10KSB 1 aspen10ksb063004.txt FORM 10-KSB (6-30-2004) ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ---------------------- FORM 10-KSB (Mark One) [ ] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934. For the fiscal year ended June 30, 2004 [ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934. For the transition period from to ------- ------ Commission file number: 001-12531 ASPEN EXPLORATION CORPORATION -------------------------------------------- (Name of small business issuer in its charter) Delaware 84-0811316 ------------------------------ ----------------- (State or other jurisdiction of (IRS Employer incorporation or organization) Identification No.) 2050 S. Oneida St., Suite 208 Denver, Colorado 80224-2426 -------------------------------------- -------- (Address of principal executive offices) (Zip Code) Issuer's telephone number: (303) 639-9860 Securities registered pursuant to Section 12(b) of the Exchange Act: None Securities registered pursuant to Section 12(g) of the Act: Common Stock, $0.005 par value Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the 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 such filing requirements for the past 90 days. Yes X No --- --- Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B 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. Yes X No --- --- Aspen's revenues for the fiscal year ended June 30, 2004 were $1,823,936. At September 23, 2004, the aggregate market value of the shares held by non-affiliates was approximately $4,632,009. The aggregate market value was calculated by multiplying the mean of the closing bid and asked prices ($1.295) of the common stock of Aspen on the Over-the-Counter Bulletin Board listing for that date, by the number of shares of stock held by non-affiliates of Aspen (3,576,841). At September 23, 2004, there were 5,958,979 shares of common stock (Aspen's only class of voting stock) outstanding. Transitional Small Business Disclosure Format (check one): Yes No X ----- ----- ================================================================================ PART I ITEM 1. BUSINESS ----------------- Because we want to provide you with more meaningful and useful information, this Annual Report on Form 10-KSB contains certain "forward-looking statements" (as such term is defined in Section 21E of the Securities Exchange Act of 1934, as amended). These statements reflect our current expectations regarding our possible future results of operations, performance, and achievements. These forward-looking statements are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, regulation of the Securities and Exchange Commission, and common law. Wherever possible, we have tried to identify these forward-looking statements by using words such as "anticipate," "believe," "estimate," "expect," "plan," "intend," and similar expressions. These statements reflect our current beliefs and are based on information currently available to us. Accordingly, these statements are subject to certain risks, uncertainties, and contingencies, which could cause our actual results, performance, or achievements to differ materially from those expressed in, or implied by, such statements. These risks, uncertainties and contingencies include, without limitation, the factors set forth under "Item 6. Management's Discussion and Analysis of Financial Conditions or Plan of Operation - Factors that may affect future operating results." We have no obligation to update or revise any such forward-looking statements that may be made to reflect events or circumstances after the date of this Form 10-KSB. Summary of Our Business Aspen was incorporated under the laws of the State of Delaware on February 28, 1980 for the primary purpose of acquiring, exploring and developing oil and gas and other mineral properties. Our principal executive offices are located at 2050 S. Oneida St., Suite 208, Denver, Colorado 80224-2426. Our telephone number is (303) 639-9860, and our facsimile number is 303-639-9863. Our websites are WWW.ASPENEXPLORATION.COM and WWW.ASPNX.COM and our email address is AECORP2@QWEST.NET. We are currently engaged primarily in the exploration and development of oil and gas properties in California. We have an interest in two inactive subsidiaries: a 25% interest in Aspen Power Systems, LLC (a company that has not been engaged in business since 2002), and Aspen Gold Mining Co., a company that has not been engaged in business since 1995. Oil and Gas Exploration and Development. Our major emphasis has been participation in the oil and gas segment, acquiring interests in producing oil or gas properties and participating in drilling operations. We engage in a broad range of activities associated with the oil and gas business in an effort to develop oil and gas reserves. With the assistance of our management, independent contractors retained from time to time by Aspen, and, to a lesser extent, unsolicited submissions, we have identified and will continue to identify prospects that we believe are suitable for drilling and acquisition. Currently, our primary area of interest is in the state of California. We have acquired a number of interests in oil and gas properties in California, as described below in more detail. In addition, we also act as operator for most of our producing wells and receive management fees for these services. Aspen has information on hand which indicates coal deposits exist under the approximate 2,074 acres of leases which Aspen has obtained in Arapahoe and Elbert Counties, Colorado. We do not know if it is possible or economically feasible to produce any coalbed methane which may exist on these leases. The leases are paid-up oil and gas leases (which include coalbed methane) which expired on their own terms in April and May of 2004. Company Strategy: At the present time, we cannot finance our oil and gas acquisitions and drilling activities solely through our own resources. Consequently, we identify prospects or production to acquire and drill prospects, and seek other industry investors who are willing to participate in these activities with us. We frequently retain a promotional interest in these prospects, but generally we finance a portion (and sometimes a significant portion) of the acquisition and drilling costs. We have in the past acquired interests in producing properties by issuing shares of our common stock, but because of the current low price of our stock, it has become more difficult and expensive to do so. Where we acquire an interest in acreage on which exploration or development drilling is planned, we will seldom assume the entire risk of acquisition or drilling. Rather, we prefer to assess the relative potential and 2 risks of each prospect and determine the degree to which we will participate in the exploration or development drilling. Generally, we have determined that it is more beneficial to invite industry participants to share the risk and the reward of the prospect by financing some or all of the costs of drilling contemplated wells. In such cases, we may retain a carried working interest, a reversionary interest, or may be required to finance all or a portion of our proportional interest in the prospect. Although this approach reduces our potential return should the drilling operations prove successful, it also reduces our risk and financial commitment to a particular prospect. Conversely, we may from time to time participate in drilling prospects offered by other persons if we believe that the potential benefit from the drilling operations outweighs the risk and the cost of the proposed operations. This approach allows us to diversify into a larger number of prospects at a lower cost per prospect, but these operations (commonly known as "farm-ins") are generally more expensive than operations where we offer the participation to others (known as "farm-outs"). As of this writing, we have participated in the drilling of two farm-in wells. Principal Products Produced and Services Rendered. Our principal products during fiscal 2004 were crude oil and natural gas. Crude oil and natural gas are generally sold to various entities, including pipeline companies, which usually service the area in which our producing wells are located. In the fiscal year ended June 30, 2004, crude oil and natural gas sales and revenues from operating oil and gas properties accounted for $1,820,680, or 99.8% of our total revenues; while $3,256, or .2%, was from interest and other income. Distribution Methods of the Products or Services. We are not involved in the distribution aspect of the oil and gas industry. Status of any Publicly Announced New Products or Services. We do not have a new product or service that would require the investment of a material amount of our assets or which we believe is material to our business. Therefore, we have not made a public announcement of nor have we made information otherwise public about any such product or service. Competitive Business Conditions: The exploration for, and development, production and acquisition of, oil, gas, precious metals and other minerals are subject to intense competition, as is the production and sale of electrical power. The principal methods of compensation for the acquisition of oil and gas and other mineral properties are the payment of: (i) cash bonuses at the time of the acquisition of leases; (ii) delay rentals and the amount of annual rental payments; (iii) advance royalties and the use of differential royalty rates; and (iv) the stipulations requiring exploration and production commitments by the lessee. Some of our current competitors, and many of our potential competitors in the oil and gas industry have vast experience, are larger and have significantly greater financial resources, existing staff and labor forces, equipment, and other resources than we do. Consequently, these competitors may be in a better position to compete for oil and gas projects. In addition, the availability of a ready market for oil and gas will depend upon numerous factors beyond our control, including the extent of domestic production and imports of oil and gas, proximity and capacity of pipelines, and the effect of federal and state regulation of oil and gas sales, as well as environmental restrictions on exploration and usage of oil and gas. Further, we expect that competition for leasing of oil and gas prospects will become even more intense in the future. We have a minimal competitive position in the oil and gas industry. Sources and Availability of Raw Materials: To conduct business, we depend on such items as drilling rigs and other equipment, casing pipe, drilling mud and other supplies, core drilling equipment, and other equipment necessary for our operations. Such items have been commonly available from a number of sources. Although we foresee no short supply or difficulty in acquiring any equipment relevant to the conduct of business, we cannot offer any assurances that these items will be available or that we will be able to acquire the items on economically feasible terms. Dependence Upon One or a Few Major Customers: We generally sell our oil and gas production to a limited number of companies. In fiscal 2004 we obtained more than 10% of our revenues from sales to Calpine Corporation and Enserco Energy, 3 Inc. and ConocoPhillips; in 2003 more than 10% of our revenues derived from Calpine Corporation and Enserco Energy, Inc. We do not believe the loss of these customers would adversely impact our revenues because we believe that oil and gas sales are primarily market driven and are not dependent on particular purchasers. Consequently, we believe that substitute purchasers would be available based on the widespread uses of and the need for oil and gas. Patents, Trademarks, Licenses, Franchises, Concessions, Royalty Agreements or Labor Contracts (Including Duration). We do not own any patents, licenses, franchises, or concessions except oil, gas and other mineral interests granted by governmental authorities and private landowners. We received a trademark registration (serial no. 74-396,919 registered on March 1, 1994) for our corporate logo. The registration is for a term of ten years. To maintain