10KSB 1 s200110k.txt 12-31-01 10-KSB UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 10-KSB [x] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2001 [ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number: 0-14731 HALLADOR PETROLEUM COMPANY COLORADO 84-1014610 (State of incorporation) (IRS Employer Identification No.) 1660 Lincoln Street, Suite 2700, Denver, Colorado 80264-2701 (Address of principal executive offices) (Zip Code) Issuer's telephone number: 303.839.5504 Fax: 303.832.3013 Securities registered under Section 12(b) of the Exchange Act: NONE Securities registered under Section 12(g) of the Exchange Act: Common Stock,$.01 par value Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of he Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to the filing requirements for the past 90 days. Yes x No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-B is not contained in this form, and no disclosure will be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-KSB or any amendment to this Form 10-KSB. [] Our revenue for the year ended December 31, 2001 was about $8 million. At March 29, 2002, we had 7,093,150 shares outstanding and the aggregate market value of such shares held by non-affiliates was about $1.4 million based on a price of $1.80, which was the last reported trade on that date. DOCUMENTS INCORPORATED BY REFERENCE: NONE ITEM 1. DESCRIPTION OF BUSINESS General Development of Business ------------------------------- Hallador Petroleum Company, a Colorado corporation, was organized by our predecessor in 1949. About five years ago, Yorktown Energy Partners II and affiliates (Yorktown) invested $5,025,000 in Hallador Petroleum, LLP, a newly formed limited liability limited partnership. We are the general partner and received a 70% interest in the partnership in return for contributing our net assets, and Yorktown represents the limited partners and received a 30% interest for its $5,025,000 cash contribution. As general partner, we consolidate the activity of the partnership and present the 30% limited partners' interest as a minority interest. We and our principal operating subsidiaries, Hallador Production Company and Hallador Petroleum, LLP, are engaged in the exploration, development and production of oil and natural gas. Our principal and administrative offices are located at 1660 Lincoln Street, Suite 2700, Denver, Colorado 80264, phone 303.839.5504, fax 303.832.3013. The South Cuyama field office is located in New Cuyama, California. We have no website. 86% of our oil and gas revenue is attributable to the South Cuyama field (the "SC Field") located in Santa Barbara County, California, approximately 75 miles southwest from Bakersfield, California. We own 92% of Santa Barbara Partners (SBP), an Oklahoma general partnership, which has a 93% working interest (78% net revenue interest) in the SC Field. The SC Field's oil reserves consist of light oil at 29 degree gravity. We operate oil and natural gas properties for our own account and for the account of others. We also review and evaluate producing oil and natural gas properties, companies, or other entities, which meet certain guidelines for acquisition purposes. In addition, we engage in the trading and acquisition of non-producing oil and gas mineral leases and fee-simple minerals. Markets ------- Our products are sold to various purchasers in the geographic area of the properties. Natural gas, after processing, is distributed through pipelines. Oil and natural gas liquids (NGLs) are distributed through pipelines or hauled by trucks. The principal uses for oil and natural gas are heating, manufacturing, power, and transportation. At March 27, 2002, we were receiving $23.11 per barrel for our California oil production, which is $1.24 more than the average price received during 2001 and $6.63 above the December 31, 2001 price. The SC Field's oil is sold to Pacific Marketing and Transportation LLC (an affiliate of Anschutz Exploration Company), pursuant to a "spot market" contract, which can be cancelled by either party with 30 days notice. The contract pays a $.20 per barrel premium to "spot market" postings. The SC Field's natural gas is sold to Coral Energy (an affiliate of Shell Oil Corporation), pursuant to a "spot market" contract, which can be cancelled by either party with 30 days notice. NGLs are sold to EOTT Energy Corp. pursuant to a "spot market" contract, which can be cancelled by either party with 30 days notice. Competition ----------- The oil and gas industry is highly competitive. We encounter competition from major and independent oil companies in acquiring economically desirable producing properties, drilling prospects, and even the equipment and labor needed to drill, operate and maintain our properties. Competition is intense with respect to the acquisition of producing and partially developed properties. We compete with companies having financial resources and technical staffs significantly larger than our own. We do not own any refining or retail outlets and have minimal control over the prices of our products. Generally, higher costs, fees and taxes assessed at the producer level cannot be passed on to our customers. We also face competition from imported products as well as alternative sources of energy such as coal, nuclear, hydro-electric power, and a growing trend toward solar. We could incur delays or curtailments of the purchase of our available production. We may also encounter increasing costs of production and transportation while sale prices remain stable or decline. Any of these competitive factors could have an adverse effect on our operating results. Environmental and Other Regulations ----------------------------------- Our operations are affected in varying degrees by federal, state, regional and local laws and regulations, including, but not limited to, laws governing allowable rates of production, well spacing, air emissions, water discharges, endangered species, marketing, prices and taxes. We are further affected by changes in such laws and by constantly changing administrative regulations. Most natural gas pricing is presently deregulated and the remaining regulation has no material impact on our prices. We cannot predict the long-term impact of future natural gas price regulation or deregulation. We are subject to various federal, state, regional and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the owner or the lessee for the cost of pollution clean-up resulting from operations, subject the owner or lessee to liability for pollution damages, require suspension or cessation of operations in affected areas or impose restrictions on injection into subsurface aquifers that may contaminate groundwater. Such regulation has increased the resources required in, and costs associated with, planning, designing, drilling, installing, operating and abandoning our oil and natural gas wells and other facilities. We spend a significant amount of technical and managerial time to comply with environmental regulations and permitting requirements. We have and will continue to make expenditures to comply with these requirements, which we believe are necessary business costs. Although environmental requirements do have a substantial impact upon the energy industry, generally these requirements do not appear to affect us any differently or to any greater or lesser extent than other companies in California. Although we are not fully insured against all environmental and other risks, we maintain insurance coverage, which we believe, is customary in the industry. During 2001, we incurred about $94,000 to comply with these recurring environmental regulations. We estimate that such expenditures for 2002 and for each year thereafter, in the foreseeable future, will approximate $98,000. We will continue to use our best efforts to comply with all applicable environmental laws and regulations. See Item 6 - Management's Discussion and Analysis (MD&A) for a discussion regarding idle wells in the SC Field. To the extent these environmental expenditures reduce funds available for increasing our reserves of oil and natural gas, future operations could be adversely impacted. Despite the fact that all of our competitors have to comply with similar