ITEM 3. LEGAL PROCEEDINGS
The Company is a party to various legal proceedings arising in the ordinary course of its business. As of the date of the filing of this report, none of these is anticipated to have a material adverse impact on Prima's financial position or results of operations.
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, 2001.
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. Excluding hedging effects, average natural gas and oil prices realized by the Company at the end of 2001 were 74% and 26% lower, respectively, than at the end of the prior year. To the extent that oil and gas prices decline, the Company's revenues, cash flows, earnings and operations are adversely impacted. Low oil and gas prices, in adversely affecting cash flow and access to capital, could reduce our ability to replace production and grow. 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 the Company's engineers and audited 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 that oil and natural gas prices in effect as of the end of the year remain constant. 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 the Company's exploration, development and acquisition activities in the future will result in the addition of any oil or natural gas reserves that 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 47% of the Company's proved reserves at December 31, 2001 were located in the Wattenberg Area of the Denver Basin, where wells are characterized by relatively rapid initial decline rates. Additionally, approximately 36% of the Company's total proved reserves at December 31, 2001, 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.
ACQUISITIONS RISKS. We continually evaluate opportunities for property or corporate acquisitions that could enhance our business. The successful acquisition of producing properties requires an assessment of several factors, including recoverable reserves, future oil and gas prices, future capital and operating costs, and potential environmental and other liabilities. The accuracy of these assessments is inherently uncertain. In connection with these assessments, we would intend to perform a review of the subject properties consistent with industry practices. However, such review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every property and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties. While it is our current intention to continue to concentrate on acquiring properties with development, exploitation and exploration potential located in our core operating areas, we cannot assure you that in the future we will not decide to pursue acquisitions or properties located in other geographic regions. To the extent that such acquired properties are substantially different than our existing properties, our ability to efficiently realize the economic benefits of such transactions may be limited. We may not be able to successfully integrate future property or corporate acquisitions. We seek to make selective niche acquisitions of oil and gas properties, and we will pursue corporate acquisitions that we believe will be accretive. However, integrating acquired properties and businesses involves a number of special risks. These risks include the possibility that management may be distracted from normal business concerns by the need to integrate operations and systems and in retaining and assimilating additional employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results.
DEPENDENCE ON TRANSPORTATION FACILITIES OWNED BY OTHERS. Our business depends on transportation facilities owned by others. The marketability of our oil and gas production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties. The unavailability of or lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Although we have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.
DERIVATIVES ACTIVITIES. Part of the Company's business strategy is to periodically use both commodity futures contracts and price and basis swaps to mitigate the impact of the volatility of oil and natural gas prices on a portion of our production and gas marketing activities. In certain circumstances, significant reductions in production, due to unforeseen events, could require the Company to make payments under such agreements even though payments are not offset by production. To reduce this risk, the Company generally strives to enter into derivatives for only a portion of its projected production. Derivatives may also prevent the Company from receiving the full advantage of increases in oil or natural gas prices. Further, such transactions may expose us to additional risk of financial loss in certain circumstances, including instances in which counterparties to our futures contracts fail to perform under the contracts or ineffectiveness of our derivatives result in losses not offset by increased sales revenue. The terms of our hedging agreements may also require that we furnish cash collateral, letters of credit or other forms of performance assurance in the event that mark-to-market calculations result in settlement obligations by us to the counterparties, which could encumber our liquidity and capital resources. We adopted Statement of Financial Accounting Standards (SFAS) No. 133 on January 1, 2001, which requires us to record each hedging transaction as an asset or liability measured at its fair value. Each quarter we must record changes in the value of our hedges, which could result in significant fluctuations in net income and stockholders' equity from period to period.
CAPITAL REQUIREMENTS. We anticipate continuing to make substantial expenditures to find, develop, acquire and produce oil and gas reserves. We expect to have sufficient cash provided by operating activities and from available net working capital to fund planned capital expenditures in 2002. However, we have not established a line of credit to provide additional capital if required to respond to new opportunities. While we believe that we could arrange for borrowings or issuance of securities to fund such opportunities, should lower oil and gas prices or operating difficulties
result in our cash flow from operations being less than expected or if capital markets were to deteriorate, we may be unable to obtain additional funds to expand our business.
DEMAND FOR OILFIELD SERVICES. Our oilfield services operations are dependent on the level of demand in our operating markets. Both short-term and long-term trends in oil and natural gas prices affect demand. Because oil and natural gas prices are volatile, the level of demand for our services can also be volatile. Although Prima utilizes its service companies in its oil and gas operations, the substantial majority of the demand for their services is dependent on third parties. In addition to oil and gas prices, factors which can influence activity levels for our oilfield service operations include competition, our experience and reputation, the availability of labor, and the weather.
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, nuclear 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. As an example, the Company's exploration and development plans for its Powder River Basin CBM properties are dependent upon the timing, content and implementation of a pending record of decision by the Bureau of Land Management concerning an environmental impact statement covering CBM development in the area. 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 effects 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.
ENVIRONMENTAL REGULATION. We must comply with complex environmental regulations. Our operations are subject to complex and constantly changing environmental laws and regulations adopted by federal, state and local governmental authorities where we are engaged in exploration or production operations. New laws or regulations, or changes to current requirements, could have a material adverse effect on our business. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state and federal agencies. We could face significant liabilities to the government and third parties for discharges of oil, natural gas or other pollutants into the air, soil or water, and we could have to spend substantial amounts on investigations, litigation and remediation. We cannot be sure that existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced or altered in the future, will not materially adversely affect our results of operations and financial condition. As a result, we may face material indemnity claims with respect to properties we own or have owned.
KEY PERSONNEL. We depend on the continued services of our executive officers. Loss of the services of any of these people could have a material adverse effect on our operations. We currently do not have employment agreements with any of our executive officers, including Richard H. Lewis, who serves as the Company's Chief Executive Officer, President and Chairman of the Board of Directors.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
Prima's common stock trades on the Nasdaq National 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, 2001 and 2000. These prices have been restated to reflect the effect of the three for two split of Prima's common stock distributed on February 24, 2000 and the three for two split of Prima's common stock distributed on December 11, 2000.
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.
On March 15, 2002, the closing sale price for the Company's common stock was $25.20 per share. Prima's common stockholders of record at March 15, 2002 totaled 849.
Holders of common stock are entitled to receive such dividends as may be declared by Prima's Board of Directors. No cash dividends were declared or paid in 2001, 2000 or 1999. Future cash dividends, if any, will be evaluated based among other things, on operating results, capital requirements and financial condition of the Company at the time.
During 2001, Prima issued a total of 10,125 common shares and options to acquire a total of 135,000 common shares that were not registered under the Securities Act of 1933, as amended. The shares and options were issued as follows:
o Prima issued a total of 10,125 common shares during July 2001 to a former director of Prima upon exercise of stock options previously granted to that director under Prima's Non-Employee Directors' Stock Option Plan.
o Options to acquire a total of 22,500 common shares were granted by Prima to directors of Prima under the terms of Prima's Non-Employee Directors' Stock Option Plan.
o Options to acquire a total of 112,500 common shares were granted to certain officers of Prima under the terms of Prima's 2001 Incentive Stock Plan.
No underwriter was involved in any of the transactions and no sales commissions, fees, or similar compensation were paid by Prima to any person in connection with the issuance of the shares and options. Prima believes that the grant of the options and the issuance of the shares in each instance was exempt from the registration requirements of Section 5 of the Securities Act by virtue of Section 4(2) of the Securities Act and/or under Rule 506 of Regulation D promulgated by the SEC thereunder, since each recipient of the common shares and options was a director and/or executive officer of Prima.
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" which are made pursuant to the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995. These statements include, without limitation, statements relating to liquidity, financing of operations, continued volatility of oil and natural gas prices, estimates of future production and net cash flows attributable to proved reserves, future expenditures, and other such matters. The words "anticipates," "believes," "expects," "intends" 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".