the registration for its entire term we filed an affidavit of commercial use on February 21, 2000. We are currently in the process of renewing the trademark registration. Need for Governmental Approval of Principal Products or Services. We do not need to seek government approval of our principal products. Effect of Existing or Probable Governmental Regulation. Oil and gas exploration and production are open to significant governmental regulation including worker health and safety laws, employment regulations and environmental regulations. Operations that occur on public lands may be subject to further regulation by the Bureau of Land Management, the U.S. Army Corps of Engineers, or the U.S. Forest Service as well as other federal and state agencies. Estimate of Amounts Spent on Research and Development Activities. We have not engaged in any material research and development activities since our inception. Costs and Effects of Compliance with Environmental Laws (federal, state and local). Because we are engaged in extracting natural resources, our business is subject to various federal, state and local provisions regarding environmental and ecological matters. Therefore, compliance with environmental laws may necessitate significant capital outlays, affect our earnings potential, and cause material changes in our current and proposed business activities. At the present time, however, the environmental laws do not materially hinder nor adversely affect our business. Capital expenditures relating to environmental control facilities have not been material to our operations since our inception. Employees. At June 30, 2004, we employed two full-time and one part-time person. We also employ independent contractors and other consultants, as needed. ITEM 2. PROPERTIES ------------------- General Information: We have a significant amount of information regarding the proven developed and undeveloped oil and gas reserves which can be found in below in this Item 2 as well as in the notes to our financial statements. Drilling and Acquisition Activity: During the fiscal year ended June 30, 2004, we participated in the drilling of 7 gross (1.38 net) wells, of which 5 gross (1.05 net) were completed as gas wells and 2 were dry holes. Of the 7 wells drilled, 1 operated gas well was drilled in the Grimes Field, 1 operated gas well was drilled in the Winters Field, 2 operated gas wells were drilled in the West Grimes Field, 1 operated gas well was drilled in the Denverton Creek Field and 2 dry holes were drilled in the Kirk Buckeye Field. In addition to the drilling activity, 3 operated gas wells and 1 non-operated gas well were acquired from an independent oil and gas company. These wells are located in Glenn, Sutter and Yolo Counties, California. 4 West Grimes Field, Colusa County, California -------------------------------------------- The WGU #15-8, located in the West Grimes Field, Colusa County, California, was directionally drilled to a depth of 7,750 feet and encountered approximately 60 feet of potential net gas pay in the Forbes Formation. Production casing was run based on very promising mud log and electric log responses. The well commenced production in August 2004 at the prolific rate of 3,700 MCFPD. Production in mid-September has declined to 1,750 MCFPD. The WGU #16-3 was drilled to a depth of 7,929 feet and encountered potential gas pay in various intervals in the Forbes formation. The well was completed and put on production in early August and is currently flowing 130 MCFPD. These wells were drilled based on a recently acquired 10.5 square mile 3-D seismic program located over Aspen's 5,000 plus leased acres in this field. Approximately 12 additional excellent drilling prospects have been identified. The wells in this field produce from multiple Forbes intervals ranging in depth from 6,000 feet to 8,500 feet and have produced over 80 BCF of gas to date. Numerous wells in this immediate area have produced at very prolific flow rates (4,000 MCFPD), have yielded excellent per well reserves (3 to 4 BCF per well), and have long productive well lives. Several of the 10 producing wells that Aspen acquired in this field last year have been producing for 40 years. Aspen believes that several of these wells may have additional gas potential in behind-pipe zones, which have not yet been perforated. Aspen has a 21% operated working interest in this field. The Morris #12-2, located in the West Grimes Field, Colusa County, California, was drilled to a depth of 8,400 feet and encountered approximately 73 feet of net gas pay (100 feet gross) in the Forbes Formation. This zone was perforated and tested at a prolific stabilized rate of 4,845 MCFPD of gas with a flowing tubing pressure of 3,350 psig and a flowing casing pressure of 3,400 psig. The shut in tubing pressure was 3,475 psig. Aspen has a 21% operated working interest in this field. We anticipate that drilling will commence on the fourth well in this project, the WGU #15-9, in October 2004. Momentum Farmout, Colusa, Yolo, Sutter and Solano Counties, California ---------------------------------------------------------------------- Aspen recently acquired a farmout package consisting of 6 quality drilling prospects, which are leased and defined by 3-D seismic data and well control. These prospects will be drilled during the 2004 - 2005 drilling seasons (4 wells in 2004 and 2 wells in 2005). Aspen has a 28.75% operated working interest in these wells. The first well drilled in this package, the Ettl #1-10, located in the Grimes Gas Field, Sutter County, California, was drilled to a depth of 7,600 feet to test three potential Forbes targets. The Grimes Gas Field has produced approximately 650 BCF (billion cubic feet) of gas and is currently producing 11,000 MCFPD. The well was successfully completed and commenced gas sales in July 2004 at the rate of 500 MCFPD. The second well drilled, the Chickohominy #1-12, located in the Winters Gas Field, Yolo County, California, was drilled to a depth of 5,050 feet, and encountered 25 feet of extremely permeable and porous potential gas pay in the Winters Formation. The well was perforated on June 28th, and tested at a stable gas rate of 2,540 MCFPD with a flowing tubing pressure of 1,725 psig. Gas sales commenced in August 2004 at a stable rate of 1,000 MCFPD with a flowing tubing pressure of 1,900 psig. The Griffin #1-1, located in the Winters Gas Field, Yolo County, California, was drilled to a depth of 5,000 feet, and encountered 15 net feet of extremely permeable and porous gas pay in the McCune Sand. This zone was perforated and tested at a stabilized rate of 1,385 MCFPD on a 12/64 inch choke. There was very little pressure drawdown during the flow test. The shut in pressure is approximately 2,000 psig. This was the third successful well drilled on a recently acquired farmout package consisting of 6 quality drilling prospects which are leased and defined by 3-D seismic data and well control. We anticipate that drilling will commence on the fourth well in this project, the Meckfessel #1-24, in October 2004. Aspen has a 28.75% operated working interest in these wells. Millar Field, Yolo County, California ------------------------------------- Aspen successfully recompleted its Pope Bypass #1-5 well, located in the Millar Field, Yolo County, California, approximately 50 miles southwest of Sacramento. This well was drilled to a depth of 7,800 feet and we believe encountered approximately 70 feet of potential net gas pay in several intervals of the Winters formation. The Winters sands in this area are extremely porous and permeable, and exhibit excellent electric log characteristics. One 2 foot 5 interval (top of 6 foot sand) was perforated and gas sales commenced on June 20, 2003 at a rate of 1,000 MCFPD. This thin zone produced 252,000 MCF though February 2004 when it watered out. The well was recompleted in March 2004 at the top (7,282 feet to 7,285 feet) of a 25 foot thick zone and after five months of production is still flowing 1,500 MCFPD with a flowing tubing pressure of 2,000 psig. Aspen currently has a 25.40% operated working interest in this well. Feather River Prospect, Sutter County, California ------------------------------------------------- Aspen completed a 12 1/2 square mile 3-D seismic survey over leased acreage in Sutter County, California. This data is currently being processed and will be interpreted over the next few months. It is hopeful that analysis of the data will yield several exciting shallow gas targets (2,500 feet) although initial indications show only a few small gas anomalies. On a positive note, Aspen has acquired 2 gas wells located on this property. One of these wells tested at 3,000 MCFPD and will probably commence gas sales in November 2004 at a rate of 500 MCFPD after pipeline construction is completed. Aspen has a 20.0% operated working interest in this project. Kirk-Buckeye Field, Colusa County, California --------------------------------------------- Aspen has drilled 4 gas wells out of 6 attempts in this field during the last 3 fiscal years. These wells produce from multiple horizons in the Forbes formation from depths ranging from 7,500 feet to 9,500 feet. Aspen has operated working interests in these wells ranging from approximately 15% to 36%. Sour Grass Prospect, Tehama County, California ---------------------------------------------- The Sour Grass prospect area is a 2,300 acre play located in southern Tehama County. In this project, for which a 7.5 square mile area 3-D seismic survey has been acquired, Aspen has a 23.33% operated working interest. There is also abundant well data for the area in addition to 2-D seismic survey information. Several prospective locations have been identified through an analysis of the data, with numerous pay zones from 2,000 to 6,000 feet in depth. Drilling of the first five wells in this project resulted in four producers and one dry hole. We will drill 1 additional well in this area this year. Denverton Creek Field, Solano County, California. ------------------------------------------------- For the past three years, we have been the recipient of the California Division of Oil, Gas, and Geothermal Resources (CDOGGR) "Outstanding Lease Maintenance Award" for our operations in the Denverton Creek gas field. CDOGGR gives this award to operators who not only meet, but exceed, the requirements for producing well operations set by CDOGGR. Aspen drilled the Emigh #35-6 in this field this year to a depth of 11,200 feet. Production casing was run based on encouraging mud log and electric log responses. The well was perforated in May 2004 and commenced gas sales in June 2004. Aspen has a 5.25% operated working interest in this well. Aspen has now drilled 13 gas wells out of 16 attempts in this field and has already produced approximately 10 BCF of gas. Aspen is the operator of all the wells in this field and has working interests ranging from 5% to 32% (with 25% working interest being the most common). The field is productive from 10 separate horizons ranging in depth from 9,000 feet to 12,000 feet. Aspen has extended the former field limits by 2 miles to the northeast and discovered new pay horizons. Current gross production is approximately 600 MCFPD of high quality natural gas (1085 BTU) with numerous behind-pipe zones in many of the wells. Sac Valley Acquisition ---------------------- Effective, October 1, 2003, Aspen acquired certain natural gas producing wells located in the Sacramento Valley of northern California. The acquisition consisted of 4 operated gas wells and 1 non-operated gas well located in various fields in the vicinity of Aspen's existing operations. Aspen's net working interests acquired in the operated wells range from 38% to 90%. These wells have flat decline rates with long productive lives. Aspen believes that excellent behind-pipe potential exists in one of the wells. 