regulations, many are much larger and have greater resources with which to deal with these regulations. Other ----- We have no significant patents, trademarks, licenses, franchises or concessions. The oil business is not generally seasonal in nature; although unusual weather extremes for extended periods may increase or decrease demand. Natural gas prices tend to increase in the fall and winter months and to decrease in the spring and summer. We have 29 employees; seven are located at our executive office in Denver and 22 are located at the SC Field. When needed we also engage consulting petroleum engineers, environmental professionals, geologists, geophysicists, landmen, accountants and attorneys on a fee basis. ITEM 2. DESCRIPTION OF PROPERTY Location and General Character ------------------------------ Our primary operating areas consist of (i) the SC Field located 75 miles southwest from Bakersfield, California, (ii) South Texas - Bonus located about 70 miles southwest of Houston, and (iii) the San Juan Basin, located in the northwest corner of New Mexico. Revenue from the SC Field accounted for 86% of 2001 oil, gas and NGL revenue, South Texas accounted for 2%, and San Juan Basin accounted for 4%. We hold our working interests in oil and natural gas properties either through recordable assignments, leases, or contractual arrangements such as operating agreements. Consistent with industry practices, we do not make a detailed examination of title when we acquire undeveloped acreage. Title to such properties is examined by legal counsel prior to commencement of drilling operations. This method of title examination is consistent with industry practices. In the acquisition and operation of oil and natural gas properties, burdens such as royalty, overriding royalty, liens incident to operating agreements, liens by taxing authorities, as well as other burdens and minor encumbrances are customarily created. We believe that no such burdens materially affect the value or use of our properties. Proved Oil and Gas Reserves --------------------------- Information concerning our reserve estimates is set forth in Note 6 to the financial statements. The reserve estimates were prepared by a sole- proprietor consulting petroleum engineer. All of our oil and gas reserves are located onshore. South Cuyama Field ------------------ Discovered in 1949 in the Cuyama Valley, Santa Barbara County, California, the SC Field became the largest oil field found to date in the valley and is located approximately 75 miles southwest from Bakersfield. By 1951, the SC Field contained 200 wells producing approximately 40,000 barrels of oil per day. Since inception, the SC Field is estimated to have produced over 222 million barrels of crude oil. Current oil production to the 100% is about 1,013 barrels per day. Currently, there are 64 producing wells. The wells produce from a depth range of 3,400 to 4,800 feet. Sales and Price Data -------------------- See Item 6 - MD&A Producing Wells --------------- As of March 29, 2002, we had a working interest in 60 gross (53 net) oil wells and 32 gross (7 net) gas wells. Leasehold Interests ------------------- The following table sets forth our gross and net acres of undeveloped oil and gas leases as of March 29, 2002:
Gross Net ----- ----- South Cuyama, California 4,813 3,821 Sac Basin, California 432 130 North Dakota 45,535 7,469 Texas 6,374 734 Utah 5,777 5,777 Wyoming 66,343 54,077 ------- ------ 129,274 72,008 ======= ======
We have an interest in 3,077 gross (2,707 net) developed acres in the SC Field. Drilling Activity ----------------- From January 1, through March 29, 2002, there has been no drilling activity. During 2001 we drilled one successful exploratory gas/oil well and one development oil well in the SC Field. Two unsuccessful development wells were drilled in the SC Field. We have an 88% WI in the SC Field. One exploratory dry hole was drilled in the Sac Basin of northern California where we have a 30% WI. One exploratory dry hole was drilled in the South Texas - Alleyton prospect where we have a 14% WI. Four successful development wells were drilled in the South Texas - Bonus field where we have a 5.5% WI. One successful exploratory gas well was drilled in South Texas - McFarland prospect where we have a 25% WI and one marginally successful exploratory gas well was drilled in East Texas where we have a 25% WI. During 2000, we drilled one successful development oil well in the SC Field. In the Sac Basin, we drilled two exploratory gas wells that were dry. In South Texas - Alleyton prospect we drilled an exploratory gas well which was dry. In the San Juan Basin, we drilled three successful development gas wells where we have a 6% WI in such wells. We also participated in one exploratory oil well in Noble County, Oklahoma that was dry in which we had a 10% WI. ITEM 3. LEGAL PROCEEDINGS: None ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS: None PART II ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Our common stock is traded on the OTC Bulletin Board under the symbol "HPCO". The following table sets forth the high and low sales price for the periods indicated:
High Low ---- ---- 2002 First quarter (through March 29, 2002) $1.80 $1.50 2001 First quarter 4.19 1.75 Second quarter 5.00 4.25 Third quarter 4.25 4.25 Fourth quarter 4.00 1.75 2000 First quarter 1.38 .66 Second quarter 3.75 1.38 Third quarter 3.00 2.38 Fourth quarter 2.50 2.06
During the last two years no dividends were paid. We have no present intention to pay any dividends in the foreseeable future. As of March 29, 2002 there were 413 holders of record of our common stock and the last recorded sales price was $1.80. ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION Overview -------- Our financial statements should be read in conjunction with this discussion. Our primary operating areas consist of (i) the South Cuyama field (SC Field) located 75 miles southwest from Bakersfield, California, (ii) the South Texas - Bonus field located about 70 miles southwest of Houston, and (iii) the San Juan Basin, located in the northwest corner of New Mexico. Due to its significance, our value depends on the estimated future cash flows from the SC Field. We intend to maximize cash flow by continuing to increase oil and gas production and keeping operating expenses low. Future operations will also be affected by the results of the development and exploration activity discussed below. About five years ago, Yorktown Energy Partners II and affiliates (Yorktown) invested $5,025,000 in Hallador Petroleum, LLP, a newly formed limited liability limited partnership. We are the general partner and received a 70% interest in the partnership in return for contributing our net assets and Yorktown represents the limited partners and received a 30% interest for its $5,025,000 cash contribution. As general partner, we consolidate the activity of the partnership and present the 30% limited partners' interest as a minority interest. Our profitability in any particular accounting period will be directly related to: (i) prices, (ii) production, (iii) lifting costs, and (iv) exploration activities. Accordingly, operating results will fluctuate from period to period based on these factors, among others. What follows is a discussion of our primary operating areas. South Cuyama Field ------------------ During October 2000, we completed a 3-D project on adjoining acreage east of the South Cuyama field (SC Field). The cost of this project was $350,000 to the 100%. We have a 70% WI in this project. The data was evaluated in January 2001 and several drillable prospects were identified. The first exploratory gas well (the Cox 41-5) was drilled in March 2001. Currently, the well is producing 500 MCF per day and 275 barrels per day from a depth of about 3,400 feet. We are the operator and own a 70% WI (60% NRI). The cost to drill and complete this well was about $300,000 to the 100%. This well is an important step in validating our 3-D seismic project. We are reviewing our 3-D seismic data to identify other locations to drill. With the high gas prices we received during the second quarter, the revenue from the Cox 41-5 recovered our drilling and seismic costs ($650,000) in less than two months. Because