The following discussion is intended to assist in understanding the Company's financial position and results of operations for the three-year period ended December 31, 2001. The Consolidated Financial Statements and notes thereto should be referred to in conjunction with this discussion.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our discussion of financial condition and results of operation are based upon the information reported in our consolidated financial statements. The preparation of these financial statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our decisions on historical experience and various other sources that are believed to be reasonable under the circumstances. Actual results may differ from the estimates we calculated due to changing business conditions or unexpected circumstances. Policies we believe are critical to understanding our business operations and results of operations are detailed below. For additional information on our significant accounting policies you should see Notes to Consolidated Financial Statements, particularly Notes 1 and 11, in our accompanying consolidated financial statements.
Revenue Recognition - We are engaged in the exploration, development, acquisition and production of natural gas and crude oil. Our revenue recognition policy is significant because our revenue is a key component of our results of operations and our forward looking statements contained in Liquidity and Capital Resources. We derive our revenue primarily from the sale of produced natural gas and crude oil. Revenue is recorded in the month our production is delivered to the purchaser, but payment is generally received between 20 and 90 days after the date of production. At the end of each period we make estimates of the amount of production delivered to the purchaser and the price we received. We use our knowledge of our properties, their historical performance, NYMEX and local spot market prices and other factors as the basis for these estimates. Variances between our estimates and the actual amounts received, which have historically been minimal, are recorded in the month such estimates are revised or when payment is received.
Fair Value of Derivative Instruments - Beginning in 2001, the estimated fair values of our derivative instruments are recorded on our consolidated balance sheet. All of our derivative instruments are entered into to mitigate risks related to the prices we will receive for our future natural gas and oil production. We do not use derivative instruments for trading purposes. Although our derivatives are reported on the balance sheet at fair value, to the extent that instruments qualify for hedge accounting treatment, changes in fair value are not included in our consolidated results of operations. Instead, they are recorded net of taxes directly to stockholders' equity until the hedged oil or natural gas quantities are produced. To the extent changes in the fair values of derivatives relate to instruments not qualifying for hedge accounting treatment, such changes are recorded in income in the period they occur. In determining the amounts to be recorded, we are required to estimate the fair values of derivatives. Our estimates are based upon various factors that include contract volumes and prices, contract settlement dates, quoted closing prices on the NYMEX or over-the-counter and, where applicable, volatility and the time value of options. The calculation of the fair value of collars and floors requires the use of the Black-Scholes option-pricing model. The estimated future prices are compared to the prices fixed by the derivatives agreements and the resulting estimated future cash inflows or outflows over the lives of the hedges are discounted to calculate the fair value of the derivative contracts. These pricing and discounting variables are sensitive
to market volatility as well as changes in future price forecasts, regional price differences and interest rates. We periodically validate our valuations using independent third party quotations.
Reserve Estimates - The Company's estimates of gas and oil reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as expected future production rates, gas and oil prices, operating costs, severance taxes, and development costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to an extent that these reserves may later be determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company's gas and oil properties and/or the rate of depletion of the gas and oil properties. Actual production, revenues and expenditures with respect to the Company's reserves will likely vary from estimates, and such variances may be material.
Full Cost Method - We use the full cost method of accounting for our oil and gas activities. Under this method, all costs incurred in the acquisition, development and exploration of oil and gas properties are capitalized into cost centers that are established on a country-by-country basis (we have a single cost center, for the United States). Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs and delay rentals. Capitalized costs also include salaries, employee benefits, costs of consulting services and other expenses that are directly related to acquisition, development and exploration activities. Costs associated with production and general corporate activities are expensed in the period incurred.
Depletion - The capitalized costs of our oil and gas properties, plus estimated future development and abandonment costs related to our proved reserves, are amortized on a unit-of-production method based on our estimate of total proved reserves. The quantities of estimated proved oil and gas reserves is a significant component of amortization and revisions in such estimates may alter the rate of future expense. Generally, if reserve volumes increase or decrease, then the amortization rate per unit of production will change inversely. However, when capitalized costs change, the amortization rate moves in the same direction. The per-unit rate is not affected by production volumes.
Full Cost Ceiling Limitation - Under the full cost method, we are subject to quarterly calculations of a limitation, or "ceiling", on the amount of our oil and gas properties that can be capitalized on our balance sheet. If the net capitalized costs of our oil and gas properties exceed the cost center ceiling, we are subject to a ceiling test writedown to the extent of such excess. A ceiling test writedown is a non-cash charge to earnings. If required, it would reduce earnings and impact stockholders' equity in the period of occurrence and result in lower amortization expense in future periods. The discounted present value of our proved reserves is a major component of the ceiling calculation and requires subjective judgments. Given the volatility of natural gas and oil prices, it is likely that our estimate of discounted future net cash flows from proved reserves will change in the future. If natural gas and oil prices decline, even if only for a short period of time, or if we have downward revisions to our estimated proved reserves, it is possible that writedowns of our oil and gas properties could occur. While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. The future net revenues associated with our estimated proved reserves are not based on our assessment of future prices or costs. The ceiling calculation dictates that prices and costs in effect as of the last day of the quarter are held constant. However, we may not be subject to a writedown if prices increase shortly after the end of a quarter in which a writedown might otherwise be required.
Unevaluated Costs - Unevaluated costs are excluded from our amortization base until we have evaluated the properties associated with these costs. The costs associated with unevaluated leasehold acreage and wells that have not yet been determined to be productive or non-productive are not initially included in our amortization base. Leasehold and associated costs are either transferred to our amortization base with the costs of drilling related wells or are assessed quarterly for possible impairment or reduction in value. Leasehold costs are transferred to our amortization base if estimated fair value is below cost. The decision to withhold costs from amortization and the timing of transferring such costs into the amortization base involves a significant amount of management judgment and may be subject to changes over time based on several factors, including our drilling plans, availability of capital, project economics and results of drilling on adjacent acreage.
Other Property and Equipment - Oilfield service equipment and other property and equipment are carried at cost. Renewals and betterments are capitalized, while repairs and maintenance are expensed. Capitalized costs are depreciated using the straight-line method over the estimated useful lives of the assets. The carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets. Changes in such estimates could cause the Company to reduce the carrying value of property and equipment.
Income Taxes - We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Our federal and state income tax returns are generally not filed before the consolidated financial statements are prepared. We, therefore, estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits and net operating loss carryforwards. Any differences between estimates we initially used and subsequently determined to be appropriate are recorded in the period in which our estimate is revised.
LIQUIDITY AND CAPITAL RESOURCES
The Company's principal sources of liquidity have been the internal generation of cash flow from operations and existing net working capital. Additional potential sources of capital include proceeds from the sale of assets, borrowings, and issuances of common stock or other securities.
Net cash provided by operating activities totaled $43,008,000 in the year ended December 31, 2001, compared to $36,376,000 for the year ended December 31, 2000 and $12,006,000 for the year ended December 31, 1999. Net working capital at December 31, 2001 totaled $28,122,000, as compared to $25,678,000 at the end of the prior year. Prima's cash equivalents and short-term investments totaled $25,755,000 at December 31, 2001, compared to $22,693,000 at December 31, 2000, and the Company was free of long-term debt at both dates.
The Company's revenues and cash flows are substantially derived from oil and gas sales, which are dependent on oil and gas production volumes and sales prices. Prima's aggregate net production volumes have increased from 2,765,000 Mcfe in the first quarter of 2001, to 2,892,000 Mcfe in the second quarter, 3,088,000 Mcfe in the third quarter and 3,118,000 in the most recent quarter, but gas prices have declined more significantly during the same periods. As a consequence, the Company's oil and gas sales revenue, including derivatives qualifying for hedge accounting, declined from $16,357,000 in the first quarter, to $11,909,000 in the second quarter, $9,163,000 in the third quarter and $7,119,000 in the latest quarter. For the full year in 2001, Prima's oil and gas sales totaled $44,548,000, approximately flat with the prior year, on a 5% increase in total net production. Prima's future revenues will continue to be significantly affected by volatility in oil and gas prices.