6 Drilling Activity: The following table sets forth the results of our drilling activities during the fiscal years ended June 30, 2002, 2003 and 2004: Drilling Activity ----------------- Gross Wells Net Wells Year Total Producing Dry Total Producing Dry ---- ----- --------- --- ----- --------- --- 2002 Exploratory 6 4 2 1.32 .98 .34 2003 Exploratory 8 7 1 1.45 1.22 .23 2004 Exploratory 7 5 2 1.38 1.05 .33 Production Information: Net Production, Average Sales Price and Average Production Costs (Lifting). -------------------------------------------------------------------------- The table below sets forth the net quantities of oil and gas production (net of all royalties, overriding royalties and production due to others) attributable to Aspen for the fiscal years ended June 30, 2004, 2003, and 2002, and the average sales prices, average production costs and direct lifting costs per unit of production. Years Ended June 30, -------------------- 2004 2003 2002 ---- ---- ---- Net Production Oil (Bbls) 357 768 3,055 Gas (MMcf) 305 248 227 Average Sales Prices Oil (per Bbl) $31.65 $26.13 $20.20 Gas (per Mcf) $ 5.17 $ 4.23 $ 2.78 Average Production Cost1 Per equivalent Bbl of oil $15.73 $12.83 $11.21 Average Lifting Costs2 Per equivalent Bbl of oil $ 4.73 $ 3.61 $ 2.86 1 Production costs include all operating expenses, depreciation, depletion and amortization, lease operating expenses and all associated taxes. 2 Direct lifting costs do not include impairment expense, ceiling write-down, or depreciation, depletion and amortization. 7 Productive Wells and Acreage: Gross and Net Productive Gas Wells, Developed Acres, and Overriding Royalty --------------------------------------------------------------------------- Interests. ---------- Leasehold Interests - Productive Wells and Developed Acres: The tables below sets forth Aspen's leasehold interests in productive and shut-in gas wells, and in developed acres, at June 30, 2004: Producing and Shut-In Wells Gross Net1 ----- ---- Prospect Gas Gas -------- --- --- California: Anderson Farms 1 0.20000 Anderson Unit 1-2 1 0.90000 Armstrong 17-4 1 0.36000 Balsdon 3-21 1 0.05983 Balsdon 6 1 0.04134 Chickohominy 1-12 1 0.28750 Cygnus 2 1 0.05125 Deane 1 1 0.12938 Dragon 1 1 0.28350 Eastby 36-2 1 0.07770 Elektra 1 1 0.07560 Emigh 34-1 1 0.32550 Emigh 35-2 1 0.32800 Emigh 35-3 1 0.11900 Emigh 35-6 1 0.05514 Ettl 1-10 1 0.28750 Firestone 1-10 1 0.03850 Gay Unit 1 0.21000 Grey Wolf 1 1 0.18000 Houghton 25-1 1 0.07770 Johnson Unit 4 0.84000 Kuppenbender 20-2 1 0.19950 Kuppenbender 20-3 1 0.15200 Leal 22-1 1 0.23334 McCullough 36-1 1 0.19750 Malton Arbuckle 1 1 0.51667 Mapco-Kylling 1 1 0.37800 NL&F 26-1 1 0.23334 Noseco 1 1 0.67900 Parsons 1 1 0.45000 Pinheiro 1-10 1 0.01890 Pinheiro 2-10 1 0.01890 Pope Bypass 1-5 1 0.25400 Porter 26-2 1 0.23334 Quarre 30-2 1 0.23334 Sanborn 3-3 1 0.12762 Sanborn 4-10 1 0.02979 Sciortino 1-7 1 0.03000 South Sycamore 7 1 0.21000 South Sycamore 20 1 0.21000 Tiahrt 1-4 1 0.13617 Verona Farms 1 1 0.20000 West Grimes Unit 14 2 0.42000 West Grimes Unit 15 4 0.84000 West Grimes Unit 16 3 0.61000 Strain Ranches 16-3 1 0.21000 Strain Ranches 17-1 1 0.21000 Walter Trust 1 1 0.07291 Zimmerman 1-24 1 0.23334 TOTAL 58 12.2651 8 1 A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. Developed Acreage Table Aspen's Developed Acres1 Prospect Gross2 Net3 -------- ----- --- California: Denverton Creek 1,431 216 Feather River 320 64 Firestone 1-10 160 6 Grey Wolf 1 120 22 Kirk Buckeye 800 241 Malton Black Butte Field 2,003 279 McCullough 36-1 583 115 Momentum 296 85 Phillips Acquisition 1,120 79 Pope Bypass 1-5 120 30 Sac Valley Acquisition 1,324 555 Sour Grass 1,312 306 West Grimes 2,197 461 ------- ------ TOTAL 11,786 2,459 ====== ====== 1 Consists of acres spaced or assignable to productive wells. 2 A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned. 3 A net acre is deemed to exist when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof. Royalty Interests in Productive Wells and Developed Acreage: The following tables set forth Aspen's royalty interest in productive gas wells and developed acres at June 30, 2004: Overriding Royalty Interests Productive Wells Gross Prospect Interest(%) Gas Acreage1 -------- ----------- --- -------- California: Denverton Creek 1.142816 1 80 Malton Black Butte 7.500000 1 645 Grimes Gas 0.101590 1 615 --- ----- TOTAL 3 1,340 === ===== 1 Consists of acres spaced or assignable to productive wells. 9

Undeveloped Acreage: Leasehold Interests Undeveloped Acreage: ---------------------------------------- The following table sets forth Aspen's leasehold interest in undeveloped acreage at June 30, 2004: Undeveloped Acreage ------------------- Gross Net ----- --- California: Denverton Creek 514 69 Echo 467 338 Feather River 320 64 Orion 750 150 Sacreiter 245 245 Sour Grass 1,028 224 West Grimes 2,869 586 ------- ------ TOTAL 6,193 1,676 ======= ===== Gas Delivery Commitments: Effective June 1, 2004, we entered a contract to sell 750 MMBTU of gas per day at a fixed price of $6.34 less transportation and other expenses. The contract is for the term June 1 - August 31, 2004 and contains monetary penalties for non-delivery of the gas. Subsequent to year-end, we completed the contract with no penalties realized. Drilling Commitments: We have a proposed drilling budget for the period August through December 2004. The budget includes drilling five wells in the Sacramento gas province of northern California, the acquisition of one gas well, and the completion of the Verona Pipeline. Our share of the estimated costs to complete this program is set forth in the following table: Drilling Completion & Acquisition Area Wells Costs Equipping Costs Costs Total -------------------------- -------- ------------- -------------------- --------------- ----------- Momentum Farmout 2 $ 61,000 $191,000 $252,000 Various Counties, CA West Grimes Field 2 189,000 147,000 336,000 Colusa County, CA Sour Grass Prospect 1 72,000 60,000 132,000 Tehama County, CA Lambie 3-4 1 82,500 82,500 Verona Pipeline - 70,000 70,000 -------- ------------- -------------------- --------------- ----------- Total Expenditure 6 $322,000 $468,000 $82,500 $872,500 ======== ============= ==================== =============== =========== Reserve Information - Oil and Gas Reserves: Cecil Engineering, Inc. evaluated our oil and gas reserves attributable to our properties at June 30, 2004. Reserve calculations by independent petroleum engineers involve the estimation of future net recoverable reserves of oil and gas and the timing and amount of future net revenues to be received therefrom. Those estimates are based in numerous factors, many of which are variable and uncertain. Reserve 10

estimators are required to make numerous judgments based upon professional training, experience and educational background. The extent and significance of the judgments in them are sufficient to render reserve estimates of future events, actual production determinations involve estimates inherently imprecise, since reserve revenues and operating expenses may not occur as estimated. Accordingly, it is common for the actual production and revenues later received to vary from earlier estimates. Estimates made in the first few years of production from a property are generally not as reliable as later estimates based on a longer production history. Reserve estimates based upon volumetric analysis are inherently less reliable than those based on lengthy production history. Also, potentially productive gas wells may not generate revenue immediately due to lack of pipeline connections and potential development wells may have to be abandoned due to unsuccessful completion techniques. Hence, reserve estimates may vary from year to year. Estimated Proved Reserves/ Developed and Undeveloped Reserves: The following tables set forth the estimated proved developed and proved undeveloped oil and gas reserves of Aspen for the years ended June 30, 2004 and 2003. See Note 10 to the Consolidated Financial Statements and the above discussion. Estimated Proved Reserves Proved Reserves Oil (Bbls) Gas (Mcf) --------------- ---------- --------- Estimated quantity, June 30, 2002 11,000 2,210,000 ---------- --------- Revisions of previous estimates (1,000) (184,000) Discoveries 0 481,000 Production (1,000) (248,000) Purchased reserves 0 221,000 Sold reserves (6,000) 0 ----------- --------- Estimated quantity, June 30, 2003 3,000 2,480,000 Revisions of previous estimates (1,000) (411,000) Discoveries 0 527,000 Production 0 (305,000) Purchased 0 243,000 ----------- --------- Estimated quantity, June 30, 2004 2,000 2,534,000 =========== ========= Developed and Undeveloped Reserves ---------------------------------- Developed Undeveloped Total --------- ----------- ----- Oil (Bbls) June 30, 2004 - 2,000 2,000 June 30, 2003 - 3,000 3,000 Gas (Mcf) June 30, 2004 1,236,000 1,298,000 2,534,000 June 30, 2003 655,000 1,825,000 2,480,000 For information concerning the standardized measure of discounted future net cash flows, estimated future net cash flows and present values of such cash flows attributable to our proved oil and gas reserves as well as other reserve information, see Note 10 to the Consolidated Financial Statements. Oil and Gas Reserves Reported to Other Agencies: We did not file any estimates of total proved net oil or gas reserves with, or include such information in reports to, any federal authority or agency since the beginning of the fiscal year ended June 30, 2004. Title Examinations: Oil and Gas: As is customary in the oil and gas industry, we perform only a perfunctory title examination at the time of acquisition of undeveloped properties. Prior to the commencement of drilling, in most cases, and in any event where we are the Operator, a thorough title examination is conducted and significant defects remedied before proceeding with 11

operations. We believe that the title to our properties is generally acceptable to a reasonably prudent operator in the oil and gas industry. The properties we own are subject to royalty, overriding royalty and other interests customary in the industry, liens incidental to operating agreements, current taxes and other burdens, minor encumbrances, easements and restrictions. We do not believe that any of these burdens materially detract from the value of the properties or will materially interfere with our business. We have purchased producing properties on which no updated title opinion was prepared. In such cases, we have retained third party certified petroleum landmen to review title. Office Facilities: Our principal office is located in Denver, Colorado. We also have an office located in Bakersfield, California. The Denver office consists of approximately 1,108 square feet with an additional 750 square feet of basement storage. We entered into a one-year lease agreement to December 31, 2004 for a lease rate of $1,261 per month. We also subleased from R.V. Bailey, our vice president, a portion of an office building owned by Mr. Bailey in Castle Rock, Colorado on a month-to-month basis for $500 per month. This sublease terminated on April 30, 2003 per the revised employment agreement with Mr. Bailey. See Item 10, R. V. Bailey Employment Contract. We entered an lease agreement for our Bakersfield, California office, which consists of approximately 546 square feet. The Bakersfield, California lease requires lease payments of ranging from $730 to $770 over the term of the lease which expires February 8, 2006. ITEM 3. LEGAL PROCEEDINGS -------------------------- We are not subject to any pending or, to our knowledge, threatened, legal proceedings. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ------------------------------------------------------------ No matters were presented to security holders for a vote during the year ended June 30, 2004, or any subsequent period. PART II ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS ----------------------------------------------------------------- Market Information: Our common stock is quoted on the Over-the-Counter Bulletin Board ("OTCBB") under the symbol "ASPN". The quotations reflect inter-dealer prices without retail mark-up, mark-down or commission and may not reflect actual transactions. The OTCBB adopted new rules that result in companies not current in their reporting requirements under the Securities Exchange Act of 1934 being removed from the quotation service. At June 30, 2003 and 2004, we believe that we were in full compliance with these rules. Quarter Ended Sept., 2003 Dec., 2003 March, 2004 June 30, 2004 ----------- ---------- ----------- ------------- Common Stock ("ASPN") High $.85 $.97 $.95 $1.23 Low $.56 $.55 $.58 $0.65 Quarter Ended Sept., 2002 Dec., 2002 March, 2003 June 30, 2003 ----------- ---------- ----------- ------------- Common Stock ("ASPN") High $.58 $.38 $.52 $.86 Low $.21 $.31 $.34 $.40 12