of the California electricity crisis natural gas prices were abnormally high during the first six months of the year. During the second quarter we were selling the gas for as high as $16 per MCF. Currently, the prices are around $3. We estimate the 100% reserves for the current producing zone for this well to be about 500,000 MCF and the oil reserves to be about 235,000 barrels. The well has three pay zones, and we are currently producing from the lowest zone. Rather than move up the hole and possibly disturb the currently producing zone, we plan to drill an offset to this well in July 2002. The estimated cost to the 100% is $375,000. Rather than assign behind-pipe reserves to the Cox #41-5 we have assigned proved undeveloped reserves to the 100% of 1.5 BCF to the offset well, the Cox #42-5. The Cox #42-5 well will be drilled 400 feet deeper than the Cox #41-5 well to test a previously untested zone in the 3-D area. This fall we plan to commence another 3-D seismic project. This project will cover the entire SC Field and land north of the SC Field. The cost to the 100% is estimated to be $1 million, our share would be $800,000. We should know the results of the shoot by the spring of 2003. Our electricity costs have increased significantly. During 2000 our average monthly electricity cost in the SC Field was $70,000 compared to our costs this year of $120,000. We are continuing to develop the proper strategy to optimize the cash flow from the SC Field considering these high electricity costs. Currently gas sales in the SC Field are limited to 1,150 MCF/day due to pipeline capacity and pressures. We are selling about 550 MCF/day to the 100%. After we drill the Cox #42-5 this summer we expect to be selling about 2,300 MCF/day to the 100% assuming arrangements can be made with Southern California Gas Company (SOCAL), the owner of the pipeline, to increase the capacity. If the capacity is not increased, our future sales will be adversely affected. Due to high electricity costs we are exploring the possibility of generating our own electricity. Based on a preliminary study, the capital costs to do so would be in the $1.5 million range. Instead of selling our gas we would burn the gas to generate electricity. This concept may come to fruition if we conclude that California electrical costs are going to remain high for the next three years and if we are unable to market our gas due to pipeline capacity. South Texas - Bonus ------------------- During the third and fourth quarter, we participated with Forest Oil Company of Denver in a four-well developmental gas prospect in Wharton County, Texas located about 70 miles southwest of Houston. These wells are deep (about 14,000 feet) and expensive; the costs to drill and complete were about $5 million per well. We have a 5.5% WI (4.3% NRI). Our net book value in the prospect is about $1.4 million. Using March 2002 prices of $3.40 per MCF we estimate future net revenue from these four wells to be about $1.4 million. San Juan Basin -------------- This gas field is located in the northwest corner of New Mexico in San Juan County. We have an interest in 20 wells and are the operator. These wells have long-lived reserves. Our WI in this field ranges from 5%-15% with NRIs between 5%-13%. Our net book value in this prospect is about $120,000. We may participate in the drilling of a development gas well in late 2002. The cost to the 100% to drill and complete this well will be about $700,000. Questar, a Salt Lake City company, will be the operator during the drilling phase. Using March 2002 prices of $3.00 per MCF we estimate future net revenue from this field to be about $1.7 million. Catalytic Solutions Investment ------------------------------ During 1998, we invested $62,000 for a small ownership in Catalytic Solutions, Inc. (CSI), a private company, located in Oxnard, California (a Los Angeles suburb). CSI manufactures catalytic converters that reduce toxic emissions from internal combustion engines. During 2000, we invested another $113,000 in CSI. Our current ownership is about .006. Environmental and Regulation ----------------------------- We are directly affected by changing environmental rules and regulations. Although we believe our operations and facilities are in compliance with applicable environmental regulations, risk of substantial cost and liabilities resulting from an unintentional breach of environmental regulations are inherent to oil and gas operations. It is possible that other developments, such as increasingly strict environmental laws, regulations, and enforcement policies or claims for damages could result in significant costs and liability in the future. In January 1999, the California legislature passed a bill, which increased our operator's bond from $100,000 to $250,000 over a five-year period. In addition, an idle well bill was passed to ensure that funds would be available to properly plug and abandon (P&A) California wells upon their depletion. Over the next ten years, we as the SC Field's operator, are required to place in an interest-bearing escrow account $500 per year for each idle well in the SC Field until such well is plugged and abandoned or until $5,000 has been deposited. Through June 30, 2001 we have made three installments totaling $196,000. We estimate that after ten annual installments we will have met the current funding obligation of $700,000 considering the interest to be earned. As the SC Field depletes, and more wells move from the producing category to the idle-well category we will have to make additional annual payments. Presently, there are 280 wells in the SC Field, 140 of which are classified as "idle". During 1999, we began amortizing, using the units-of-production method, our share of the estimated future costs ($1,207,000) to P&A the SC Field's 280 wells. Included in the DD&A expense for 2000 and 2001 was $113,000 and $154,000, respectively, associated with these estimated future costs. ARCO Indemnity -------------- The SC Field was purchased from ARCO (Atlantic Richfield which is now part of BP p.l.c.) in May 1990. ARCO assumed certain environmental liabilities connected with their 40-year ownership of the SC Field (hereafter, referred to as the "Indemnity".) During 2002, we plan to remove and clean up portions of the old gas plant, which has not been in operation for at least 25 years. Some of this old equipment has evidence of asbestos. It is our position as set forth in the Indemnity that the old gas plant and a good portion of other clean up liability will be covered by the Indemnity. Trend Acreage ------------- We have been leasing undeveloped acreage on state and federal lands in Wyoming. From October 2001 to March 2002 we have invested about $165,000. These leases have a ten-year term. We expect to sell or farm-out these leases to third parties. During 2001 and 2000 we realized gains of $67,000 and $147,000, respectively from such sales. We always retain an overriding royalty interest in the oil and gas lease we sell. Self-insurance for Employee Medical Costs ----------------------------------------- Due to the rising costs in providing health care coverage for our employees we changed from a standard type of policy to a self-insured policy. We are responsible for the first $5,700 of health care costs for each employee and their dependents. Our maximum exposure in any given year is about $100,000. Starting April 2002 we will begin accruing $3,000 per month for our estimated claims. Liquidity and Capital Resources ------------------------------- Cash and cash to be provided from operations are expected to enable us to meet our obligations as they become due during the next several years. The SC Field, our principal asset, is pledged to U. S. Bank National Association under a $2,000,000 revolving line of credit. Presently, we owe $31,000 under this line. We have never entered into hedging activities and at this time do not expect to. We have no special purpose entities and no off-balance sheet debt nor did we enter into any related party transactions during the two years ended December 31, 2001. RESULTS OF OPERATIONS YEAR-TO-DATE COMPARISON ----------------------- The table below (in thousands) provides sales data and average prices for the period.
