concurrent adjustments to hedging positions. It is not possible to accurately predict future movements in oil and natural gas prices.
The Company periodically hedges a portion of the price risk associated with the sale of its oil and natural gas production through the use of derivative commodity instruments, which consist of commodity futures contracts and price swaps. These instruments reduce the Company's exposure to decreases in oil and natural gas prices on the hedged portion of its production by enabling it to effectively receive a fixed price on its oil and natural gas sales. The Company had no derivative commodity instruments in place as of March 11, 1999. During 1998, the Company sold 286,000 barrels of oil. A hypothetical decrease of $1.03 per barrel (10% of year end 1998 prices) would decrease the Company's production revenues by $295,000 during 1999, assuming that oil production remains at 1998 levels. The Company sold 6.48 Bcf of natural gas in 1998. A hypothetical decrease of $.21 per Mcf (10% of year end 1998 prices) would decrease the Company's production revenues by $1,361,000 for 1999, assuming that natural gas production remains at 1998 levels.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Consolidated Financial Statements that constitute Item 8 are attached at the end of this Annual Report on Form 10-K. An index to these Consolidated Financial Statements 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 DISCLOSURE
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 19, 1999 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
(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.
(b) REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the Company's fiscal quarter ended December 31, 1998. A Form 8-K dated January 21, 1999, announced the sale of oil and gas properties and related assets for $26 million. See Note 10 of the Notes to Consolidated Financial Statements for additional discussion of this transaction.
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, 1998 and 1997, and the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 1998. 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 its subsidiaries at December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998 in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
March 19, 1999 Denver, Colorado
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS DECEMBER 31, 1998 AND 1997
ASSETS
See accompanying notes to consolidated financial statements.
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS (CONT'D.) DECEMBER 31, 1998 AND 1997
LIABILITIES AND STOCKHOLDERS' EQUITY
See accompanying notes to consolidated financial statements.
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
See accompanying notes to consolidated financial statements.
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
See accompanying notes to consolidated financial statements.
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
See accompanying notes to consolidated financial statements.
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Supplemental schedule of noncash investing and financing activities:
The Company purchased oilfield service assets for $600,000 in June 1997. A summary of the transaction is as follows:
See accompanying notes to consolidated financial statements.
PRIMA ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
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 of the United States.
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, 1998.
USE OF ESTIMATES
The preparation of the financial statements of 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 for income taxes was $810,000, $787,000 and $693,000 for the years ended December 31, 1998, 1997 and 1996, respectively. Cash paid for interest in 1998 was $20,000. No amounts were paid for interest in 1997 or 1996.
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 deferred income taxes, as an adjustment to stockholders' equity. Available for sale securities are readily marketable and available for use in the Company's operations should the need arise. 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.
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.
Long-lived assets, other than oil and gas properties which are evaluated for impairment as described above, are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. To date, Prima has not recognized any impairment losses.
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, 1997, the Company had delivered 8,000 MMBtu's into the pipeline which had not been delivered to the purchaser. 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 other current assets at December 31, 1997, is $19,000 representing the cost of gas which had been delivered into the pipeline but not delivered to the purchaser. There were no amounts over or under delivered at December 31, 1998.
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. In order to qualify for hedge accounting, the item to be hedged must expose the Company to price risk (which is the sensitivity of the Company's income for one or more future periods to changes in oil and gas spot prices) and the financial contract must reduce the price exposure of the Company and be designated as a hedge. Further, since the financial contracts for the sale of oil and gas relate to anticipated transactions, the significant characteristics and expected terms of the anticipated transaction must be identified (i.e., expected date of the transaction, the commodity involved, and the expected quantity to be purchased or sold) and it must be probable that the anticipated transaction will occur. 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 anticipated physical transactions (anticipated physical transactions include committed gas marketing activities or production from producing wells), the transactions do 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, 1998, the Company had no transactions that did not correspond to anticipated physical transactions. For the years ended December 31, 1998, 1997 and 1996, 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, 1998, 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 payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. The deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when the assets and liabilities are recovered or settled. Deferred income taxes are also recognized for tax credits that are available to offset future federal income taxes. Deferred income taxes are measured by applying currently enacted tax rates.