Holders: As of June 30, 2003 and 2004, there were approximately 1,182 and 1,158 holders of record of our Common Stock, respectively. This does not include an indeterminate number of persons who hold our Common Stock in brokerage accounts and otherwise in `street name.' Dividends: We have never declared or paid a cash dividend on our Common Stock. We presently intend to retain our earnings to fund development and growth of our business. Decisions concerning dividend payments in the future will depend on income and cash requirements. Holders of common stock are entitled to receive such dividends as may be declared by Aspen's Board of Directors. There were no dividends declared by the Board of Directors during the fiscal year ended June 30, 2004, or subsequently, and we have paid no cash dividends on its common stock since inception. There are no contractual restrictions on our ability to pay dividends to our shareholders. Securities authorized for issuance under equity compensation plans. The following is provided with respect to compensation plans (including individual compensation arrangements) under which equity securities are authorized for issuance as of the fiscal year ending June 30, 2004. ----------------------------------------------------------------------------------------------- Equity Compensation Plan Information (1) ----------------------------------------------------------------------------------------------- Plan Category and Number of Weighted-average Number of securities remaining Description Securities to be exercise price of available for future issuance issued upon outstanding under equity compensation exercise of options, warrants, plans (excluding securities outstanding and rights reflected in column (a)) options, warrants, and rights (a) (b) (c) --------------------- ------------------ --------------------- -------------------------------- Equity compensation plans approved by security holders -0- $-0- -0- --------------------- ------------------ --------------------- -------------------------------- Equity compensation plans not approved by security holders 484,000 $0.57 NA --------------------- ------------------ --------------------- -------------------------------- Total 484,000 $0.57 NA --------------------- ------------------ --------------------- -------------------------------- (1) This does not include options held by management and directors that were not granted as compensation. In each case, the disclosure refers to options or warrants unless otherwise specifically stated. 13

Recent Sales of Unregistered Securities -- Item 701 Disclosure. The following sets forth information regarding sales of unregistered securities during the June 30, 2004 fiscal year and subsequently as required by Item 701 of Regulation S-B. Tri-Power Resources, Inc. On June 28, 2004, Tri-Power Resources, Inc., a privately-held California corporation, purchased a $300,000 convertible debenture from Aspen Exploration Corporation. Aspen also issued to Tri-Power warrants to purchase 300,000 shares of its common stock which, if exercised before March 31, 2005, will result in the purchaser acquiring warrants to purchase an additional 300,000 shares. Shares potentially issuable to Tri-Power total 900,000. (a) The transaction was completed effective June 28, 2004. We issued the following securities to one accredited investor in exchange for the investor's payment to Aspen of $300,000: a convertible debenture with a principal amount of $300,000, bearing interest at 4% per annum and 300,000 common stock warrants exercisable as described in paragraph (c) below. (b) There was no placement agent or underwriter for the transaction and Aspen did not publicly offer any securities. (c) The total offering price was $300,000. No underwriting discounts or commissions were paid. If the holder exercises the warrant before June 30, 2005, Aspen will receive an additional $330,000 ($1.10 per share); if the holder exercises the warrant before June 30, 2006 but after June 30, 2005, Aspen will receive an additional $360,000 ($1.20 per share). If the holder exercises the warrant before March 31, 2005, the holder will receive an additional warrant exercisable to purchase 300,000 shares at $1.25 per share. In any case, the warrant (and any additional warrant) will expire unless exercised by June 30, 2006. (d) We relied on the exemption from registration provided by Sections 4(2) and 4(6) under the Securities Act of 1933 for this transaction and Regulation D. We did not engage in any public advertising or general solicitation in connection with this transaction which was in negotiation for more than several weeks. We provided the accredited investor with disclosure of all aspects of our business, including providing the accredited investor with our reports filed with the Securities and Exchange Commission, our press releases, access to our auditors, and other financial, business, and corporate information. Based on our investigation, we believe that the accredited investor obtained all information regarding Aspen it requested, received answers to all questions it (and its advisors) posed, and otherwise understood the risks of accepting our securities for investment purposes. (e) The convertible debenture convertible into common stock at the effective price of $1.00 per share (subject to dilution adjustment in the event of stock splits, stock dividends, and similar transactions, the "Conversion Price"). The convertible debenture will automatically convert into common stock at the Conversion Price if the market price for Aspen's common stock as reported by the OTC Bulletin Board remains above $1.00 per share for ten consecutive trading days. Each common stock warrant is exercisable to purchase one share of common stock through June 30, 2006. The warrants may only be exercised to the extent that there is an exemption available for the exercise at the time of exercise. If exercised before March 31, 2005, the exercise price is $1.10 per share, and the holder will receive one share of common stock and one additional warrant (exercisable through June 30, 2006 at $1.25 per share) for each warrant exercised. If exercised before June 30, 2005, the exercise price is $1.10 per share, and the holder will receive one share of common stock for each warrant exercised. 14 If exercised after June 30, 2005 but before the expiration date (June 30, 2006), the exercise price is $1.20 per share, and the holder will receive one share of common stock for each warrant exercised. Aspen has the right to redeem the common stock purchase warrants issued at any time for the payment of $0.10 per warrant provided there is an effective registration statement for the resale of the shares underlying the warrant at the time of the redemption, and provided further that the market price of Aspen's common stock has exceeded $2.50 per share for twenty of the thirty trading days preceding the date Aspen gives notice of its intention to redeem the warrants. There are no other registration rights associated with the securities issued to the accredited investor. (f) We will use the proceeds for expenses of drilling and (if warranted) completing oil and gas wells. Conversion of Convertible Debenture On July 15, 2004, Aspen gave the holder notice that the conditions for the automatic conversion of the convertible debenture had been met, and issued 300,500 shares of common stock upon such conversion. (a) The conversion was completed effective July 15, 2004. We issued the 300,500 shares of our restricted common stock to one accredited investor in conversion of and outstanding convertible debenture and accrued interest. (b) There was no placement agent or underwriter for the transaction and Aspen did not publicly offer any securities. (c) Aspen received no proceeds as a result of the conversion of the debenture. (d) We relied on the exemption from registration provided by Sections 3(a)(9), 4(2) and 4(6) under the Securities Act of 1933 for this transaction and Regulation D. We did not engage in any public advertising or general solicitation in connection with this conversion. We provided the accredited investor with disclosure of all aspects of our business, including providing the accredited investor with our reports filed with the Securities and Exchange Commission, our press releases, access to our auditors, and other financial, business, and corporate information. Based on our investigation, we believe that the accredited investor obtained all information regarding Aspen it requested, received answers to all questions it (and its advisors) posed, and otherwise understood the risks of accepting our securities for investment purposes. (e) We issued common stock to the holder upon conversion of the convertible debenture. (f) We received no proceeds from the conversion of the debenture. 15 Stock Issuances pursuant to exercise of options On May 14, 2004, three directors and one executive officer of Aspen, and one staff member, exercised common stock purchase options they held and acquired shares of Aspen's common stock as described below. In each case, the persons exercising the options paid the exercise price by returning common stock to Aspen. ----------------------- ------------- ------------- ------------ ----------- Name and Principal Date Number of Exercise Option Position Common Price paid Exercise Shares Sold ($) Price Per (#) Share ($) ----------------------- ------------- ------------- ------------ ----------- R. A. Cohan, 5/14/2004 50,000 28,500 .57 director and president, options exercised ----------------------- ------------- ------------- ------------ ----------- R. V. Bailey, 5/14/2004 50,000 28,500 .57 director and vice president, options exercised ----------------------- ------------- ------------- ------------ ----------- R. F. Sheldon, 5/14/2004 50,000 28,500 .57 director, options exercised ----------------------- ------------- ------------- ------------ ----------- J. L. Shelton, 5/14/2004 17,000 9,690 .57 office manager, options exercised ----------------------- ------------- ------------- ------------ ----------- R. K. Davis, 5/14/2004 25,000 14,250 .57 consultant, options exercised ----------------------- ------------- ------------- ------------ ----------- Total 192,000 109,440 .57 ----------------------- ------------- ------------- ------------ ----------- (a) The transactions were each effective May 14, 2004. In the aggregate, Aspen issued 192,000 shares of its common stock upon the exercise of options at a price of $0.57 per share. The option holders surrendered a total of 96,850 shares of Aspen's common stock in payment of the exercise price. (b) There was no underwriter involved in this transaction, and Aspen did not publicly offer any securities. Each of the persons who acquired shares has had prior relationships with Aspen extending over a period of many years. (c) No securities were sold for cash. Aspen accepted shares of its common stock at its market price as payment of the exercise price for the options. (d) We relied on the exemption from registration provided by Sections 3(a)(9) and 4(2) under the Securities Act of 1933 for this transaction and Regulation D. Each of the persons receiving our common stock was and remains a shareholder of Aspen, and no person paid any consideration other than the exchange of securities with Aspen. Furthermore, we did not engage in any public advertising or general solicitation in connection with this transaction which was in negotiation for more than several weeks. We provided the investors with disclosure of all aspects of our business, including providing the accredited investor with our reports filed with the Securities and Exchange Commission, our press releases, access to our auditors, and other financial, business, and corporate information. Based on our investigation, we believe that the investors obtained all information regarding Aspen it requested, received answers to all questions it (and its advisors) posed, and otherwise understood the risks of accepting our securities for investment purposes. (e) Not applicable, since the securities issued are neither convertible nor exchangeable. 