2001 2000 ------------------------ ---------------------- Sales Average Sales Average Volume Price Revenue Volume Price Revenue ------- ------- ------ ------ ----- ------- Oil - barrels South Cuyama field 215 $22.09 $4,749 233 $27.74 $6,464 Cox #41-5 (1) 15 19.47 292 South Texas-Bonus 1.4 18.57 26 Other 1.7 24.71 42 * * 30 Gas - mcf South Cuyama field 53 8.81 467 41 3.90 160 Cox #41-5 (1) 121 7.79 942 South Texas - Bonus 47 2.85 134 San Juan-New Mexico 51 3.90 199 56 3.45 193 Merlin Prospect(2) 56 7.59 425 111 3.89 432 Other 40 4.17 167 74 3.26 241 NGLs - barrels South Cuyama field 13 18.77 244 16 21.50 344 San Juan-New Mexico 5 15.00 75 5 19.60 98 Other * * 1 * * 4 ------------------------ * Not meaningful (1) This well is part of the SC Field, due to its significance we present it separately. (2) This field located in northern California is near the end of its economic life.
The table below (in thousands) shows lease operating expenses (LOE) for our primary fields.
2001 2000 ---- ---- South Cuyama field: LOE excluding electricity $2,623 $2,406 Electricity 1,434 852 ----- ----- 4,057 3,258 South Texas - Bonus 12 San Juan - New Mexico 70 117 Other 88 102 ----- ----- Total $4,227 $3,477 ===== =====
LOE per equivalent barrel was $13.41 for 2001 and $11.59 for 2000. Oil and NGL revenue is down compared to last year due to lower prices and volumes. The increase in gas revenue is due primarily to the Cox #41-5 and to the abnormally high gas prices during the summer of 2001. LOE increased due to higher electricity costs in the SC Field. G&A increased due to bonuses paid to employees during the summer of 2001 when oil and gas prices were high. Risk Factors ------------ The six issues that cause us worry are: 1. OPEC deciding to significantly increase production, which would result in a free-fall of oil prices. 2. Although the SC Field has a 50-year operating history, the reserve estimates could be overstated. 3. We never know what adverse rules or regulations could be passed by our regulatory agencies such as the EPA (Environmental Protection Agency), BLM (Bureau of Land Management), DOG (California Division of Oil & Gas), and the SBAPCD (Santa Barbara County Air Pollution Control District). 4. The SC Field is a high-water-cut oil field meaning that we move about 30,000 barrels of water per day in order to produce about 1,000 barrels of oil per day. Such fields have a high break-even point and consequently depend on a relatively high oil price to make money. Higher electricity costs will make it difficult to continue to operate the SC Field profitably. Oil prices hit a low of $15 and gas hit a low of $1.90 during the fourth quarter 2001. At those low prices, our total monthly cash flow from all properties was $35,000; at current prices of $23 oil and $3 gas our monthly cash flow is $250,000. 5. California is prone to earthquakes. Certain types of earthquakes could shear the casing heads resulting in catastrophic damage to the SC Field. Earthquake insurance is cost prohibitive. 6. We have no succession plan for our CEO, Victor Stabio. The loss of his services would have an adverse affect on us. We do have a key man life insurance policy on Mr. Stabio in the amount of $2.5 million. Critical Accounting Policies and Estimates ------------------------------------------ We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our financial statements. Successful Efforts Method of Accounting --------------------------------------- We account for our exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties. The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and gas field is typically considered a development cost and capitalized but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions. The successful efforts method of accounting can have a significant impact on the operational results reported when we enter a new exploratory area in hopes of finding an oil and gas field that will be the focus of future development drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial which will result in additional exploration expenses when incurred. Reserve Estimates -------------------------- Our estimates of oil and gas 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 oil and gas 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 oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and gas prices, future operating costs, severance taxes, development costs and workover 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 be later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of oil and gas 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 our oil and gas properties and/or the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. Impairment of Developed Oil and Gas Properties ---------------------------------------------- We review our oil and gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. We estimate the expected future cash flows of our oil and gas properties and compare such future cash flows to the carrying amount of our oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to their fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. There were no impairments of developed oil and gas properties during 2001 and 2000. At December 31, 2001 oil prices in the SC Field were $16.48. At that price cash flow from the SC Field is slightly positive. During March 2002 oil prices improved, if they had not improved, we would have taken a significant impairment charge. If prices during 2002 decline below $20 per barrel and we conclude these low oil prices are not reasonably likely to improve, we could be taking a significant impairment charge in the $1-$2 million range. Our net book value in the SC Field at December 31, 2001 was $6.1 million. Future undiscounted cash flows using March 2002 prices are $7.7 million; future undiscounted cash flows using December 31, 2001 prices were $2.4 million. Impairment of Unproved Oil and Gas Properties --------------------------------------------- We periodically assess individually significant unproved oil and gas properties for impairment, on a project-by-project basis. Our assessment of the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects impact the amount and timing of impairment provisions. During 2001 we took a $229,000 impairment. Future Abandonment Costs ------------------------ We are required to make judgments based on historical experience and future expectations on the future abandonment cost, net of salvage value, of our oil and gas properties and equipment. We review our estimate of the future obligation periodically and accrue the estimated obligation monthly based on the units-of-production method. For properties other than the SC Field we estimate that the future abandonment cost, net of salvage value, will not be material. For the SC Field we are estimating such future costs to be $1.2 million. New Accounting Pronouncements ----------------------------- In June 2001 the Financial Accounting Standards Board issued SFAS No. 141, "Business Combinations." Under this statement all business combinations must be accounted for under the purchase method. The pooling method is no longer allowed. The statement also establishes criteria to assess when to recognize intangible assets separately from goodwill. SFAS No. 141 is effective for business combinations initiated after June 30, 2001 and for all business combinations using the purchase method for which the date of acquisition is after June 30, 2001. At this time we have no pending business combinations that would be affected by the adoption of this statement. In June 2001 the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets." This statement addresses the accounting for goodwill and other intangible assets and provides specific guidance for testing