This volatility in oil and gas prices is also reflected in year-end estimates of the Company's proved oil and gas reserves and related future net cash flows. Estimated future net cash flows from proved oil and gas reserves were
$156,624,000 at December 31, 2001 compared to $975,940,000 at December 31, 2000 and $190,008,000 at December 31, 1999. The standardized measure of discounted future net cash flows of the Company's proved oil and natural gas reserves was $66,801,000 at December 31, 2001, compared to $371,121,000 at December 31, 2000 and $75,466,000 at December 31, 1999. The fluctuations in both future net cash flows and the standardized measure were primarily attributable to the volatility of commodity prices. The Company's average realized prices as of the last day of each of the past three years, which were therefore used without future escalation in preparing year-end reserve estimates, were as follows for 2001, 2000 and 1999, respectively: $1.94, $7.51 and $1.90 per Mcf of natural gas; and $19.71, $26.48 and $24.68 per barrel of oil.
The Company increased its net working capital, with the sale of certain oil and gas properties on March 5, 2002 for approximately $13,539,000 of cash. The assets sold included the Company's Stones Throw CBM project in the northern Powder River Basin, the associated gathering system facilities and approximately 35,000 net undeveloped acres in the Stones Throw area. These properties accounted for approximately 6.1% of Prima's total estimated proved oil and gas reserves and 4.5% of the related estimated present value of future net cash flows before income taxes, as of the end of 2001. The producing wells sold accounted for approximately 9.6% of Prima's total oil and gas sales revenue before hedging gains in the fourth quarter of 2001.
The Company's average daily net production in the fourth quarter of 2001 totaled approximately 33,900 Mcfe, including 6,300 Mcf per day of CBM production from the Stones Throw Field, which was sold on March 5, 2002. In the absence of an acquisition in the interim, Prima does not expect significant production from new sources until the third quarter of this year, when production from the Company's Porcupine-Tuit CBM project is expected to commence. No other major variances from recent production levels are expected in the near term. Prima has drilled 23 Wyodak coal wells at Porcupine-Tuit to-date and has 72 additional locations in the project area identified for near-term drilling, but 63 of these are on federal lands for which drilling access is presently limited. Production reported for several nearby wells owned by other operators have been in the 150 to 400 Mcf per day per well range, after brief de-watering periods. The Company expects production from its wells in this area to exhibit similar performance, but cannot precisely forecast when production will be initiated or how the wells will then perform. The timing and amounts of production that may be added later in the year from other new activities, including other CBM projects and exploration also cannot be precisely forecast.
Prima invested $35,248,000 in additions to oil and gas properties during 2001, compared to $31,952,000 in 2000 and $18,617,000 in 1999. During 2001, $31,114,000 was expended for development, $1,620,000 for exploratory activities, $2,114,000 for acquisitions of unproved oil and gas properties, and $400,000 for purchases of proved properties. Other uses of funds in 2001 included $3,866,000 for treasury stock repurchases, $1,956,000 for purchases of oilfield service equipment and facilities, and $125,000 for other assets.
Excluding acquisitions, Prima currently plans to make capital investments in 2002 aggregating between $25 million and $30 million. Among anticipated 2002 drilling activities are 60 to 110 CBM wells, six to 12 wells in the Denver Basin, and three to six exploratory wells. The Company also intends to invest in various hook-up and infrastructure projects, including the Porcupine-Tuit CBM project in the Powder River Basin, and anticipates conducting 40 to 50 refracturing or recompletion operations in the Denver Basin. A significant portion of the 2002 budget has also been reserved for acquisition of additional acreage for future exploration or exploitation, or for other opportunities identified during the year. Activities planned by the Company for 2002 are weighted toward the second half of the year. This may enable the Company to benefit from development and operating efficiencies related to the expected issuance by the Bureau of Land Management of a record of decision concerning an environmental impact statement (EIS) for CBM development in the Powder River Basin. Approximately 82% of Prima's Powder River Basin acreage is federal, and access to federal lands has been limited pending completion of the EIS. The Company has also been deferring certain investments to benefit from anticipated improvements in gas prices and service costs, which have recently begun to materialize. Prima does not establish a specific budget for property acquisitions, but the Company continues to pursue such opportunities on an ongoing basis. The strong financial condition of the Company allows for considerable flexibility in responding to opportunities. Spot market prices for gas and oil have risen by approximately 20% from levels prevailing when the Company's budgeting process was initially completed. These prices, if deemed sustainable, may result in an acceleration of activities, which could include additional Powder River Basin CBM and Denver Basin drilling.
In January 2001, Prima's Board of Directors approved a repurchase program of up to 5% of the Company's common stock then outstanding, or approximately 640,000 shares. As of December 31, 2001, approximately 485,000 shares remained subject to repurchase under this authorization.
Prima expects to fund its exploration, development, and exploitation operations, the expansion of its service companies, and any re-purchases of common stock primarily with cash provided by operating activities and working capital. The Company also regularly reviews opportunities for acquisition of assets or companies related to the oil and gas industry that could expand or enhance its existing business. If a sufficiently large transaction is consummated, it could involve the incurrence of debt or issuance of equity securities.
RESULTS OF OPERATIONS
As noted above, the Company's primary source of revenues is the sale of oil and natural gas production. Because of significant fluctuations in oil and natural gas prices and variances in production volumes, the Company's operating results for any period are not necessarily indicative of future operating results.
Historically, oil and natural gas prices have been volatile and are likely to continue to be volatile. Prices are affected by, among other things, market supply and demand factors, market uncertainty, and actions of the United States and foreign governments and international cartels. These factors are beyond the control of the Company. Prima's revenues, cash flows, earnings and operations are adversely affected when oil and gas prices decline. Gas prices have declined significantly since reaching record high levels early in 2001, and oil prices have also declined during the past year, albeit more modestly. These price declines have unfavorably impacted the Company's operating results, as more fully described below. The Company cannot accurately predict future oil and natural gas prices, but historically oil and gas supply and demand have responded to changes in price levels to correct from short-lived extreme levels of high or low prices.
2001 VS 2000
For the year ended December 31, 2001, the Company earned net income of $23,768,000, or $1.80 per diluted share, on revenues of $60,287,000, compared to net income of $21,895,000, or $1.65 per diluted share, on revenues of $52,179,000 for the year ended December 31, 2000. Expenses, other than income taxes, were $26,480,000 for 2001 compared to $20,749,000 for 2000. Revenues increased $8,108,000 or 16%, expenses increased $5,731,000 or 28% and net income increased $1,873,000 or 9% in 2001.
Revenues for 2001 included $9,816,000 of gains from oil and gas derivatives (see "Derivative Activities" in Notes to Consolidated Financial Statements). This total included hedging gains of $3,381,000, which were reflected in oil and gas sales, plus $6,435,000 of separately reported gains on derivative instruments not qualifying for hedge accounting, of which $2,057,000 were realized and $4,378,000 were unrealized as of December 31, 2001. During the prior year the company recognized $42,000 of hedging gains. Derivative instruments that did not qualify for hedge accounting were principally NYMEX gas swaps for which the Company did not elect to enter into corresponding swaps for Rocky Mountain basis differentials.
Oil and gas sales reported for 2001 totaled $44,548,000, compared to $44,437,000 for 2000, an increase of less than 1%. The flat sales results were creditable to a 5% year-over-year growth in production volumes offset by approximately a like-sized decline in the average price realized per equivalent unit of natural gas and oil production. Excluding gains from derivative instruments, oil and gas sales reported for 2001 were $41,167,000, compared to $44,395,000 for 2000, a decrease of $3,228,000 or 7%.