16 (f) Not applicable, inasmuch as Aspen did not receive any cash from the issuance of the securities. ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION OR PLAN OF ------------------------------------------------------------------------------ OPERATION --------- The management discussion and analysis and other portions of this report contain forward-looking statements (as such term is defined in Section 21E of the Securities Exchange Act of 1934, as amended). These statements reflect our current expectations regarding our possible future results of operations, performance, and achievements. These forward-looking statements are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Wherever possible, we have tried to identify these forward-looking statements by using words such as "anticipate," "believe," "estimate," "expect," "plan," "intend," and similar expressions. These statements reflect our current beliefs and are based on information currently available to us. Accordingly, these statements are subject to certain risks, uncertainties, and contingencies, which could cause our actual results, performance, or achievements to differ materially from those expressed in, or implied by, such statements. These risks, uncertainties and contingencies include, without limitation, the factors set forth in our Form 10-KSB under "Item 6. Management's Discussion and Analysis of Financial Conditions or Plan of Operation - Factors that may affect future operating results." Overview -------- Aspen Exploration Corporation was organized in 1980 for the purpose of acquiring, exploring and developing oil and gas and other mineral properties. Since 1996, we have focused our efforts on the exploration, development and operation of natural gas properties in the Sacramento Valley of northern California. We are currently the operator of 46 gas wells and have a non-operated interest in 16 additional gas wells. We currently have offices in Bakersfield, California and Denver, Colorado and have 2 full time and one part time employees as well as the Chairman of the Board who allocates a portion of his time to the Company. We also make extensive use of consultants for the conduct of our business, ranging from financial, engineering, land, legal, and geological and geophysical specialists. We will typically review 20 to 25 prospects for every well we participate in, using 3-D seismic and well control geology to evaluate each prospect. Our goal is to identify low to moderate risk wells with good gas reserve potential. Where possible, we attempt to be the operator of each property we invest in. Our knowledge of drilling and operating wells in the Sacramento Valley allows us to maximize the potential return of each property. Administrative charges to the properties help cover approximately 37% of our selling, general and administrative expenses. Critical Accounting Policies and Estimates: We believe the following critical accounting policies affect our most significant judgments and estimates used in the preparation of our Consolidated Financial Statements. Reserve Estimates: ------------------ Our estimates of oil and natural 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 natural 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 natural 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 natural gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural 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 17 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. Many factors will affect actual future net cash flows, including: - the amount and timing of actual production; - supply and demand for natural gas; - curtailments or increases in consumption by natural gas purchasers; and - changes in governmental regulations or taxation. Property, Equipment and Depreciation: ------------------------------------- We follow the full-cost method of accounting for oil and gas properties. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, including salaries, benefits and other internal salary related costs directly attributable to these activities. Costs associated with production and general corporate activities are expensed in the period incurred. Interest costs related to unproved properties and properties under development are also capitalized to oil and gas properties. If the net investment in oil and gas properties exceeds an amount equal to the sum of (1) the standardized measure of discounted future net cash flows from proved reserves, and (2) the lower of cost or fair market value of properties in process of development and unexplored acreage, the excess is charged to expense as additional depletion. Normal dispositions of oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized. We apply SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." Under SFAS No. 144, long-lived assets and certain intangibles are reported at the lower of the carrying amount or their estimated recoverable amounts. Long-lived assets subject to the requirements of SFAS No. 144 are evaluated for possible impairment through review of undiscounted expected future cash flows. If the sum of undiscounted expected future cash flows is less than the carrying amount of the asset or if changes in facts and circumstances indicate, an impairment loss is recognized. Asset retirement obligations: ----------------------------- We recognize the future cost to plug and abandon gas wells over the estimated useful life of the wells in accordance with the provision of SFAS No. 143. SFAS No. 143 requires that we record a liability for the present value of the asset retirement obligation with a corresponding increase to the carrying value of the related long-lived asset. We amortize the amount added to the oil and gas properties and recognize accretion expense in connection with the discounted liability over the remaining lives of the respective gas wells. Our liability estimate is based on our historical experience in plugging and abandoning gas wells, estimated well lives based on engineering studies, external estimates as to the cost to plug and abandon wells in the future and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate of 6.25%. Revisions to the liability could occur due to changes in well lives, or if federal and state regulators enact new requirements on the plugging and abandonment of gas wells. Outlook and Trends ------------------ We expect our natural gas production to increase substantially during fiscal 2005 due to recent drilling successes. Total production for the year will depend on the number of wells successfully completed, the date they are put on line, their initial rate of production, and their production decline rates. We also anticipate that the average price for our product will be in the range of $4.75 to $6.25 per MMBTU for the fiscal year ended June 30, 2005. Over the past five years we have been able to replace our produced reserves and increase our yearly natural gas production. We have also benefited from a general increase in natural gas prices over the past two years, from a low of $2.78 per MMBTU average during the first quarter of fiscal 2003 to $5.97 per MMBTU for the quarter ended June 30, 2004. 18 Quantitative and Qualitative Disclosure About Risk -------------------------------------------------- Our ability to replace reserves, dissipated through production or recalculation, will depend largely on how successful our drilling and acquisition efforts will be in the future. While we cannot predict the future, our historic success ratio over the past 3 1/2 years has been 86%. With the use of 3-D seismic and well control data, interpreted by our geological and geophysical consultants, we feel we can manage our dry hole risk as well as anyone in the industry. Commodity prices are impacted by many factors that are outside of our control. Historically, commodity prices have been volatile and we expect them to remain volatile. Commodity prices are affected by changes in market demands, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas and NGL (natural gas liquids) prices, and therefore, we cannot determine what effect increases or decreases in production volumes will have on future revenues. On regulatory and operational matters, we actively manage our exploration and production activities. We value sound stewardship and strong relationships with all stakeholders in conducting our business. We attempt to stay abreast of emerging issues to effectively anticipate and manage potential impacts to our operations. To manage commercial risk, we may use financial tools to hedge the price we will receive for our product. The primary purpose of hedging is to provide adequate return on our investments, grow our reserves while leaving as much commodity price upside as possible. We are exposed to interest rate risk to the extent we have borrowed funds. During December 2003, we borrowed $225,000 from a bank for a modest acquisition. We currently pay 2% over the bank's prime rate for that facility. At June 30, 2004, the effective interest rate was 6.5%. In June 2004, we issued a convertible debenture for $300,000 with interest at 4% per annum. Liquidity and Capital Resources ------------------------------- We have historically financed our operations with internally generated funds and limited borrowings from banks and third parties, and farmout arrangements, which permit third parties (including some related parties) to participate in our drilling prospects. Our principal uses of cash are for operating expenses, the acquisition, drilling and production of prospects, the acquisition of producing properties, working capital, servicing debt and the payment of income taxes. Cash of $1,536,500 and $901,100 was provided by our operations for the twelve months ended June 30, 2004 and 2003. The cash flow from operations increase of $635,400, or 71%, was because of: Increased oil and gas sales ($1,588,250 in 2004 as compared to $1,068,800 in 2003); A $100,650 decrease in accounts receivable during 2003 (which provided cash) compared to a decrease in accounts receivable during 2004 of $288,300; and A $874,200 increase in accounts payable and accrued expenses in 2004 (which conserved cash) compared to a $261,780 increase in accounts payable and accrued expenses in 2003. Investing activities used cash to increase capitalized oil and gas costs of $1,448,100 and $1,378,400 in the twelve months ended June 30, 2004 and 2003. Cash in the current twelve month period ended June 30, 2004 was used for lease acquisition and seismic work ($886,800), intangible drilling and well workovers ($615,400), and the purchase of oil and gas well equipment ($130,000). These expenditures were offset by the sale of interests in wells to be drilled charged to third party investors. At June 30, 2004, our balance sheet also reflected short-term debt in the form of a convertible debenture in the amount of $300,000. This debt converted into common stock during July 2004 and is no longer a liability. 19