goodwill and other intangible assets for impairment. This statement is effective for fiscal years beginning after December 15, 2001. The adoption of this statement did not have a material effect on our financial position or results of operations. In July 2001 the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement requires companies to recognize the fair value of an asset retirement liability in the financial statements by capitalizing that cost as part of the cost of the related long-lived asset. The asset retirement liability should then be allocated to expense by using a systematic and rational method. The statement is effective January 1, 2003. We have not determined the impact of adoption of this statement but the minimum liability would be at least $1 million on an undiscounted basis. In August 2001 the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This statement provides a single accounting model for long-lived assets to be disposed of and changes the criteria that would have to be met to classify an asset as held-for-sale. The statement also requires expected future operating losses from discontinued operations to be recognized in the periods in which the losses are incurred, which is a change from the current requirement of recognizing such operating losses as of the measurement date. The statement is effective January 1, 2002. The adoption of the statement did not have a material effect on our financial position or results of operations. ITEM 7. FINANCIAL STATEMENTS REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Hallador Petroleum Company: We have audited the accompanying consolidated balance sheet of Hallador Petroleum Company (a Colorado corporation) and subsidiaries as of December 31, 2001 and the related consolidated statements of operations and cash flows for each of the two 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. 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, the financial statements referred to above present fairly, in all material respects, the financial position of Hallador Petroleum Company and subsidiaries as of December 31, 2001 and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP /s/ARTHUR ANDERSEN LLP Denver, Colorado March 27, 2002 Consolidated Balance Sheet December 31, 2001 (in thousands)
ASSETS Current assets: Cash and cash equivalents $ 2,078 Accounts receivable- Oil and gas sales 706 Well operations 174 ------- Total current assets 2,958 ------- Oil and gas properties at cost (successful efforts): Unproved properties 204 Proved properties 24,687 Less - accumulated depreciation, depletion, amortization and impairment (16,497) ------- 8,394 ------- Oil and gas operator bonds 366 Investment in Catalytic Solutions 175 Other assets 44 ------- $ 11,937 ======= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable and accrued liabilities $ 833 Oil and gas sales payable 180 ------- Total current liabilities 1,013 ------- Key employee bonus plan 335 ------- Future site restoration - South Cuyama Field 344 ------- Minority interest 5,516 ------- Commitments and contingent liabilities Stockholders' equity: Preferred stock, $.10 par value; 10,000,000 shares authorized; none issued Common stock, $.01 par value; 100,000,000 shares authorized; 7,093,150 shares issued 71 Additional paid-in capital 18,061 Accumulated deficit* (13,403) ------- 4,729 ------- $ 11,937 ======= *Net income has been the only change in stockholders' equity during the past two years.
See accompanying notes. Consolidated Statement of Operations December 31, 2001 (in thousands)
Years ended December 31, 2001 2000 ------ ------ Revenue: Oil $5,109 $6,494 Gas 2,334 1,026 NGLs 320 446 Gain on prospect sale 67 147 Interest and other 130 159 ----- ----- 7,960 8,272 ----- ----- Costs and expenses: Lease operating 4,227 3,477 Exploration costs Geological and geophysical 296 Dry hole expense 123 319 Delay rentals 82 72 Impairment-proved properties 436 Impairment-unproved properties 229 Depreciation, depletion and amortization 1,300 976 General and administrative 909 777 California income taxes 63 Purchase of employee stock options 300 Interest 41 94 ----- ----- 7,710 6,011 ----- ----- Income before minority interest 250 2,261 Minority interest (75) (678) ----- ----- Net income $ 175 $1,583 ===== ===== Basic and diluted income per share $ 0.02 $ 0.22 ===== ===== Weighted average shares outstanding-basic 7,093 7,093 ===== ===== Weighted average shares outstanding-diluted 7,508 7,318 ===== =====
See accompanying notes. CONSOLIDATED STATEMENT OF CASH FLOWS December 31, 2001 (in thousands)
Years ended December 31, 2001 2000 ------ ------ Cash flows from operating activities: Net income $ 175 $1,583 Depreciation, depletion, and amortization 1,300 976 Minority interest 75 678 Impairment 665 Change in accounts receivable 419 (469) Change in payables and accrued liabilities (605) 695 Other 6 ----- ----- Net cash provided by operating activities 2,035 3,463 ----- ----- Cash flows from investing activities: Properties (2,181) (1,715) Other assets (65) (216) ----- ----- Net cash used in investing activities (2,246) (1,931) ----- ----- Cash flows from financing activities: Repayment of debt (200) (1,000) ----- ----- Net increase (decrease) in cash and cash equivalents (411) 532 Cash and cash equivalents, beginning of year 2,489 1,957 ----- ----- Cash and cash equivalents, end of period $2,078 $2,489 ===== ===== Supplemental disclosure of cash flow information: Cash paid out for interest $ 32 $ 84 ===== =====
See accompanying notes. NOTES TO FINANCIAL STATEMENTS (1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES ------------------------------------------ Basis of Presentation and Consolidation --------------------------------------- The accompanying consolidated financial statements include the accounts of Hallador Petroleum Company and its wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. We are engaged in the exploration, development, and production of oil and natural gas primarily in California. On July 21, 1997, Yorktown Energy Partners II and affiliates (Yorktown) invested $5,025,000 in Hallador Petroleum, LLP, a newly formed limited liability limited partnership. We are the general partner and received a 70% interest in the partnership in return for contributing our net assets, and Yorktown represents the limited partners and received a 30% interest for its $5,025,000 cash contribution. As general partner, we consolidate the activity of the partnership and present the 30% limited partners' interest as a minority interest. We are a 92% partner in Santa Barbara Partners (SBP), a general partnership, and account for our investment using the proportionate consolidation method. SBP has a 93% working interest in the South Cuyama field. Oil and Gas Properties ---------------------- We account for our oil and gas activities using the successful efforts method of accounting. Under the successful efforts method, the costs of successful wells, development dry holes and productive leases are capitalized and amortized on a units-of-production basis over the remaining life of the related reserves. Exploratory dry hole costs and other exploratory costs, including geological and geophysical costs, are expensed as incurred. Delay rentals are also expensed as incurred. Cost centers for amortization purposes are determined on a field-by-field basis. Estimated future abandonment and site restoration costs, net of anticipated salvage values, are accrued based on units-of-production. Unproved properties with significant acquisition costs are periodically assessed for impairment in value, with any impairment charged to expense. The carrying value of each field is assessed for impairment on a quarterly basis. If estimated future undiscounted net revenues are