The following information is provided excluding effects of derivatives. The average sales price received by the Company for natural gas production was $3.24 per Mcf in 2001, compared to $3.63 per Mcf in 2000, a decrease of $0.39 per Mcf, or 11%. The average price received per barrel of oil was $25.68 in 2001, compared to $29.20 in 2000, representing a decrease of $3.52 per barrel or 12%. On an Mcf equivalent basis, the average price received was $3.47
per Mcfe in 2001 compared to $3.92 per Mcfe in the prior year, representing an overall 11% decline in average prices. The portion of the Company's total oil and gas revenues that was derived from natural gas was 73% in 2001 compared to 71% in 2000.
The $3,381,000 of gains from derivative transactions that were accounted for as hedges in 2001 had the effect of increasing average price realizations reported for the year by $0.36 per Mcf of natural gas, $0.20 per barrel of oil, and $0.29 per Mcfe. These hedges covered approximately 24% of the Company's natural gas production and 19% of its oil production for the year. Total gains realized on all derivatives related to production months in 2001, including the portion reported as non-hedge derivatives, totaled $5,438,000. During 2000, the Company hedged approximately 1% of its gas production and 5% of its oil production, and realized gains of $42,000 were included in oil and gas revenues. These gains had the effect of increasing average price realizations by $0.09 per barrel of oil, but had a negligible impact on average price realizations per Mcf of gas or per Mcfe.
The Company's natural gas production totaled 9,277,000 Mcf in 2001 compared to 8,683,000 Mcf in 2000, representing a current year increase of 594,000 Mcf, or 7%. Prima's oil production totaled 431,000 barrels and 440,000 barrels in 2001 and 2000, respectively, representing a decrease of 9,000 barrels, or 2%. On an equivalent unit basis, the Company's production increased approximately 5%, to 11,863,000 Mcfe in the recent year from 11,325,000 Mcfe in 2000. Total production was 78% natural gas and 22% oil in 2001, compared to 77% gas and 23% oil in the prior year. Net production from the Company's CBM operations, which totaled 1,453,000 Mcf in 2001 compared to 7,000 Mcf in 2000, more than offset net decreases from the Company's other producing properties, which were attributable to natural declines and limited new activity.
The Company's depletion expense for oil and gas properties was $9,190,000, or $0.77 per Mcfe, in 2001, compared to $6,150,000, or $0.54 per Mcfe, in 2000. The substantial increase in the depletion rate reflects a number of factors, including: significant declines in oil and gas prices, which, under the methodology prescribed, affects estimates of oil and gas reserves that can be economically recovered through future production; increases in oilfield service costs, which impacted actual costs incurred during the past year and the assumptions required to be used in estimating future development costs; and use of more conservative assumptions for estimating undeveloped CBM reserves, pending additional performance-related data. The depletion rate per Mcfe was increased mid-year 2001 to reflect these factors, and averaged $0.90 during the second half of the year.
Depreciation of other fixed assets, which include service equipment, office furniture and equipment, and buildings, was $1,369,000 and $1,054,000 for 2001 and 2000, respectively. The increase of $315,000, or 30%, was due primarily to acquisitions of oilfield service equipment in 2000 and 2001.
Lease operating expenses ("LOE") totaled $3,295,000 for the year ended December 31, 2001 compared to $2,623,000 for the year ended December 31, 2000, an increase of $672,000 or 26%. The increase was primarily attributable to new production from CBM wells. Ad valorem and production taxes were $3,344,000 and $3,421,000 for the same periods, a decrease of $77,000 or 2%. Production taxes fluctuate with revenues and changing mill levy rates. Total lifting costs (LOE plus ad valorem and production taxes) were 15% of oil and gas revenues and $0.56 per Mcfe for 2001 compared to 14% and $0.53 per Mcfe for 2000.
Oilfield services include the operations of Action Oilfield Services, Inc. (Colorado) and Action Energy Services (Wyoming), wholly-owned subsidiaries. Related revenues include well servicing fees from completion and swab rigs, CBM drilling rigs, trucking, water hauling, equipment rentals, and other related activities. Services are provided to both Prima and unaffiliated third parties, but intercompany billings are eliminated in consolidation. Revenues from third parties totaled $8,090,000 for the year ended December 31, 2001 compared to $6,278,000 for the year ended December 31, 2000, an increase of $1,812,000, or 29%. Costs of oilfield services provided to third parties were $5,482,000 in 2001 compared to $4,585,000 for 2000, an increase of $897,000 or 20%. Higher revenues and costs both reflected increases in the amount of equipment placed in service and the portion of services provided to third parties. Approximately 34% of fees billed by the service companies in 2001 were for Company-owned property interests, compared to 37% in 2000. Improved revenues were also partially attributable to rate increases resulting from increased demand for oilfield services.
General and administrative expenses ("G&A"), net of third party reimbursements and amounts capitalized, were $3,559,000 for the year ended December 31, 2001 compared to $2,916,000 for the year ended December 31, 2000. Net G&A costs increased by $643,000 or 22% due to expansion of the Company's activities and operations, partially offset by increased amounts capitalized. Third party reimbursements of management and operator fees decreased from $426,000 in 2000 to $371,000 in 2001 due to the Company's acquisition of additional ownership interests in certain managed properties. Capitalized G&A increased from $1,200,000 in 2000 to $1,573,000 in 2001, reflecting additional costs incurred to grow exploration and development activities.
The impairment of a natural gas swap in 2001 relates to a derivatives contract with Enron North America Corp, which filed for bankruptcy protection in December 2001. Prima had an unrealized gain of $241,000 due from Enron when the Company terminated the contract under default provisions in the agreement. Although this amount was reflected in gains on derivative instruments in 2001, the full amount was reserved for and reflected as an impairment expense in the same period.
The provision for income taxes was $10,650,000 for the year ended December 31, 2001 compared to $9,535,000 for the year ended December 31, 2000, an increase of $1,115,000 or 12%. The Company's effective tax rate increased to 31.5% in 2001 from 30.3% in 2000. The effective tax rates in both years were less than statutory rates due to permanent differences in financial and taxable income, consisting primarily of statutory depletion deductions and Section 29 tax credits. The higher effective tax rate in 2001 was primarily attributable to a $2,377,000, or 8%, increase in pre-tax income without a proportionate increase in permanent differences.
2000 VS 1999
Prima earned net income in 2000 of $21,895,000, or $1.65 per diluted share, on revenues of $52,179,000, compared to net income of $9,027,000, or $0.69 per diluted share, on revenues of $29,222,000 in 1999. Expenses, other than income taxes, were $20,749,000 for 2000 compared to $17,160,000 for 1999. Revenues increased $22,957,000 or 79%, expenses increased $3,589,000 or 21% and net income increased $12,868,000 or 143% in 2000, compared to 1999.
Oil and gas sales in 2000 were $44,437,000 compared to $20,644,000 in 1999, an increase of $23,793,000 or 115%. This increase was due to both significantly higher product prices and increased production. The Company's net natural gas production was 8.7 Bcf for 2000 compared to 7.2 Bcf in 1999, an increase of 1.5 Bcf or 21%. Net oil production was 440,000 barrels in 2000 compared to 322,000 barrels for 1999, an increase of 118,000 barrels or 37%. On an Mcfe basis, the Company's production for 2000 increased 2.2 Bcfe or 25%. The average price received per Mcf of natural gas sold was $3.63 for 2000 compared to $2.10 per Mcf for the prior year, an increase of $1.53 per Mcf or 73%. The average price received per barrel of oil sold was $29.29 in 2000 compared to $17.42 in 1999, an increase of $11.87 per barrel or 68%. During the year ended December 31, 2000, the Company hedged approximately 1% of its gas production and 5% of its oil production. Hedging gains of $42,000 were included in oil and gas revenues for the year, which increased the average price received per barrel of oil by $0.09 and had no material effect on the price realized for natural gas or per equivalent unit of production. The Company hedged approximately 25% of its oil production and 15% of its natural gas production in 1999. Hedging losses of $180,000 were included in oil and gas revenues for the year, which decreased average prices received by $0.17 per barrel of oil, by $0.02 per Mcf of natural gas, and by $0.02 per Mcfe of production.