Contractual Obligations ----------------------- We had six contractual obligations as of June 30, 2004 (not including the convertible debenture that converted to common stock in July 2004 and, therefore, is no longer outstanding). The following table lists our significant liabilities at June 30, 2004: Payments Due By Period ------------------------------------------------------------------------------------------ Less than After Contractual Obligations 1 year 2-3 years 4-5 years 5 years Total ---------------------------------- --------------- -------------- -------------- --------------- --------------- Employment Obligations $210,400 $240,800 $147,400 -0- $ 598,600 Bank Loans 150,000 260,719 -0- -0- 410,719 Operating Leases 16,686 6,160 -0- -0- 22,846 --------------- -------------- -------------- --------------- --------------- Total contractual cash obligations $377,086 $507,679 $147,400 $-0- $1,032,165 =============== ============== ============== =============== =============== Future Commitments ------------------ We have a proposed drilling, completion and construction budget for the period July through December 2004. The budget includes drilling six wells in the Sacramento gas province of northern California, the acquisition of one gas well, and the completion of the Verona Pipeline. Our share of the estimated costs to complete this program over the next six months is set forth in the following table: Drilling Completion & Acquisition Area Wells Costs Equipping Costs Costs Total ------------------------------- ---------- ----------- ------------------- -------------- ----------- Momentum Farmout 2 $61,000 $191,000 $252,000 Various Counties, CA West Grimes Field 2 189,000 147,000 336,000 Colusa County, CA Sour Grass Prospect 1 72,000 60,000 132,000 Tehama County, CA Lambie 3-4 1 82,500 82,500 Verona Pipeline - 70,000 70,000 ---------- ----------- ------------------- -------------- ----------- Total Expenditure 6 $322,000 $468,000 $82,500 $872,500 ========== =========== =================== ============== =========== We maintain office space in Denver, Colorado, our principal office, and Bakersfield, California. The Denver office consists of approximately 1,108 square feet with an additional 750 square feet of basement storage. We entered into a one-year lease agreement through December 31, 2004 for a lease rate of $1,261 per month. We also subleased from R. V. Bailey, our vice president, a portion of an office building owned by Mr. Bailey in Castle Rock, Colorado on a month to month basis for $500 per month. This lease arrangement was terminated on April 30, 2003. The Bakersfield, California office has 546 square feet and a monthly rental fee of $730 to $770 over the term of the lease. The three year lease expires February 8, 2006. Rent expense for the years ended June 30, 2004 and 2003 were $24,370 and $28,536, respectively. In addition to office leases, we are responsible for various compressor rentals located on our California producing properties. These leases are on a month to month basis and total approximately $57,700 per year. Our working capital deficit (current assets less current liabilities) at June 30, 2004, was $101,086. We anticipate that our working capital and anticipated cash flow from operations and future successful drilling will be 20

sufficient to pay our current liabilities as long as our gas production continues to provide us with sufficient cash flow. As discussed below, this is dependent, in part, on maintaining or increasing our level of production and the national and world market maintaining its current prices for our gas production. Our capital requirements can fluctuate over a twelve month period because our drilling program is usually carried out in California's dry season, from late April until November, after which wet weather either precludes further activity or makes it cost prohibitive. We believe that internally generated funds will be sufficient to finance our drilling and operating expenses for the next twelve months. However, during December 2003, we borrowed $225,000 from a bank in California and used the proceeds to acquire various working interests in producing gas wells located in several counties in the Sacramento Valley, California. We also issued a convertible debenture for $300,000 in June 2004 (which converted to common stock in July 2004 and was reclassified from a current liability to equity) to finance our share of additional wells drilled in July and August of 2004 (which was converted to common stock in July 2004 and was reclassified from a current liability to equity). If our drilling efforts are successful, the anticipated increased cash flow from the new gas discoveries, in addition to our existing cash flow, should be sufficient to fund our share of any future completion and pipeline costs. 21

Results of Operations June 30, 2004 Compared to June 30, 2003 --------------------------------------- For the twelve months ended June 30, 2004, our operations continued to be focused on the production of oil and gas, and the investigation for possible acquisition of producing oil and gas properties in California. During the 2004 period, our revenues increased by more than $500,000 as compared to the comparable period of our 2003 fiscal year because of: Increased production (305,000 MMBTU sold as compared to 248,000 MMBTU sold during our 2003 fiscal year, a 23% increase); and Increased price received for our production (an average of $5.17 per MMBTU during our 2004 fiscal year as compared to $4.23 per MMBTU received during that period in 2003). The foregoing increases were offset in part by decreased management fees received ($232,430 during 2004 as compared to $245,023 during 2003). Although we were operators of more wells during 2004 (46 wells compared to 38 wells in 2003), our management fees were impacted by a lesser amount of promotional drilling costs charged to third parties in 2004. The following table sets forth certain items from our Consolidated Statements of Operations as expressed as a percentage of total revenues, shown by year for fiscal 2004, 2003 and 2002: For the Year Ended ----------------------------------------- 6/30/2004 6/30/2003 6/30/2002 ------------ -------------- ------------- Total revenues 100.0% 100.0% 100.0% Oil & gas production costs 13.3 12.1 13.5 ------------ -------------- ------------- Income from operations 86.7 87.9 86.5 ------------ -------------- ------------- Costs and expenses Depreciation and depletion 31.9 32.4 41.3 Selling, general and administrative 34.4 47.7 69.5 Interest expense .3 .0 .5 Aspen Power System - - 2.9 ------------ -------------- ------------- Total costs and expenses 66.6 80.1 114.2 ------------ -------------- ------------- Income before income taxes 20.0 7.8 (27.7) Provision for income taxes 9.0 3.2 13.2 Cumulative effect of accounting charge - .2 - ------------ -------------- ------------- Net income (loss) 11.0 4.4 (14.5) ============ ============== ============= 22

To facilitate discussion of our operating results for the years ended June 30, 2004 and 2003, we have included the following selected data from our Consolidated Statements of Operations: Comparison of the Fiscal Twelve Months Ended June 30, Increase (Decrease) -------------------------------------- ---------------------------------- 2004 2003 Amount Percentage ----------------- -------------------- ----------------- ---------------- Revenues: Oil and gas sales $1,588,250 $1,068,798 $ 519,452 48.6% Management fees 232,430 245,023 (12,593) (5.1) Interest and other 3,256 9,852 (6,596) (67.0) ----------------- -------------------- ----------------- ---------------- Total revenues 1,823,936 1,323,673 500,263 37.8 ----------------- -------------------- ----------------- ---------------- Cost and expenses: Oil and gas production 242,472 159,948 82,524 51.6 Depreciation and depletion 581,402 428,964 152,438 35.5 Selling, general and administrative 628,265 632,035 (3,770) (.6) Interest expense 6,152 - 6,152 NMF ----------------- -------------------- ----------------- ---------------- Total costs and expenses 1,458,291 1,220,947 237,344 19.4% ----------------- -------------------- ----------------- ---------------- Net operating income $ 365,645 $ 102,726 $ 262,919 255.9% ================= ==================== ================= ================ Central to the issue of success of the twelve months operations ended June 30, 2004 is the discussion of changes in oil and gas sales, volumes of natural gas sold and the price received for those sales. We present them here in tabular form: Oil & Gas MMBTU (1) Sales Sold Price/MMBTU -------------- --------------- ------------------ 2004 --------------------------- lst Quarter $ 341,926 72,600 $ 4.75 2nd Quarter 362,942 79,900 4.64 3rd Quarter 401,941 71,900 5.28 4th Quarter 481,441 80,600 5.97 -------------- --------------- ------------------ Year to date 1,588,250 305,000 5.17 -------------- --------------- ------------------ 2003 --------------------------- lst Quarter 198,431 65,800 2.78 2nd Quarter 241,700 63,700 3.76 3rd Quarter 314,222 57,900 5.47 4th Quarter 314,445 60,600 5.19 -------------- --------------- ------------------ Year to date 1,068,798 248,000 4.23 -------------- --------------- ------------------ Year to date change Amount $519,452 57,000 $.94 Percentage 48.6% 23% 22.2% (1) Price per MMBTU may not agree with oil and gas sales because of the inclusion of oil and NGL sales. Oil and gas revenue, volumes sold and price received for our product have shown a steady improvement over the past twelve months of fiscal 2004 and the twelve months of fiscal 2003. As the table above notes, revenue has increased approximately 49% when comparing the two twelve month periods ended June 30, 2004 and 2003. Volumes sold increased approximately 23%, while the price received for our product increased 22%. Total revenue increased $519,452, or 49% when comparing the two periods, while operating and production costs increased $82,500, or 52%. As set out in the previous paragraph, revenue from gas sales increased because the volumes sold from new and existing wells increased and natural gas prices increased substantially. Production costs increased due to the addition of newly productive wells. 23

A significant ratio presented is the percentage of management fees charged to operated wells versus our general and administrative costs. This coverage of general and administrative costs remained fairly constant at approximately 39% for the twelve months ended June 30, 2003 to approximately 37% at June 30, 2004. When comparing general and administrative expense for 2004 and 2003, costs declined slightly by $3,770, or .6%. Results of operations and net income (loss) before income taxes are presented in the following table: Quarterly Financial Information (unaudited) (1) Net Income Net Income (loss) Total Operating (Loss) Before Per Share 2004 Revenues Income Income Taxes Basic Diluted ------------------------ --------------- -------------- ----------------- ----------- ------------- lst Quarter $ 388,337 $ 348,739 $ 50,197 $.014 $ .014 2nd Quarter 433,317 365,761 93,022 .016 .016 3rd Quarter 440,127 354,642 76,762 .010 .010 4th Quarter 558,899 509,066 145,664 .025 .024 --------------- -------------- ----------------- ----------- ------------- Total 1,820,680 1,578,208 365,645 0.06 0.06 --------------- -------------- ----------------- ----------- ------------- 2003 ------------------------ lst Quarter 264,896 232,246 (44,238) (.008) (.007) 2nd Quarter 279,080 237,155 (15,660) (.003) (.003) 3rd Quarter 337,476 271,845 28,748 .005 .005 4th Quarter 432,369 272,421 133,876 .023 .022 --------------- -------------- ----------------- ----------- ------------- Total $ 1,313,821 $ 1,103,667 $102,726 $ .02 $ .02 --------------- -------------- ----------------- ----------- ------------- (1) Operating income is oil and gas sales plus management fees less direct operating costs. As can be seen in the table, revenues and operating income have improved significantly when comparing the twelve month periods ended June 30, 2004 and 2003. We believe this is due to the steady increase in production volumes sold in each subsequent quarter and the fact that we have enjoyed an appreciating price received for our product. Operating income has increased because production costs have increased at a lesser rate than production and prices. Our future success in the oil and gas industry will depend on the cost of finding oil or gas reserves to replace our production, the volume of our production and the prices we receive for sale of our production. These factors are subject to all of the risks associated with operations in the oil and gas industry, many of which are beyond our control. Factors that may Affect Future Operating Results ------------------------------------------------ In evaluating our business, readers of this report should carefully consider the following factors in addition to the other information presented in this report and in our other reports filed with the SEC that attempt to advise interested parties of the risks and factors that may affect our business. As noted elsewhere herein, the future conduct of Aspen's business, non-oil and gas exploration activities, and discussions of possible future activities is dependent upon a number of factors, and there can be no assurance that Aspen will be able to conduct its operations as contemplated herein. These risks include, but are not limited to: (1) The possibility that the described operations, reserves, or exploration or production activities will not be completed or continued on economic terms, if at all. (2) The exploration and development of oil and gas, and mineral properties are enterprises attendant with high risk, including the risk of fluctuating prices for oil, natural gas and other minerals being sought. (3) Imports of petroleum products from other countries. (4) Not encountering adequate resources despite expending large sums of money. (5) Test results and reserve estimates may not be accurate, notwithstanding best effort precautions. 24