less than the recorded amounts, an impairment charge is recorded. Statement of Cash Flows ----------------------- Cash equivalents include investments (primarily commercial paper) with maturities of three months or less from the date of purchase. Income Taxes ------------ Income taxes are provided based on the liability method of accounting pursuant to FAS 109, Accounting for Income Taxes. The provision for income taxes is based on pretax financial taxable income. Deferred tax assets and liabilities are recognized for the future expected tax consequences of temporary differences between income tax and financial reporting and principally relate to differences in the tax basis of assets and liabilities and their reported amounts, using enacted tax rates in effect for the year in which differences are expected to reverse. If it is more likely than not that some portion or all of a deferred tax asset will not be realized, a valuation allowance is recognized. Earnings per Share ------------------ We follow the provisions of FAS 128, Earnings Per Share. Basic earnings per share are computed based on the weighted average number of common shares outstanding. Diluted earnings per share are computed based on the weighted average number of common shares outstanding adjusted for the incremental shares attributed to outstanding stock options. Under the treasury stock method, options to purchase 415,000 and 225,000 shares of common stock were included in the calculation of diluted earnings per share for the years ended December 31, 2001 and 2000, respectively. Use of Estimates in the Preparation of Financial Statements ----------------------------------------------------------- The preparation of financial statements in conformity with generally accepted accounting principles requires us 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 revenue and expenses during the reporting period. Actual amounts could differ from those estimates. (2) INCOME TAXES ------------ We have the following tax carryforwards at December 31, 2001 (in thousands): Statutory depletion $ 3,500 Tax net operating losses (NOLs), utilization limited (expires 2003) 1,500 Tax NOLs, utilization not limited (expires in 2005-2020) 4,700 We have fully reserved our net deferred tax asset account of about $2.2 million. (3) STOCK OPTIONS AND BONUS PLANS Stock Option Plan ----------------- In December 1995, we granted to our CEO 620,000 options and another 62,000 options to other employees at an exercise price of $1.00. These options are fully vested. During 1999, we issued 68,000 options with an exercise price of $1.00, which vested one-third upon grant date with the remainder over the next two years. No options were granted during 2001 and 2000. At December 31, 2000, there were 750,000 options outstanding of which 728,335 are exercisable at $1.00. All options were granted at fair value. On January 19, 2001, we purchased from certain employees 177,777 options at a cost of $1.6875 per option (about $300,000), which was recorded as compensation expense in January 2001. Since December 1995 no options have been exercised. At December 31, 2001, there were 572,223 exercisable and outstanding options. Options to purchase a 3% partnership interest in Hallador Petroleum, LLP are outstanding as of December 31, 2001. The exercise price for these options was based on the fair market value on the date of grant. We account for our option plans under APB 25, Accounting for Stock Issued to Employees. Had compensation costs for the plans been determined consistent with FAS 123, Accounting for Stock-Based Compensation, the effect on 2000 and 2001 operations would have been immaterial. 401-(k) Plan ------------ We maintain a 401-(k) Plan, which all full-time employees are able to participate after six months of service. We match dollar-for-dollar up to 4% of all employee contributions when oil prices are $13.00 or greater per barrel; vesting occurs immediately. Our contributions for 2001 and 2000 were $44,000 and $37,000, respectively. Key Employee Bonus Plan --------------------- At present, Mr. Stabio, CEO, is the only participant in the key employee bonus plan. Bonuses are computed based on cash flow attributed to the SC Field plus accrued interest on the bonus plan liability at 30-day risk free rates. Amounts accrued for 2001 and 2000 were $40,000 and $61,000, respectively. As of December 31, 2001, the liability to Mr. Stabio was $335,000. This liability will not be paid until the earliest of the following events occur; (i) voluntary or involuntary termination of the participant's employment; (ii) our merger or sale or a sale of substantially all of our assets, or (iii) the exercise by a participant of any of our stock options which requires a payment by the participant of more than $100,000. The amounts accrued are unfunded and unsecured. Catalytic Solutions Investment ------------------------------ During 1998, we invested $62,000 for a small ownership in Catalytic Solutions, Inc. (CSI), a private company, located in Oxnard, California (a Los Angeles suburb). CSI manufactures catalytic converters that reduce toxic emissions from internal combustion engines. During 2000, we invested another $113,000 resulting in a total ownership of about .006. This investment is accounted for under the cost method. Mr. Stabio and other employees own less than a quarter percent (.0025) in CSI. (4) MAJOR CUSTOMERS --------------- The SC Field's oil production is purchased by Pacific Marketing and Transportation LLC and the gas by Coral Energy. (5) COMMITMENTS AND CONTINGENT LIABILITIES -------------------------------------- South Cuyama Field ------------------ In January 1999, the California legislature passed a bill, which increased our operator's bond from $100,000 to $250,000 to be phased in over a five-year period. In addition, an idle well bill was passed to ensure that funds would be available to properly plug and abandon (P&A) California wells upon their depletion. Over the next ten years, we as the SC Field's operator, are required to place in an interest-bearing escrow account $500 per year for each idle well in the SC Field until such well is plugged and abandoned or until $5,000 has been deposited. Through June 30, 2001 we have made three installments totaling $196,000. We estimate that after 10 annual installments we will have met the current funding obligation of $700,000 considering the interest to be earned. As the SC Field depletes, and more wells move from the producing category to the idle-well category we will have to make additional annual payments. Presently, there are 280 wells in the SC Field, 140 of which are classified as "idle". During 1999, we began amortizing, using the units-of-production method, our share of the estimated future costs ($1,207,000) to P&A the SC Field's 280 wells. Included in the DD&A expense for 2000 and 2001 was $113,000 and $154,000, respectively, associated with these estimated future costs. Self-insurance for Employee Medical Costs ----------------------------------------- Due to the rising costs in providing health care coverage for our employees we changed from a standard type of policy to a self-insurance policy. We are responsible for the first $5,700 for each employee and their dependents health costs. Our ultimate exposure in any given year is about $100,000. Starting April 2002 we will be accruing $3,000 per month for our estimated claims. (6) OIL AND GAS RESERVE DATA (UNAUDITED) ------------------------------------ The following reserve estimates for the years ended December 31, 2000 and 2001 were prepared by a sole-proprietor consulting petroleum engineer based on data we supplied. Be cautious that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and NGLs 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 reserves expected to be recovered through existing wells with existing equipment and operating methods. There were no significant proved undeveloped reserves at December 31, 2000. Oil prices in the SC Field at December 31, 2001 were $16.48. Due to these low oil prices the SC Field had an economic life of two years. At March 25, 2002 oil prices in the SC Field had increased to $22 which gave it an estimated economic life of six years. Due to this change, we are presenting two sets of reserve estimates and SMOG data; one based on year end prices and the other based on March 25, 2002 prices. Analysis of Changes in Proved Reserves (in thousands, using December 31, 2001 prices)