The Company's depletion of oil and gas properties was $6,150,000, or $0.54 per Mcfe, on 11,325,000 equivalent Mcf produced in 2000. This compared to $4,650,000, or $0.51 per Mcfe, on 9,093,000 equivalent Mcf produced in 1999. The higher depletion rate for 2000 reflected higher oilfield service costs experienced during the fourth quarter of 2000, as industry activity escalated. Depreciation of other fixed assets, including service equipment, office furniture and equipment and buildings, was $1,054,000 and $817,000 for 2000 and 1999, respectively. Depreciation expense on these assets increased $237,000, or 29%, due primarily to acquisitions of oilfield service equipment.
LOE was $2,623,000 in 2000 compared to $2,012,000 in 1999. Ad valorem and production taxes were $3,421,000 and $1,765,000, respectively, for the same periods. Production taxes increased with oil and gas revenues, on higher production volumes and product prices. Total lifting costs were 14% of oil and gas revenues and $0.53 per Mcfe for 2000, compared to 18% and $0.42 for 1999.
Oilfield services revenues were $6,278,000 and $4,974,000 in 2000 and 1999, respectively. Costs for oilfield services were $4,585,000 in 2000 compared to $3,377,000 in 1999. These amounts reflect an increase in revenues of $1,304,000, or 26%, and an increase in costs of $1,208,000 or 36%. Utilization levels in the Wattenberg Area remained high and activity levels increased steadily during the period in the Powder River Basin of Wyoming, where service operations were initiated in March 1999. During 2000 and 1999, 37% and 26%, respectively, of the gross fees billed by the service companies were for Prima-owned property interests.
Trading revenues and costs relate to the marketing of third-party gas by Prima Natural Gas Marketing, Inc., a wholly owned subsidiary. Trading activities fluctuate with natural gas markets and the Company's ability to develop markets that meet the Company's trading criteria. The Company engaged in no trading activities during 2000. In 1999, the Company marketed 1,311,000 Mmbtus of natural gas, with trading revenues of $2,318,000 and costs of $2,827,000. G&A, net of third-party reimbursements, totaled $2,916,000 for 2000 compared to $1,712,000 for 1999, an increase of $1,204,000 or 70%. Third-party reimbursements were $426,000 and $619,000 during 2000 and 1999, respectively. The Company's G&A increased due to expansion of the Company's operations, particularly increased activities in the Powder River Basin. The Company capitalized G&A costs of $1,200,000 and $780,000 in 2000 and 1999, respectively, reflecting these increases in exploration and development activities.
The provision for income taxes was $9,535,000 for 2000 compared to $3,035,000 for 1999. The effective tax rate was 30.3% in 2000 compared to 25.2% in 1999. The Company's effective tax rate increased primarily because pre-tax income increased $19,368,000 or 161% for 2000, while permanent differences did not increase proportionately.
NEW ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standard ("SFAS") No. 141, "Business Combinations." SFAS No. 141 is intended to improve the transparency of the accounting and reporting for business combinations by requiring that all business combinations be accounted for under a single method, the purchase method. This statement is effective for all business combinations initiated after June 30, 2001. Management does not believe the adoption of this statement will have a material effect on the Company's financial position or results of operations.
In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets." This statement applies to intangibles and goodwill acquired after June 30, 2001, as well as goodwill and intangibles previously acquired. Under this statement, goodwill as well as other intangibles determined to have an infinite life will no longer be amortized. These assets will be reviewed for impairment on a periodic basis. This statement is effective for the Company in the first quarter of 2002. Management does not believe the adoption of this statement will have a material effect on the Company's financial position or results of operations.
In August 2001, the FASB issued SFAS No. 143 "Accounting for Asset Retirement Obligations." SFAS No. 143 provides the accounting requirements for retirement obligations associated with long-lived assets and requires the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying costs of the asset. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002, and early adoption is permitted. The Company is currently assessing, but has not yet determined, the impact of SFAS No. 143 on its consolidated results of operations, cash flows or financial position.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 requires that long-lived assets be measured at the lower of carrying amount or fair value less costs to sell, whether reported in continuing operations or in discontinued operations. Therefore, discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. SFAS No. 144 is effective for financial statements issued for fiscal years beginning after December 15, 2001 and generally is to be applied prospectively. Management does not believe the adoption of this statement will have a material effect on the Company's financial position or results of operations.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's primary market risks relate to changes in prices received on sales of natural gas and oil production. The Company periodically enters into derivative contracts to mitigate a portion of this commodity price risk. Such derivatives consist of commodity futures or price swaps (agreements with counterparties to exchange floating prices for fixed prices), and options on such futures or price swaps. These instruments reduce the Company's exposure to decreases in gas and oil prices, or increases in differentials between NYMEX and Rocky Mountain gas prices, but they also generally limit the benefits realized by the Company from increases in prices or narrowing of basis differentials. By hedging only a portion of its exposure to changes in prices, the Company is able to benefit from increases in gas and oil prices or improvements in basis differentials, but it remains exposed to market risk on the portion of its production not covered by such derivatives. The Company also retains risks related to the ineffective portion of its derivatives instruments, when applicable.
The Company has derivative positions that are intended to offset risks associated with downward price movements in benchmark NYMEX gas and oil prices and basis swaps to protect the Company from increases in the differential between NYMEX and Rocky Mountain gas prices. The Company's derivatives contracts generally represent cash flow hedges that are determined to be qualifying or non-qualifying for hedge accounting treatment in accordance with the provisions of SFAS 133. See Derivative Activities in Notes to Consolidated Financial Statements for additional information with respect to derivatives and related accounting policies.
All derivatives transactions are executed by personnel who have appropriate skills, experience and supervision. The personnel involved in these activities must follow prescribed trading limits and parameters that are regularly reviewed by the Company's Chief Executive Officer. All derivatives transactions are approved by the Company's Chief Executive Officer before being entered into and significant transactions are reviewed by the Company's Board of Directors. The Company uses only conventional derivative instruments and attempts to manage its credit risk by entering into derivative contracts only with financial institutions that are believed to be reputable and which carry an investment grade rating.
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 positions. It is not possible to accurately predict future movements in natural gas and oil prices.
During 2001, the Company sold 431,000 barrels of oil. A hypothetical decrease of $2.57 per barrel (10% of average prices for the period exclusive of hedging transactions) would have decreased the Company's production revenues by $1,108,000 for the period. The Company sold 9,277,000 Mcf of natural gas during the same period. A hypothetical decrease of $ 0.32 per Mcf (10% of average prices for the period exclusive of hedging transactions) would have decreased the Company's production revenues by $2,969,000 for the period.
The Company closed certain derivative instruments between December 31, 2001 and March 15, 2002, for net realized gains totaling $2,450,000. As of March 15, 2002, open oil and gas derivative instruments showed net unrealized losses of $48,000, as follows:
As of December 31, 2001, the Company had $4,378,000 of unrealized gains on derivatives that did not qualify for hedge accounting, which had been reported as revenue in 2001, and $94,000 of unrealized mark-to-market gains on derivatives treated as hedges, which amount was included in other comprehensive income for 2001. This total of $4,472,000 exceeded the aggregate of gains realized on derivatives in 2002 through March 15 and the net unrealized loss on derivatives outstanding at that date by $2,070,000. This amount less the $94,000 of unrealized hedging gains which were not reported as revenue in 2001 would be recorded as a reduction of current period or future revenue if gas and oil prices were to remain at levels reflected on futures markets as of March 15, 2002. Such amounts will change, however, potentially significantly, as gas and oil prices rise or fall before such contracts expire or are terminated.
The table above excludes commodity positions with Enron North America Corp, which filed for bankruptcy protection in December 2001. Prima's unrealized hedge gain due from Enron totaled approximately $241,000 when the Company terminated the contract under default provisions in the agreement. Although this amount was reflected in gains on derivative instruments in 2001, the full amount was reserved for and reflected as an impairment expense in the same period.