(6) The possibility that the estimates on which we are relying are inaccurate and that unknown or unexpected future events may occur that will tend to reduce or increase our ability to operate successfully, if at all. (7) Our ability to participate in these projects may be dependent on the availability of adequate financing from third parties which may not be available on commercially-reasonable terms, if at all. (8) Our ability to compete with other companies (many of whom may be better financed than are we) for the purchase of properties, hiring of drilling rigs for exploration and development work, and completing wells for production. Many of these considerations are price-sensitive, and the cost will depend on many factors associated with the oil and gas industry regionally, nationally, and internationally, and over which we have no control. (9) Our stock price may be hurt by future sales of our shares or the perception that such sales may occur. As of the date of this Form 10-KSB, approximately 2,473,867 shares of Common Stock held by existing stockholders constitute "restricted shares" as defined in Rule 144 under the Securities Act. These shares may only be sold if they are registered under the Securities Act or sold under Rule 144 or another exemption from registration under the Securities Act. Sales under Rule 144 are subject to the satisfaction of certain holding periods, volume limitations, manner of sale requirements, and the availability of current public information about us. Off Balance Sheet Arrangements ------------------------------ We do not have any off balance sheet accounting arrangements except in connection with joint ventures and operating agreements for the ownership and drilling of wells. Aspen's balance sheet only reflects its own interest in these arrangements, however, and has no interest in any ownership by third parties (some of whom are related parties). 25 ITEM 7. FINANCIAL STATEMENTS The information required by this item begins on page 41 of Part III of this Report on Form 10-KSB and is incorporated into this part by reference. ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND ------------------------------------------------------------------------ FINANCIAL DISCLOSURE -------------------- Not applicable. ITEM 8A. CONTROLS AND PROCEDURES --------------------------------- (a) Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15 under the Securities Exchange Act of 1934, within the 90 days prior to the filing date of this report, we carried out an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures. This evaluation was carried out under the supervision and with the participation of our principal executive officer as well as our principal financial officer, who concluded that the Company's disclosure controls and procedures are effective. Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in our reports filed under the Exchange Act is accumulated and communicated to management, including the our principal executive officer and our principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. (b) Changes in Internal Controls. There were no changes in our internal controls or in other factors that could significantly affect these internal controls subsequent to the date of their evaluation. ITEM 8B. OTHER INFORMATION Not applicable. All required information has been reported herein. PART III ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS, --------------------------------------------------------------------- COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT ------------------------------------------------- Identification of Directors and Executive Officers: The following table sets forth the names and ages of all the Directors and Executive Officers of Aspen, and the positions held by each such person. As described below, the Board of Directors is divided into three classes which, under Delaware law, must be as nearly equal in number as possible. The members of each class are elected for three-year terms at each successive meeting of stockholders serve until their successors are duly elected and qualified; officers are appointed by, and serve at the pleasure of, the Board of Directors. We have held no annual meetings since February 25, 1994. Therefore the terms of each class of director expires at the next annual meeting of stockholders. 26 Director Name Age Position Class Since ---- --- -------- ----- ----- Robert A. Cohan 48 President, Chief Executive Officer, Chief Financial I 1998 Officer, Treasurer and Director Robert F. Sheldon 81 Director II 1981 R. V. Bailey 72 Vice President, Secretary, III 1980 and III Director Each of the directors will be up for reelection at the next annual meeting of stockholders and will continue to serve until his successor is elected and qualified or until his or her earlier death, resignation, or removal. We do not expect to hold an annual meeting during fiscal 2005. Each officer is appointed annually and serves at the discretion of the Board of Directors until his successor is duly elected and qualified. No arrangement exists between any of the above officers and directors pursuant to which any of those persons was elected to such office or position. None of the directors are also directors of other companies filing reports under the Securities Exchange Act of 1934. Robert A. Cohan. Mr. Cohan obtained a Bachelor of Science degree in Geology from the State University College at Oneonta, NY in 1979 and he works for Aspen on a full-time basis. He has approximately 25 years experience in oil and gas exploration and development, including employment in Denver, CO with Western Geophysical, H. K. van Poollen & Assoc., Inc., as a Reservoir Engineer and Geologist, Universal Oil & Gas, and as a principal of Rio Oil Co., Denver, CO. Mr. Cohan served as Manager, Oil & Gas Operations, Aspen Exploration Corporation, Denver, CO from 1989 to 1992. He was employed as Vice President, Oil & Gas Operations, for Tri-Valley Oil & Gas Co., Bakersfield, CA. from 1992 to April 1995, at which time Mr. Cohan rejoined Aspen Exploration Corporation as Vice President (now President), West Coast Division, opening an office in Bakersfield, CA. He is a member of the Society of Petroleum Engineers (SPE) and the American Association of Petroleum Geologists (AAPG). Robert F. Sheldon. Mr. Sheldon obtained a Bachelor of Science degree in Geological Engineering from the University of British Columbia in 1948. He served a total of approximately 40 years at various mining companies, with his experience covering a wide range of mineral commodities including gold, silver, copper, uranium, lead, zinc, nickel, mercury, molybdenum and tungsten. He is a member of the Professional Engineers of British Columbia, the Society of Mining Engineers, the Canadian Institute of Mining and Metallurgy, and the Yukon Chamber of Mines (where he served as an officer for four years). Mr. Sheldon joined Aspen's Board of Directors in April 1981. Mr. Sheldon is currently retired and only devotes a small portion of his time to Aspen's business. R. V. Bailey. R. V. Bailey obtained a Bachelor of Science degree in Geology from the University of Wyoming in 1956. He has approximately 42 years experience in exploration and development of mineral deposits, primarily gold, uranium, coal, and oil and gas. His experience includes basic conception and execution of mineral exploration projects. Mr. Bailey is a member of several professional societies, including the Society for Mining and Exploration, the Society of Economic Geologists and the American Association of Petroleum Geologists, and has written a number of papers concerning mineral deposits in the United States. He is the co-author of a 542-page text, published in 1977, concerning applied exploration for mineral deposits. Mr. Bailey is the founder of Aspen and has been an officer and director since its inception, but currently devotes only a small portion of his time to Aspen's business. Meetings of the Board and Committees: The Board of directors held one formal meeting during the fiscal year ended June 30, 2004. Each director attended all of the formal meetings either in person or by telephone, without exception. In addition, regular communications were maintained throughout the year among all of the officers and directors of the Company and the directors acted by unanimous consent four times during fiscal 2003 and six times subsequently through June 30, 2004. 27 No Audit Committee or Code of Ethics Aspen does not have an audit committee or other committee of the board that performs similar functions. Consequently Aspen has not designated an audit committee financial expert. Aspen's board of directors has not adopted a code of ethics because the board does not believe that, given the small size of Aspen and the limited transactions, a code of ethics is warranted. Procedures by which security holders may recommend nominees to the board of directors; communications with members of the Board of Directors The board of directors has not adopted procedures by which security holders may recommend nominees to the board of directors. Any shareholder desiring to communicate directly with any officer or director of Aspen may address correspondence to that person at our offices in Denver, Colorado. Our office staff will forward such communications to the addressee. Identification of Significant Employees: There are no significant employees who are not also directors or executive officers as described above. No arrangement exists between any of the above officers and directors pursuant to which any one of those persons was elected to such office or position. Family Relationships: As of June 30, 2004, and subsequently, there were no family relationships between any director, executive officer, or person nominated or chosen by the Company to become a director or executive officer. Involvement in Legal Proceedings: We are not subject to any pending or, to our knowledge, threatened, legal proceedings. Section 16(a) Beneficial Ownership Reporting Compliance: Section 16(a) of the Securities Exchange Act of 1934 (the "Exchange Act") requires Aspen's directors and officers and any persons who own more than ten percent of Aspen's equity securities, to file reports of ownership and changes in ownership with the Securities and Exchange Commission (the "SEC"). All directors, officers and greater than ten-percent shareholders are required by SEC regulation to furnish Aspen with copies of all Section 16(a) reports files. Based solely on our review of the copies of the reports it received from persons required to file, we believe that during the period from July 1, 1995 through September 23, 2004, all filing requirements applicable to its officers, directors and greater-than-ten-percent shareholders were complied with except as set forth in the following paragraphs. 1. Robert F. Sheldon, a director, filed one Form 4 late. The Form 4 reported a single transaction. 2. Tri-Power Resources, Inc., beneficial owner of more than 10% of our common stock, filed its Form 3 reporting one transaction (its acquisition of more than 10% of our common stock) late. Tri-Power Resources has also filed Form 4 reporting the conversion of its debenture into common stock (a report required by SEC Rule 16a-3(g)(1) even though the transaction is exempt from the application of Section 16(b)) late. 28