Oil Gas NGLs (BBLs) (MCF) (BBLs) ------- ------- ------- Balance at December 31, 1999 3,039 2,022 212 Revisions of previous estimates (693) (77) 75 Discoveries 223 13 Production (234) ( 287) (22) ----- ----- ---- Balance at December 31, 2000 2,112 1,881 278 Revisions of previous estimates (1) (1,492) (584) (175) Discoveries 97 1,573 Production (233) (368) (18) ----- ----- ---- Balance at December 31, 2001 484 2,502 85 ===== ===== ==== Net of 30% minority interest 339 1,751 60 ===== ===== ==== Proved producing 484 1,760 85 ===== ===== ==== Net of 30% minority interest 349 1,232 60 ===== ===== ==== (1) Due to low oil prices at December 31, 2001, we took a significant downward revision for the SC Field's reserves.
Analysis of Changes in Proved Reserves (in thousands, using March 25, 2002 prices)
Oil Gas NGLs (BBLs) (MCF) (BBLs) ------- ------- ------- Balance at December 31, 1999 3,039 2,022 212 Revisions of previous estimates (693) (77) 75 Discoveries 223 13 Production (234) ( 287) (22) ----- ----- ---- Balance at December 31, 2000 2,112 1,881 278 Revisions of previous estimates (988) (300) (143) Discoveries 163 1,867 Production (233) (368) (18) ----- ----- ---- Balance at December 31, 2001 1,054 3,080 117 ===== ===== ==== Net of 30% minority interest 738 2,156 82 ===== ===== ==== Proved producing 1,054 2,195 117 ===== ===== ==== Net of 30% minority interest 738 1,537 82 ===== ===== ====
The following table (in thousands) sets forth a standardized measure of the discounted future net cash flows attributable to our proved developed oil and gas reserves (hereinafter referred to as "SMOG"). Future cash inflows were computed using December 31, 2000 and 2001 product prices of $21.13 and $16.48 for oil, $28.73 and $9.60 for NGLs and $7.19 and $2.29 for gas, respectively. March 25, 2002 prices were $22.10 for oil and $3 for gas. Future production costs represent the estimated future expenditures to be incurred in producing the reserves, assuming continuation of economic conditions existing at year-end. Discounting the annual net cash inflows at 10% illustrates the impact of timing on these future cash inflows.
2001 2001 2000 ------ ------ ------ (3/25/02 prices) Future Revenue Oil $ 8,000 $23,300 $45,000 Gas 6,200 9,600 13,000 NGLs 300 1,000 8,000 ------ ------ ------ Future cash inflows 14,500 33,900 66,000 Future cash outflows - production costs (9,700) (22,600) (47,000) Future income taxes (1,000) ------ ------ ------ Future net cash flows 4,800 11,300 18,000 10% discount factor (900) (2,100) (6,400) ------ ------ ------ SMOG $ 3,900 $ 9,200 $11,600 ====== ====== ====== Net of 30% minority interest $ 2,730 $ 6,440 $ 8,120 ====== ====== ======
The following table (in thousands) summarizes the principal factors comprising the changes in SMOG:
2001 2000 ------ ------ SMOG, beginning of year $11,600 $ 19,000 Sales of oil and gas, net of production costs (3,540) (4,500) Net changes in prices and production costs (9,060) 500 Revisions (300) (10,400) Discoveries 3,900 900 Change in income taxes 200 1,800 Changes in production rates and other 2,200 Acceleration of discount 1,100 2,100 ------ ------ SMOG, end of year $ 3,900 $11,600 ====== ======
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE: None PART III ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT CORTLANDT S. DIETLER, 80, has been one of our directors since November 1995. From April 1995 to October 1999 he was CEO of TransMontaigne Inc. and is currently Chairman of the Board. He also serves as a director of Carbon Energy Corporation, Forest Oil Corporation and Key Production Company. DAVID HARDIE, 51, is the Chairman of the Board and has served as a director since July 1989. He is a General Partner of Hallador Venture Partners LLC, the General Partner of Hallador Venture Fund II & III. Mr. Hardie is also a director of Freedom Communications Company based in Irvine, California and serves as a director and partner of other private entities that are owned by members of his family. STEVEN HARDIE, 47, has been a director since 1994. He and David Hardie are brothers. For the last 16 years he has been a self-employed film producer. He also serves as a director and partner of other private entities that are owned by members of his family. BRYAN H. LAWRENCE, 59, has been one of our directors since November 1995. He is a founder and senior manager of Yorktown Partners LLC that manages investment partnerships formerly affiliated with Dillon, Read & Co. Inc., an investment-banking firm (Dillon Read.) He had been employed with Dillon, Read since 1966, serving most recently as a Managing Director until the merger of Dillon Read with SBC Warburg in September 1997. He also serves as a Director of Carbon Energy Corporation, D&K Healthcare Resources, Inc., TransMontaigne, Inc., and Vintage Petroleum, Inc. (each a United States public company), and Cavell Energy Corp. (a Canadian public company) and certain non-public companies in the energy industry in which Yorktown partnership holds equity interests including PetroSantander Inc., Savoy Energy, L.P., Ricks Exploration, Inc., Athanor Resources Inc., Camden Resources,Inc., and Crosstex Energy Holdings, Inc., and ESI Energy Services, Inc. He is a graduate of Hamilton College and also has a MBA from Columbia University. VICTOR P. STABIO, 54, is our President, CEO, CFO and a director. He joined us in March 1991 as our President and CEO and has been active in the oil and gas business for the past 29 years. Section 16(a) Beneficial Ownership Reporting Compliance ------------------------------------------------------- Certain members of the Hardie family were delinquent in reporting certain inter-family transactions on Form 4s. ITEM 10. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE Annual Compensation --------------------------------------------- Name and Principal Other Annual Position Year Salary Bonus (1) Compensation (2) --------------------- ---- --------- ---------- ---------------- Victor P. Stabio, CEO 2001 $120,800 $193,300 $7,300 2000 110,500 94,700 5,900 1999 105,000 48,000 4,400
(1) Includes amounts, payment of which is deferred, pursuant to the Key Employee Bonus Plan and the purchase of 75,000 stock options at a cost $1.6875 per option or $126,500. (2) Our contribution to the 401(k) Plan. During 1997, Mr. Stabio was granted an option to purchase 1.75% of Hallador Petroleum, LLP for $294,000 that expires December 31, 2010. No options were exercised during the last three years. On January 19, 2001 we purchased 75,000 options from Mr. Stabio at a cost of $1.6875 per option or $126,500. At December 31, 2001 Mr. Stabio had 545,000 exercisable options and in-the-money value $409,000. Change in Control Arrangements ------------------------------ As of December 31, 2001, we have accrued $335,000 payable to Mr. Stabio pursuant to the key employee bonus plan. The $335,000 will become payable upon our merger/sale or sale of substantially all of our assets or his voluntary or involuntary termination. ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table is as of March 29, 2002.