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 15, 2002 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
(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
3 Certificate of Incorporation of Prima energy Corporation, Delaware, as filed August 18, 1988. (Incorporated by reference to Registration of Securities of Certain Successor Issuers on Form 8-B dated January 20, 1989.)
3 Certificate of Amendment of Certificate of Incorporation of Prima Energy Corporation filed May 1, 1989. (Incorporated by reference to Annual Report on Form 10-K for Prima Energy Corporation dated June 30, 1989.)
3 Bylaws of Prima Energy Corporation. (Incorporated by reference to Registration of Securities of Certain Successor Issuers on Form 8-B dated January 20, 1989.)
3 Certificate of Amendment of the Certificate of Incorporation of Prima Energy Corporation. (Incorporated by reference to Quarterly Report on Form 10-Q for Prima Energy Corporation dated June 30, 1997.)
3 Certificate of Amendment of the Certificate of Incorporation of Prima Energy Corporation. (Incorporated by reference to Quarterly Report on Form 10-Q for Prima Energy Corporation dated September 30, 2000.)
3 Certificate of Amendment of the Certificate of Incorporation of Prima Energy Corporation. (Incorporated by reference to Quarterly Report on Form 10-Q for Prima Energy Corporation dated June 30, 2001 and filed August 14, 2001.)
4 Rights Agreement dated as of May 23, 2001, between Prima Energy Corporation and Computershare Trust Company, Inc., as Rights Agent, including the form of Certificate of Designation, Powers, Preferences and Rights of Series A Participating Preferred Stock dated May 29, 2001, as Exhibit A, the Form of Right Certificate, as Exhibit B, and the Summary of Rights to Purchase Preferred Shares. (Incorporated by reference to Current Report on Form 8-K for Prima Energy Corporation dated May 23, 2001 and filed June 6, 2001.)
10 Prima Energy Corporation Employee Stock Ownership Plan (Incorporated by reference to Annual Report on Form 10-K for Prima Energy Corporation dated June 30, 1989.)
10 Prima Energy Corporation 1993 Stock Incentive Plan. (Incorporated by reference to Annual Report on Form 10-K for Prima Energy Corporation dated December 31, 1993.)
10 Agreement of Lease between Denver-Stellar Associates LP, Landlord and Prima Energy Corporation, Tenant, effective December 1, 2000. (Incorporated by reference to Annual Report on Form 10-K for Prima Energy Corporation dated December 31, 2000.)
21 Subsidiaries of the Registrant
23 Consent of Deloitte & Touche LLP
(b) REPORTS ON FORM 8-K
During the quarter ended and subsequent to December 31, 2001, the Company filed the following reports on Form 8-K:
o Report dated November 13, 2001, reporting earnings for the quarter and nine months ended September 30, 2001, and providing an update on operating activities and commodity hedging.
o Report dated March 4, 2002, reporting year-end 2001 reserves, year 2002 estimated capital expenditures, and the sale of assets.
o Report dated March 20, 2002, reporting year-end 2001 financial results and providing an update of operating activities and commodity hedging transactions.
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, 2001 and 2000, 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, 2001. 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 auditing standards generally accepted in the United States of America. 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, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the consolidated financial statements, in 2001 the Company adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities."
DELOITTE & TOUCHE LLP
March 15, 2002 Denver, Colorado
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS DECEMBER 31, 2001 AND 2000
ASSETS
See accompanying notes to consolidated financial statements.
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS (CONT'D.) DECEMBER 31, 2001 AND 2000
LIABILITIES AND STOCKHOLDERS' EQUITY
See accompanying notes to consolidated financial statements.
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
See accompanying notes to consolidated financial statements.
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
See accompanying notes to consolidated financial statements.
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
See accompanying notes to consolidated financial statements.
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
See accompanying notes to consolidated financial statements.
PRIMA ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
BUSINESS
Prima Energy Corporation ("Prima") is an independent oil and gas company primarily engaged in the exploration for, and the acquisition, development and production of, crude oil and natural gas. Through 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 conducted principally 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. All significant intercompany transactions have been eliminated. Certain amounts in prior years have been reclassified to conform with the classifications at December 31, 2001.
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.
COMPREHENSIVE INCOME
Comprehensive income consists of net income and unrealized gains and losses on marketable equity securities held for sale and the effective component of derivative instruments classified as cash flow hedges, net of tax. Comprehensive income is presented in the consolidated statements of stockholders' equity and comprehensive income.
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 financial statements.
Supplemental disclosures of cash flow information:
Cash paid for income taxes was $905,000, $2,722,000 and $4,725,000 for the years ended December 31, 2001, 2000 and 1999, respectively. Cash paid for interest in 2000 and 1999 was $15,000 and $37,000, respectively. No amounts were paid for interest in 2001.
Supplemental schedule of noncash investing and financing activities:
The Company purchased oilfield service assets for $ 460,000 in March 1999. A summary of the transaction is as follows:
ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS AND AVAILABLE FOR SALE SECURITIES
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 and high credit quality of those investments.
The Company classifies marketable 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.
Commencing with its adoption of Statement of Financial Accounting Standards No. 133 on January 1, 2001 (see Note 4), the Company has recognized all derivatives on its balance sheet at their estimated fair values. The fair values of these contracts are determined based on various factors, including contract volumes and prices, contract settlement dates, quoted closing prices on the NYMEX or over-the-counter and, where applicable, volatility and the time value of options. The calculation of the fair value of collars and floors requires the use of the Black-Scholes option-pricing model, but the Company had no such positions during 2001. Substantially all of the Company's derivatives transactions are settled based upon reported settlement prices on the NYMEX or as quoted in relatively liquid over-the-counter markets by a number of market makers.
INVENTORY
Inventory consists of various tubular goods and surface production facility equipment intended to be used in the Company's oil and gas operations and is stated at the lower of cost or market value using the first-in, first-out valuation method.
OIL AND GAS PROPERTIES
The Company utilizes the full cost method of accounting for oil and gas activities. Under this method, 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 all located within the United States, which constitutes one cost center. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of oil and gas properties and 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. The Company invests in unevaluated oil and gas properties for the purpose of future exploration for proved reserves. The costs of such assets are included in unproved oil and gas properties at the lower of cost or estimated fair market value and are not subject to amortization.
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 prices of oil and natural gas as of the balance sheet date of the calculation to estimated future production of proved oil and gas reserves as of such date, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. The Company did not recognize any impairment losses during the three-year period ended December 31, 2001.
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 equipment sold upon abandonment of such properties. The Company's estimates are based upon its historical experience and upon review of its current properties and restoration obligations.
PROPERTY AND EQUIPMENT
Property and equipment is recorded at cost. Renewals and betterments that 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 of the assets, ranging from three to 15 years. Long-lived assets, other than oil and gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company did not recognize any impairment losses during the three-year period ended December 31, 2001.
NATURAL GAS REVENUES
The Company utilizes the accrual method of accounting for natural gas revenues whereby revenues are recognized as the Company's entitlement share of gas is produced based on its net revenue interests in the properties. The Company records a receivable (payable) to the extent it receives less (more) than its proportionate share of gas revenues. At December 31, 2001, the imbalance position was not significant.
OILFIELD SERVICES AND OPERATOR FEES
Fees earned from providing oilfield services and operating wells for third parties are recorded when the services are performed. Oilfield services fees are recognized as income. Operating fees are recorded as a reduction of general and administrative expenses.
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.
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
The Company periodically enters into derivative contracts to mitigate risks associated with downward price movements in benchmark NYMEX gas and oil prices or, in the case of basis swaps, to protect the Company from increases in the differential between NYMEX and Rocky Mountain gas prices. The Company's derivatives contracts generally represent cash flow hedges that are determined to be qualifying or non-qualifying for hedge accounting treatment in accordance with the provisions of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133").