COMPREHENSIVE INCOME
The Company adopted Statement of Financial Accounting Standards No. 130 "Reporting Comprehensive Income" ("SFAS 130") effective January 1, 1998. SFAS 130 requires that changes in equity during a reporting period, except transactions with owners in their capacity as owners (for example, the issuance of common stock and dividends paid on common stock) and transactions reported as direct adjustments to capital deficit or retained earnings, be reported as a component of comprehensive income. Comprehensive income is required to be reported in a financial statement that is displayed with the same prominence as other financial statements. Statements of comprehensive income for the years ended December 31, 1998, 1997 and 1996 are included in the accompanying financial statements.
SEGMENT REPORTING
The Company adopted Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and Related Information" ("SFAS 131") effective January 1, 1998. SFAS 131 establishes standards for reporting selected information about operating segments and related disclosures about products and services, geographic areas, and major customers. SFAS 131 requires that a public business enterprise report financial and descriptive information about its operating segments which are regularly evaluated by the chief operating decision maker in deciding how to allocate resources and in assessing performance. SFAS 131 also requires that the financial information be reported on the basis that it used internally for evaluating segment performance. The Company's adoption of SFAS 131 in 1998 had no impact on its consolidated financial position, results of operations or cash flows.
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
During June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 establishes standards for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. SFAS 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. If certain conditions are met, a derivative may be specifically designated as (a) a hedge of the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment, (b) a hedge of the exposure to variable cash flows of a forecasted transaction, or (c) a hedge of the foreign currency exposure of a net investment in a foreign operation, an unrecognized firm commitment, an available-for-sale security, or a foreign-currency- denominated forecasted transaction. The accounting for changes in the fair value of a derivative (gains and losses) depends on the intended use of the derivative and the resulting designation. The Company is required to adopt SFAS 133 on January 1, 2000. The Company has not completed the process of evaluating the impact that will result from adopting SFAS 133.
EARNINGS PER SHARE
Basic net income per share is computed by dividing net income by the weighted average common shares outstanding during the period. Diluted net income per share includes the potential dilution that could occur upon exercise of the options to acquire common stock described in Note 9, computed using the treasury stock method. The treasury stock method assumes that the increase in the number of shares issued is reduced by the number of shares which could have been repurchased by the Company with the proceeds from the exercise of the options (which were assumed to have been at the average market price of the common shares during the reporting period).
The following table reconciles the numerator and denominator used in the calculation of basic and diluted net income per share.
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. During 1997, the shareholders of Prima approved an increase in the number of authorized shares of common stock from 8,000,000 to 12,000,000 shares.
2. 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.
Natural gas hedge contracts are not recorded on the balance sheet at December 31, 1998 and 1997. The fair value of the Company's liability under these contracts is estimated to be $42,000 and $155,000, respectively. The estimated fair value of the natural gas hedge contracts is determined by multiplying the difference between year end natural gas prices and the hedge contract price by the quantities under contract.
The fair market value of the Company's debt at December 31, 1998 is approximately equal to its carrying value since the Company could have obtained the debt for the same terms at December 31, 1998.
3. AVAILABLE FOR SALE SECURITIES
The Company's investments are comprised of marketable equity securities. For the years ended December 31, 1998 and 1997, the Company sold securities with a market value of $28,000 and $113,000 which resulted in realized gains and (losses) of $2,000 and ($10,000), respectively. The net unrealized gain on securities at December 31, 1998 and 1997 is included in accumulated other comprehensive income, net of deferred income taxes of $30,000 and $27,000, respectively. The change in net unrealized gain or loss on securities for the years ended December 31, 1998 and 1997 was determined as follows:
The components of fair value as of December 31, 1998 and 1997 are as follows:
4. NOTE PAYABLE AND LINE OF CREDIT
The Company's note payable consists of the following:
The note is dated June 10, 1997 and is due on June 10, 2000, with interest at an annual rate of 8%. Payments of principal and accrued interest on the note are to be made in three equal annual installments on the anniversary date of the note. The note financed the purchase of oilfield service equipment by Action Oilfield Services, Inc., a wholly owned subsidiary. The note is collateralized by oilfield service equipment with a net book value of approximately $474,000 at December 31, 1998.
Prima maintains an $8,000,000 unsecured line of credit with a commercial bank. The line of credit, which matures on May 1, 1999, bears interest at the bank's prime rate (7.75% at December 31, 1998), with interest payable monthly. At December 31, 1998 and 1997, there were no amounts outstanding under the line of credit.