Name No. Shares (1) % of Class (1) ------------------------------------ --------------- ------------- David Hardie and Steven Hardie as 3,791,259 53 Nominee for Hardie Family Members (2) Victor P. Stabio (3) 609,937 8 Cortlandt S. Dietler (4) 100,000 1 Bryan H. Lawrence (5) 2,328,500 33 SBC Warburg Dillion Read Inc. (6) 421,500 6 All directors and executive officer as a group (3) 6,829,696 96
(1) Based on total outstanding shares of 7,093,150 if no options are held by the named directors, or based on a pro forma calculation of the total outstanding shares including shares issued upon exercise of options held by the named director or by members of the named group. Beneficial ownership of certain shares have been, or is being, specifically disclaimed by certain directors in ownership reports filed with the SEC. (2) The Hardie family business address is 740 University Avenue, Suite 110, Sacramento, California 95825. (3) Includes 545,000 shares issuable upon the exercise of options by Mr. Stabio. (4) Mr. Dietler's address is P. O. Box 5660, Denver, Colorado 80217. All shares are held by Pinnacle Engine Company LLC, wholly owned by Mr. Dietler. (5) Mr. Lawrence's address is 410 Park Avenue, 19th Floor, New York, NY 10022. Mr. Lawrence owns 50,000 shares directly, and the remainder is held by Yorktown Energy Partners II, L.P., an affiliate. (6) SBC Warburg Dillon Read Inc.'s address is 535 Madison Avenue, New York, NY 10022. ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None. PART IV ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits 3.1 Restated Articles of Incorporation of Kimbark Oil and Gas Company, effective September 24, 1987 (1) 3.2 Articles of Amendment to Restated Articles of Incorporation of Kimbark Oil & Gas Company, effective December 14, 1989, to effect change of name to Hallador Petroleum Company and to change the par value and number of authorized shares of common stock (1) 3.3 Amendment to Articles of Incorporation dated December 31, 1990 to effect the one-for-ten reverse stock split (2) 3.4 By-laws of Hallador Petroleum Company, effective November 9, 1993 (4) 10.1 Composite Agreement and Plan of Merger dated as of July 17, 1989, as amended as of August 24, 1989, among Kimbark Oil & Gas Company, KOG Acquisition, Inc., Hallador Exploration Company and Harco Investors, with Exhibits A, B, C and D (1) 10.2 Hallador Petroleum Company 1993 Stock Option Plan *(3) 10.3 Not used 10.4 Not used 10.5 Hallador Petroleum Company Key Employee Bonus Compensation Plan *(3) 10.6 Not used 10.7 EOTT ENERGY NGL Contract (10) 10.8 EOTT ENERGY OIL Contract (10) 10.9 First Amendment to the 1993 Stock Option Plan *(6) 10.10 First Amendment to Key Employee Bonus Compensation Plan *(6) 10.11 Stock Purchase Agreement with Yorktown dated November 15, 1995 (6) 10.12 Second Amendment to Key Employee Bonus Compensation Plan *(7) 10.13 Hallador Petroleum, LLP Agreement (9) 10.14 Hallador Petroleum, LLP Stock Option Agreement *(9) 10.15 ARCO Indemnity - excerpt from the Purchase and Sale Agreement dated January 29, 1990 by and between Atlantic Richfield Corporation and Stream Energy, Inc. (11) 21.1 List of Subsidiaries (2) 99.a Letter regarding Arthur Andersen LLP (11) ------------------- (1) Incorporated by reference (IBR) to the 1989 Form 10-K. (2) IBR to the 1990 Form 10-K. (3) IBR to the 1992 Form 10-KSB. (4) IBR to the 1993 Form 10-KSB. (5) Not used. (6) IBR to the 1995 Form 10-KSB. (7) IBR to the September 30, 1996 Form 10-QSB. (8) IBR to the September 30, 1997 Form 10-QSB. (9) IBR to the December 31, 1997 Form 10-KSB. (10) IBR to the December 31, 2000 Form 10-KSB. (11) Filed herewith. * Management contracts or compensatory plans. (b) No reports on Form 8-K were filed during the 2001 fourth quarter. SIGNATURES In accordance with Section 13 or 15(d) of the Exchange Act, the Registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. HALLADOR PETROLEUM COMPANY BY:/S/VICTOR P. STABIO VICTOR P. STABIO, CEO Dated: March 29, 2002 In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. /S/ DAVID HARDIE Chairman March 29, 2002 DAVID HARDIE /S/ VICTOR P. STABIO CEO, Principal Financial March 29, 2002 VICTOR P. STABIO and Accounting Officer and Director /S/ BRYAN LAWRENCE Director March 29, 2002 BRYAN LAWRENCE