SFAS 133 prescribes that the fair value of all derivatives should be recognized as either assets or liabilities in the statement of financial position. SFAS 133 also establishes requirements for designation and documentation of hedging relationships and ongoing effectiveness assessments. Hedge effectiveness is measured based on the relative changes over time in the fair values of a derivative and the related hedged item. If a cash flow hedge qualifies for hedge accounting under SFAS 133, and is so designated by the Company, changes in the fair value of the derivative are recorded initially in other comprehensive income and then recognized in the income statement when the hedged item affects earnings. If a cash flow hedge does not qualify for hedge accounting under SFAS 133, or if the Company so elects, changes in the fair value of the derivative are immediately recognized in earnings. The Company generally elects to use hedge accounting when conditions to do so are satisfied.
The Company has determined that pursuant to SFAS 133 requirements, and based on its current sources of oil and gas production, swaps, collars, puts or floors that are based on NYMEX oil prices or CIG gas prices qualify as cash flow hedges. Derivatives based on NYMEX gas prices will not so qualify unless the Company has entered into corresponding transactions to hedge basis differentials between NYMEX and CIG indices. In addition, stand-alone basis differential swaps and sales of call options do not qualify for hedge accounting.
The adoption of SFAS 133 as of January 1, 2001 resulted in the recognition of a current asset of $1,241,000, a current liability of $549,000, and net-of-tax cumulative effect adjustments reducing other comprehensive income by $129,000 and increasing net income by $611,000. The $611,000 is reflected as the cumulative effect of a change in accounting principle in the December 31, 2001 financial statements.
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 10, 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).
NEW ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standard ("SFAS") No. 141, "Business Combinations." SFAS No. 141 is intended to improve the transparency of the accounting and reporting for business combinations by requiring that all business combinations be accounted for under a single method, the purchase method. This statement is effective for all business combinations initiated after June 30, 2001. Management does not believe the adoption of this statement will have a material effect on the Company's financial position or results of operations.
In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets." This statement applies to intangibles and goodwill acquired after June 30, 2001, as well as goodwill and intangibles previously acquired. Under this statement, goodwill as well as other intangibles determined to have an infinite life will no longer be amortized. These assets will be reviewed for impairment on a periodic basis. This statement is effective for the Company in the first quarter of 2002. Management does not believe the adoption of this statement will have a material effect on the Company's financial position or results of operations.
In August 2001, the FASB issued SFAS No. 143 "Accounting for Asset Retirement Obligations." SFAS No. 143 provides the accounting requirements for retirement obligations associated with long-lived assets and requires the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying costs of the asset. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002, and early adoption is permitted. The Company is currently assessing, but has not yet determined, the impact of SFAS No. 143 on its consolidated results of operations, cash flows or financial position.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 requires that long-lived assets be measured at the lower of carrying amount or fair value less costs to sell, whether reported in continuing operations or in discontinued operations. Therefore, discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. SFAS No. 144 is effective for financial statements issued for fiscal years beginning after December 15, 2001 and generally is to be applied prospectively. Management does not believe the adoption of this statement will have a material effect on the Company's financial position or results of operations.
2. AVAILABLE FOR SALE SECURITIES
The Company's available for sale securities are comprised of marketable equity securities, including closed-end bond funds. For the years ended December 31, 2001 and 2000, the Company sold securities with a market value of $166,000 and $57,000 which resulted in realized losses of $1,000 and $18,000, respectively. The net unrealized gain or loss on securities at December 31, 2001 and 2000 is included in accumulated other comprehensive income, net of
deferred income taxes of $(20,000) and $(75,000), respectively. The change in net unrealized gain or loss on securities for the years ended December 31, 2001 and 2000 was as follows:
The components of fair value as of December 31, 2001 and 2000 were as follows:
3. EARNINGS PER SHARE AND COMMON STOCK
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 two separate three for two stock splits of the Company's common stock during 2000. All share and per share amounts included in these financial statements have been restated to show the retroactive effects of the stock splits.
During 2000, the Company purchased 108,150 shares of its common stock for its treasury for $1,935,000. The Board of Directors authorized the retirement of 431,199 shares of common stock held in the treasury as of December 31, 2000. These shares were returned to an authorized but unissued status. In January 2001, the Board approved a repurchase program of up to 5% of the Company's common stock then outstanding, or approximately 640,000 shares. In 2001, the Company purchased 155,351 treasury shares for $3,866,000. This represents approximately 1.2% of the shares then outstanding, or 24% of the shares authorized under the repurchase program.
During 2000, the shareholders of Prima approved an increase in the number of authorized shares of common stock from 12,000,000 to 18,000,000 shares. During 2001, the shareholders approved an additional increase to 35,000,000 authorized shares.
4. DERIVATIVE ACTIVITIES
Crude oil and natural gas futures, options and swaps, and basis swaps, are used from time to time in order to hedge the price of a portion of the Company's production and to lock in the basis from NYMEX to the Rocky Mountains. These cash flow hedging derivatives are entered into to mitigate the risk of fluctuating oil and natural gas prices and fluctuating basis differentials, which can adversely affect operating results. The Company uses only conventional derivative instruments and attempts to manage its credit risk by entering into derivative contracts only with financial institutions that are believed to be reputable and which carry an investment grade rating. While such hedges can reduce the adverse effects of oil and gas price declines, they may also limit the benefits of price increases.
The Company has entered into various cash flow hedges related to its oil and gas production. Some of these derivatives qualify for hedge accounting, while others are non-qualifying. The following table summarizes the income statement effects of these transactions in 2001, 2000 and 1999:
In addition, the Company had $94,000 of unrealized mark-to-market gains as of December 31, 2001 on derivatives qualifying for hedge accounting, which amount has been included in other comprehensive income for 2001. The realized gains on derivatives that qualified for hedge accounting, which were included in oil and gas sales, related to approximately 24%, 1% and 15% of the Company's natural gas production in 2001, 2000 and 1999, respectively, and 19%, 5% and 25%, respectively, of its oil production for the same three years.
As of December 31, 2001, the Company had recorded a current asset of $4,472,000, representing the aggregate unrealized mark-to-market gains for its open derivative positions, which are summarized below:
Oil and gas prices are volatile and the market value of these derivatives will change as the underlying commodity futures prices change. Mark-to-market adjustments could result in significant earnings volatility. The actual gains or
losses realized will depend on the applicable futures prices in effect at the time such positions expire or are closed. The table above excludes commodity positions with Enron North America Corp, which filed for bankruptcy protection in December 2001. Prima's unrealized gain on derivatives due from Enron totaled approximately $241,000 when the Company terminated the contract under default provisions in the agreement. Although this amount was reflected in gains on derivative instruments in 2001, the full amount was reserved for and reflected as an impairment expense in the same period.
5. INCOME TAXES
The provision for income taxes consists of the following components:
The provision for income taxes includes $265,000 of current expense that was netted in the cumulative effect of change in accounting method. During 2001, 2000 and 1999, the Company recognized income tax deductions of $1,979,000, $1,946,000 and $1,247,000, respectively, from the exercise of nonqualified stock options. Stockholders' equity has been credited in the amount of $732,000, $720,000 and $477,000 for the income tax benefit of these deductions. During 2001, the Company recognized taxable income of $207,000 from short-swing profits. Stockholders' equity has been reduced in the amount of $77,000 for the current income tax expense associated with this income.
The significant components of deferred tax assets and 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, 2001, the Company had minimum tax credit carryforwards of approximately $1,727,000, which may by carried forward indefinitely.
6. 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) providing oil field services for wells which it operates and for third parties and 3) the marketing and trading of third party natural gas (which activity has not been actively conducted since 1999). 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, 2001, 2000 and 1999. 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 oilfield services provided to Company-owned wells, which are eliminated in consolidation. 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.
Following is a table summarizing the percentage of sales made to each customer that accounted for over 10% of the Company's consolidated revenues. 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.