5. 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 and purchases for resale. 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 44% and 37% of its natural gas production in 1998 and 1997. No natural gas was hedged in 1996. The Company hedged approximately 29% and 25% of its oil production in 1997 and 1996. No oil was hedged in 1998.
To hedge its natural gas and crude oil production and purchases for resale, the Company from time to time uses futures and energy swaps. The purpose of these hedges is to provide market price protection in the volatile environment of oil and natural gas spot pricing. As a result of its trading activities, the Company may also from time to time have open purchase or sale commitments without corresponding contracts to offset these commitments, which could result in losses to the Company. The Company attempts to control its exposure to these risks by monitoring its positions as it deems appropriate. All hedges or open positions are reviewed by the Chief Executive Officer before they are committed to, and significant positions are
reviewed by the Company's Board of Directors. The Company had no open trading positions to purchase or deliver natural gas at December 31, 1998. During 1998, the Company had hedged a portion of its expected natural gas production in its key area of production, the Rocky Mountain Region, by entering into a one year commodity swap agreement covering 200,000 MMBtu per month beginning March 1, at a fixed price of $1.855 per MMBtu. At December 31, 1998, the Company had an unrealized loss of $42,000 on the remaining open months of January and February 1999.
6. INCOME TAXES
The provision for income taxes consists of the following components:
During 1998 and 1997, the Company recognized income tax deductions of $23,000 and $143,000, respectively, from the exercise of nonqualified stock options. Stockholders' equity has been credited in the amount of $9,000 and $52,000 for the income tax benefit of these deductions.
The significant components of deferred tax assets and deferred tax liabilities included in the balance sheet are as follows:
A reconciliation of income tax computed at the federal statutory tax rate to the Company's effective tax rate is as follows:
At December 31, 1998, the Company had minimum tax credit carryforwards of approximately $3,674,000, which may be carried forward indefinitely.
7. SEGMENT INFORMATION
The Company organizes its activities in operating segments that consist of 1) the acquisition, exploration, development and operation of oil and gas properties and the development, production and sale of oil and natural gas, 2) the marketing and trading of third party natural gas and 3) providing oil field services for wells which it operates and for third parties. The Company's activities are located primarily in the Rocky Mountain region of the United States, which is one geographic area.
The information below presents the operating segment data for the Company on the basis used by management in deciding how to allocate resources and in assessing performance. 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, 1998, 1997 and 1996. This information is presented on the basis used by management, which is the same basis used in the preparation of the Company's consolidated financial statements.
Total revenue by operating 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 which are eliminated in consolidation. Oilfield services revenue includes $1,074,000, $921,000 and $624,000 for the years ended December 31, 1998, 1997 and 1996, respectively, for intersegment sales. Oilfield services revenue is priced and accounted for consistently for both unaffiliated and intersegment sales.
Identifiable assets by operating 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.
The following customers have each accounted for over 10% of the Company's consolidated revenues and are from the identified operating segment. Following is a table summarizing the percentage of sales made to 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 other customers for the purchase of its production and may be able to secure additional marketing opportunities.
8. COMMITMENTS AND CONTINGENCIES
NOTE GUARANTEE
Bonny Gathering Company ("Bonny"), an unincorporated joint venture of which Prima was the managing joint venturer and operator, established a line of credit with a commercial bank in the amount of $3,500,000 during 1997. The promissory note bore interest at the bank's prime interest rate less 1/2%, payable monthly on the last day of each calendar month. Funds could have been advanced on the line of credit through November 30, 1998 and the note was due November 30, 2001. The note was collateralized by a first priority mortgage and deed of trust on the assets of Bonny. Prima had guaranteed its 15.5%
proportionate share of the note. At December 31, 1998, Bonny had drawn $2,165,000 on the note. On January 21, 1999, the note was paid in full.
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 $126,000, $112,000 and $109,000 for the years ended December 31, 1998, 1997 and 1996, respectively. Future minimum annual rentals under non-cancelable operating leases with remaining terms in excess of one year are as follows:
9. BENEFIT PLANS
EMPLOYEE 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. Options granted under the Plan vest at 20% per year for five years, and expire 10 years from the date of grant. At December 31, 1998, options to acquire 525,500 shares of the Company's common stock were outstanding under the Plan. The exercise prices, which equaled the market price of the stock on the date of grant, range from $8.83 to $19.25 per share, with a weighted average price of $11.58 per share. As of December 31, 1998, the weighted average remaining contractual life of the options outstanding is 6 years, 9 months.