7. COMMITMENTS AND CONTINGENCIES
The Company entered into a seven-year office space lease, effective December 1, 2000. Office lease expense totaled $282,000, $187,000 and $155,000 for the years ended December 31, 2001, 2000 and 1999, respectively. Future minimum annual rentals under the non-cancelable operating lease for the remainder of the seven-year term are as follows:
From time to time the Company may be involved in litigation that arises in the normal course of business operations. As of the date of this report, the Company is not a party to any litigation that it believes could reasonably be expected to have a material adverse effect on the business or results of operations.
8. BENEFIT PLANS
EMPLOYEE STOCK OPTION PLAN
Under the Prima Energy Corporation 1993 Stock Incentive Plan and the Prima Energy Corporation 2001 Stock Incentive Plan, 2,650,000 shares of Prima's common stock are reserved for issuance to key employees at fair market value on the date of grant. Options granted to date under the plan vest ratably over three to five years, and expire ten years from the date of grant. At December 31, 2001, options to acquire 1,037,950 shares of the Company's common stock were outstanding. The exercise prices, which equaled the market price of the stock on the date of grant, range from $3.93 to $33.25 per share, with a weighted average price of $11.14 per share. No options were granted in 2000. As of December 31, 2001, the weighted average remaining contractual life of the options outstanding is 5 years, 4 months. A summary of options granted, exercised and outstanding during the three years ended December 31, 2001 is as follows:
NON-EMPLOYEE DIRECTORS' STOCK OPTION PLAN
Under the Prima Energy Corporation Non-Employee Directors' Stock Option Plan 225,000 shares of Prima's common stock are reserved 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, 22,500 options are granted each non-employee director. On each anniversary date of the initial grant, an additional 5,625 options are granted to each non-employee director for as long as they continue to serve on the Board. Options vest ratably over five years, and expire ten years from the date of grant. At December 31, 2001, options to acquire 135,000 shares of the Company's common stock were outstanding under the plan, at exercise prices ranging from $6.67 to $32.33 per share. As of December 31, 2001, the weighted average remaining contractual life of the options outstanding is eight years. A summary of options granted, exercised and outstanding during the three years ended December 31, 2001 is as follows:
SUMMARY OF OUTSTANDING OPTIONS
The following table summarizes information about stock options outstanding at December 31, 2001 on a combined basis for the employee and non-employee directors' plans:
RECOGNITION OF COMPENSATION EXPENSE
Prima has adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"). Accordingly, no compensation costs have been recognized for the Employee Stock Option Plan or the Non-Employee Directors' Stock Option Plan. For disclosure purposes, the fair value of options is measured at the date of grant using the Black-Scholes option valuation model, which was developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable. Such option valuation models also require the input of highly subjective assumptions, including the projected life of the options and expected stock price volatility. Because the Company's employee and directors' stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the estimated fair value, these valuation models do not necessarily provide a reliable measure of the fair value of such stock options.
The following assumptions were utilized to estimate the fair values on the dates of grant of options issued during the three years ended December 31, 2001, using the Black-Scholes Valuation Model:
Based on the above, the estimated weighted average fair values of employee stock options granted during 2001 and 1999 were $16.04 and $5.54, respectively. No employee stock options were granted in 2000. The weighted average fair values of non-employee directors' options granted during 2001, 2000 and 1999 were $12.49, $20.47 and $5.54, respectively.
For purposes of pro forma disclosures, the estimated fair values of option grants are amortized to expense over the options' vesting periods. Had compensation expense been determined based on the estimated fair values at the grant dates for options awarded through December 31, 2001, consistent with the provisions of SFAS 123, the Company's net income and net income per share would have been adjusted to the pro forma amounts indicated below.
EMPLOYEE STOCK OWNERSHIP PLAN
The Company has an Employee Stock Ownership Plan ("ESOP"), which is administered pursuant to a Trust Agreement. The ESOP 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's year, September 30, and are allocated among the participants in proportion to their eligible compensation for the year. Contributions are payable at a minimum rate of 5% of eligible salaries. Through September 30, 1993, the ESOP 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 ESOP was amended to allow fully vested employees the option to direct the Trustees to diversify a portion of their investments by selling a limited percent of Prima common stock and investing the proceeds, as well as their contributions, in various diversified investment options. The ESOP benefits all full-time employees and provides for vesting in increments over six years. For the years ended December 31, 2001, 2000 and 1999, the Company expensed $316,000, $283,000 and $224,000, respectively, of Company contributions to the Plan.
9. TRANSACTIONS WITH RELATED PARTIES
The Company is a 6% limited partner in a real estate limited partnership that 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, 2001 and 2000 was $257,000. During the three years ended December 31, 2001, the Company did not make any capital contributions to the partnership, nor did it 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 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 similar transactions with unrelated parties.
The Company acquired oil and gas leases covering 26,680 net undeveloped acres in June 2000 from a company controlled by a director of Prima for a negotiated price of $12 per net acre, or a total of $320,000. Additional acreage in the same general area were subsequently acquired from this director at cost. The aggregate amounts paid for these property interests, including the initial acquisition totaled $290,000 in 2001 and $376,000 in 2000. All leases acquired were subject to an overriding royalty reserved by the director or entities controlled by him of 3% or less, depending on the net revenue interest of the leases, proportionately reduced to the working interest acquired. The disinterested members of the Board of Directors approved the transactions.
10. SUBSEQUENT EVENT
On March 5, 2002, the Company sold all of its producing wells in the Stone's Throw CBM project in the northern Powder River Basin, along with associated gathering system facilities and approximately 35,000 net undeveloped acres in the Stone's Throw area. Net proceeds from the transaction totaled $13,539,000 after normal closing adjustments. Approximately $11,746,000 of the proceeds were closed into an escrow account with a qualified intermediary, to preserve the opportunity to consummate a tax-free like-kind exchange if suitable properties to acquire can be identified within 45 days and purchased within six months. If a tax-free exchange is not consummated, the Company's current income taxes for 2002 could increase by up to $1,400,000.
11. SUPPLEMENTARY OIL AND GAS INFORMATION
The Company's oil and gas operations are conducted entirely in the United States, primarily in the Rocky Mountain region. Certain information concerning these activities follows:
COSTS INCURRED -- Costs incurred in oil and gas property acquisition, exploration and development activities and related depletion per equivalent unit-of-production were as follows:
COSTS NOT BEING AMORTIZED -- Oil and gas property costs not being amortized at December 31, 2001 consisted of $13,132,000 of leasehold costs. The Company anticipates that substantially all unevaluated costs will be classified as evaluated costs within five years.
RESULTS OF OPERATIONS -- Results of operations for oil and gas producing activities were as follows:
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
The reserve information presented below is based on estimates of net proved reserves as of December 31, 2001 that were prepared by the Company's engineers and audited by Netherland, Sewell and Associates, Inc., independent petroleum engineers, and estimates at the end of 2000 and 1999 that were prepared or audited in part by Netherland, Sewell and Associates, Inc. and in part by Ryder Scott Company, independent petroleum engineers. 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.
ANALYSES OF CHANGES IN PROVED RESERVES - The following table sets forth information regarding the Company's estimated net total proved and proved developed oil and gas reserve quantities:
YEAR-END OIL AND GAS PRICES -- Oil and natural gas prices in effect at each year end used in calculating reserve estimates were as follows:
STANDARDIZED MEASURE - The following table presents the standardized measure of discounted future net cash flows related to proved oil and gas reserves.
A summary of changes in the standardized measure of discounted future net cash flows is as follows:
12. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of the unaudited financial data for each quarter for the years ended December 31, 2001 and 2000.
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, 2002.
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.
INDEX TO EXHIBITS
(b) REPORTS ON FORM 8-K
During the quarter ended and subsequent to December 31, 2001, the Company filed the following reports on Form 8-K:
o Report dated November 13, 2001, reporting earnings for the quarter and nine months ended September 30, 2001, and providing an update on operating activities and commodity hedging.
o Report dated March 4, 2002, reporting year-end 2001 reserves, year 2002 estimated capital expenditures, and the sale of assets.
o Report dated March 20, 2002, reporting year-end 2001 financial results and providing an update of operating activities and commodity hedging transactions.