A summary of options granted, exercised and outstanding during 1996, 1997 and 1998 is as follows:
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 and 1998 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:
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:
NON-EMPLOYEE DIRECTORS' STOCK OPTION PLAN
The Board of Directors adopted the Prima Energy Corporation Non-Employee Directors' Stock Option Plan effective September 18, 1998, subject to stockholder approval at the 1999 Annual Meeting of Stockholders. The plan reserves 100,000 shares of Prima's common stock for issuance to non-employee directors at fair market value on the date of grant of a stock option. Upon the effective date of the plan, or upon election as a non-employee director, 10,000 options would be granted each non-employee director. On each anniversary date of the initial grant, an additional 2,500 options would be granted to each non-employee director for as long as they continue to serve on the Board. Options under the plan vest at 20% per year for five years, and expire 10 years from the date of grant. As of December 31, 1998, options to purchase 40,000 shares had been granted under the plan. The option price is $15.00 per share. If the fair market value of the underlying stock exceeds the exercise price on the date of shareholder approval, compensation expense would be recognizable by the Company.
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, 1998, 1997 and 1996, the Company expensed $193,000, $169,000 and $125,000, respectively, of contributions payable to the Plan.
10. SUBSEQUENT EVENTS
The Company sold certain of its oil and gas properties and related assets on January 21, 1999, for approximately $26,000,000 (subject to certain closing and post closing adjustments). The assets sold consisted of all of the Company's interest in 16,253 gross acres and 135 producing wells and related equipment in the Bonny Field in Yuma County, Colorado. Prima also sold its 15.5% interest in the Bonny Gathering Company joint venture, which owned the pipeline, gathering, compression and dehydration facilities at the Bonny Field.
The sales proceeds have been placed in a like-kind exchange escrow account with Norwest Bank Colorado, National Association as escrow agent. The Company intends to identify and close on certain qualifying properties pursuant to the like-kind exchange provisions of Section 1031 of the Internal Revenue Code of 1986. Pursuant to these tax provisions, Prima must identify the qualifying properties within 45 days and close within 180 days of the closing of the Bonny Field transaction. On March 5, 1999, the Company filed a listing of qualifying properties with the escrow agent. This list included oil and gas properties and other real estate properties. There is no assurance the Company will be able to close on these properties within the applicable time limit. To the extent the Company does not close on qualifying properties, the unexpended funds will be disbursed from the escrow account to Prima and will be subject to federal and state income taxes.
11. 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 a 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. The carrying value of this investment at December 31, 1998, was $257,000. During the three years ended December 31, 1998, the Company did not make any capital contributions to the partnership, nor receive any distributions therefrom.
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 as a result of participations in jointly held oil and gas properties. Amounts due to or from officers and directors resulting from billings of joint interest costs or receipts of production revenues on these properties are handled on terms pursuant to standard industry joint operating agreements which are no more or less favorable than these same transactions with unrelated parties.
The Company, a director of Prima and an unrelated third party were working interest owners in the wells at the Bonny Field and joint venturers in Bonny Gathering Company. The director sold his interest in the wells and the joint venture at the same time as the Company and the unrelated third party. The director participated in the original development of the field in 1982 and in the construction and the renovation of the gathering system and continued as a working interest owner and joint venturer until the sale in January 1999.
12. SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED)
Costs incurred in oil and gas property acquisition, exploration and development activities are as follows:
Results of operations for oil and gas producing activities are as follows:
The reserve information presented below was prepared by independent engineers for the years ended December 31, 1998 and 1997 and by Company personnel for the year ended December 31, 1996. 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 require 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:
Oil and natural gas prices in effect at each year end used in calculating reserve estimates are as follows:
Standardized measures of discounted future net cash flows relating to proved oil and gas reserves are as follows:
The principal sources of change in the standardized measure of discounted future net cash flows are as follows:
13. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of the unaudited financial data for each quarter for the years ended December 31, 1998 and 1997.
(1) During the quarter ended March 31, 1998, the Company terminated a gas sales agreement for $3,850,000, which is included in revenues and gross profit, and reported net income of $2,500,000 from this non-recurring item.
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 19th day of March, 1999.
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.