ITEM 10. EXECUTIVE COMPENSATION The following table sets forth information regarding compensation awarded, paid to, or earned by the chief executive officer and the other principal officers of Aspen for the three years ended June 30, 2002, 2003 and 2004. No other person who is currently an executive officer of Aspen earned salary and bonus compensation exceeding $100,000 during any of those years. This includes all compensation paid to each by Aspen and any subsidiary. ---------------------------- -------------------------------- -------------------------------------- Annual compensation Long-term Compensation Awards ------------------------------------------------------------- -------------------------- ----------- Awards Payout ------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- ----------------- (a) (b) (c) (d) (e) (f) (g) (h) (i) ------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- ----------------- Securities ($) Underlying All Other Name and Fiscal ($) ($) ($) Restricted Options & LTIP Compensation Principal Position Year Salary Bonus Other (1) Awards SARs (#) Payout (1) ------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- ----------------- R. A. Cohan 2002 123,300 0 34,850 0 0 0 200 President and CEO 2003 127,100 0 35,600 0 0 0 9,700 2004 137,100 0 54,800 0 0 0 7,300 ------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- ----------------- R. V. Bailey, 2002 122,900 0 34,850 0 0 0 11,565 Vice President 2003 111,700 0 33,250 0 0 0 23,487 and Chairman 2004 45,000 0 59,100 0 0 0 25,250 ------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- ----------------- (1) We have an "Amended Royalty and Working Interest Plan" by which we, in our discretion, are able to assign overriding royalty interests or working interests in oil and gas properties or in mineral properties. This plan is intended to provide additional compensation to Aspen's personnel involved in the acquisition, exploration and development of Aspen's oil or gas or mineral prospects. We have a medical insurance plan for our employees and those of its subsidiaries, and a life insurance plan for our chairman and vice president, R. V. Bailey. This life insurance plan included a split-dollar insurance plan for the benefit of Mr. Bailey, which is described in Note 2 to the financial statements. In June 2003 the plan was terminated. No additional compensation has been recognized as reimbursement to the vice president for income taxes for the years ended June 30, 2004, 2003 and 2002. Mr. Bailey's taxable amount was $-0- for fiscal 2004, 2003 and 2002, equal to the "economic benefit" attributed to the vice president as defined by the Internal Revenue Code. The Company paid no premiums during fiscal 2004, 2003 and 2002. We adopted a Profit-Sharing 401(k) Plan which took effect July 1, 1990. All employees are eligible to participate in this Plan immediately upon being hired to work at least 1,000 hours per year and attained age 21. Aspen's contribution (if any) to this plan is determined by the Board of Directors each year. At June 30, 2002, we contributed $-0- to the plan; during fiscal 2003 we contributed $7,388 to the plan. During fiscal 2004, we contributed $8,550 to the plan. When amounts are contributed to Mr. Bailey's and Mr. Cohan's accounts (which amounts are fully vested), these amounts are also included in column (e) of the tables, above. We have furnished a vehicle to Mr. Bailey, and the compensation allocable to this vehicle, plus amounts paid for various travel and entertainment paid on behalf of Mr. Bailey and Mr. Bailey's wife when she accompanied him for business purposes, are also included in column (i) of the table. Aspen also purchased a vehicle for Mr. Cohan. This vehicle is used substantially for business purposes; therefore, no vehicle costs were charged to Mr. Cohan. We have agreed to reimburse our officers and directors for out-of-pocket costs and expenses incurred on behalf of Aspen. 29

During fiscal 2004, we assigned to employees royalties, which accumulated during the fiscal year ended June 30, 2004, on certain wells drilled during the year. The value assigned to these overrides is considered nominal, as the assignments were made before the leases were proved. The overriding royalty interests in these California properties granted to our employees were as follows: R. V. R. A. J. L. Bailey Cohan Shelton ------ ----- ------- Anderson Farms 1 1.360000% 2.000000% 0.640000% Chickohominy 1-12 0.850000% 1.250000% 0.400000% Emigh 35-6 0.144121% 0.211943% 0.067822% Ettl 1-10 1.020000% 1.500000% 0.480000% Stock Options and Stock Appreciation Rights Granted during the Last Fiscal Year: No stock options were granted to executive officers and directors during the fiscal year ended June 30, 2004. A director and two officers exercised options to acquire 50,000 shares each of our common stock during the fiscal year ended June 30, 2004. Aggregated Option Exercises in Last Fiscal Year and Fiscal Year End Option Values: The following table sets forth information regarding the year-end value of options being held by the Chief Executive Officer and the other such named officers and persons on June 30, 2004. Number of securities underlying unexercised Value of unexercised Shares options/SARs in-the-money options/SARs acquired on Value at June 30, 2004 at June 30, 2004 Name and Principal Position exercise (#) realized Exercisable/Unexercisable Exercisable/Unexercisable --------------------------- ------------ -------- ------------------------- ------------------------- R. V. Bailey Vice President & Chairman... 50,000 $28,500 0 /100,000 $-0- Robert A. Cohan President & CEO............. 50,000 $28,500 0 /200,000 $-0- Robert F. Sheldon Director.................... 50,000 $28,500 0 /100,000 $-0- Long Term Incentive Plans/Awards in Last Fiscal Year: We do not have a long-term incentive plan nor have we made any awards during the fiscal year ended June 30, 2004. Employment contracts and termination of employment and change in control arrangements: Mr. Bailey: Effective May 1, 2003 we entered into a new employment agreement with Chairman of the Board, R. V. Bailey. Some of the pertinent provisions include an employment period ending May 1, 2009, the title of Vice President subject to the general direction of the President, Robert A. Cohan, and the Board of Directors of Aspen. Mr. Bailey's salary will be $45,000 per year from May 1, 2003 to December 31, 2006 and $60,000 per year from January 1, 2007, ending May 1, 2009. Mr. Bailey will also participate in Aspen's stock options and royalty interest programs. During the term of the agreement, we have agreed to pay Mr. Bailey a monthly $1,700 allowance to cover such items as prescriptions, medical and dental coverage for himself and his dependents and other expenses not covered in the agreement. Mr. Bailey's keyman life insurance policy terminated in August of 2003 and will result in an annual savings of approximately $6,500. The stock purchase agreement with Mr. Bailey was cancelled and replaced by his current employment agreement. The agreement had provided that we apply 75% of the $1,000,000 keyman life insurance to purchase up to 75% of the common shares owned by him at the time of his death. Mr. Bailey will continue to use the Company vehicle and may trade the current vehicle for a similar vehicle of his choice prior to June 30, 2006. During 2007 or thereafter, Mr. Bailey may purchase the vehicle for $500. 30

We may terminate this agreement upon Mr. Bailey's death by paying his estate all compensation that had or will accrue to the end of the year of his death plus $75,000. Should Mr. Bailey become totally and permanently disabled, we will pay Mr. Bailey one half of the salary and benefits set forth in our agreement with him for the remainder of the term of the agreement. Mr. Cohan: On April 16, 1998, we entered into an employment agreement with Robert A. Cohan, which provides for the payment of $90,000 for the first year of employment, plus reimbursement of expenses, including health insurance. We have renewed the agreement effective April 15, 1999 to April 15, 2002 at the rate of $95,000 per year for the year commencing April 15, 1999, $100,000 for the year commencing April 15, 2000 and $105,000 for the year commencing April 15, 2001. On August 1, 2001 Mr. Cohan's salary was increased to $125,000 per year. Mr. Cohan's employment agreement expired by its own terms on April 15, 2002 and was replaced by an employment agreement dated January 1, 2003. Some of the pertinent provisions include an employment period ending December 31, 2005, salary increases from $125,000 per year to $135,000 per year effective April 15, 2003, and a further salary increase to $145,000 per year from April 15, 2004 through the end of the contract. Other benefits and duties will remain the same as the previous employment contract. Prior to February 2000, we and Mr. Cohan agreed to utilize a portion of Mr. Cohan's home in Bakersfield, California from which to conduct Aspen's business. Mr. Cohan did not charge Aspen any rent for the use of his home as a business office. Aspen agreed to pay for all office supplies, communication and copy equipment used by Mr. Cohan in his office, as well as the monthly telephone expense incurred by Mr. Cohan on behalf of Aspen. On February 7, 2000, we entered into a three-year lease of office space in Bakersfield, California thereby alleviating the necessity of home office reimbursement to Mr. Cohan. Effective May 1, 2003 our Board of Directors appointed Mr. Robert A. Cohan President of Aspen Exploration Corporation, replacing Mr. Bailey. During fiscal 2002 we entered into a rental agreement with R. V. Bailey to rent office space in Castle Rock, Colorado in an office building owned by Mr. Bailey. The rental amount was $6,000 per year on a month to month basis. This agreement was terminated effective May 1, 2003. See also Item 12, Certain Relationships and Related Party Transactions. Report on Repricing of Options/SARs We did not reprice any options or stock appreciation rights during the fiscal year ended June 30, 2004, or subsequently. ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. ------------------------------------------------------------------------- The following table sets forth as of September 23, 2004 the number and percentage of Aspen's shares of $.005 par value common stock owned of record and beneficially owned by each person owning more than five percent of such common stock, and by each Director, and by all Officers and Directors as a group. Beneficial Ownership Percent Beneficial Owner Number of Shares of Total ---------------- ---------------- -------- R. V. Bailey 1,319,182i 22.14% Robert A. Cohan 742,377ii 12.46% Robert F. Sheldon 259,562iii 4.36% All Officers and Directors as a Group 2,321,121 38.95% (3 persons) 31 The address for all of the above directors and executive officers is: 2050 S. Oneida St., Suite 208, Denver, CO 80224 Tri-Power Resources, Inc. 900,500iv 13.7% P.O. Box 849 Ardmore, OK 73402 (i) This number includes 1,146,083 shares of stock held of record in the name of R. V. Bailey and 16,320 shares of record in the name of Mieko Nakamura Bailey, his wife. In addition, the number of shares owned includes 100,000 shares of common stock granted in a property exchange; stock options to purchase 150,000 shares of restricted common stock, which includes 50,000 shares of restricted common stock that were exercised on May 14, 2004; and 200,000 shares of restricted common stock that were exercised on June 11, 2001. Additionally, Aspen issued 32,000 shares of common stock to the Aspen Exploration Profit Sharing Plan for the benefit of R. V. Bailey as a corporation contribution to Mr. Bailey's 401(k) account. (ii) This number includes 300,000 shares of common stock granted; stock options to purchase 250,000 shares of restricted common stock, which includes 50,000 shares of restricted common stock that were exercised on May 14, 2004 and 50,000 shares of restricted common stock that were exercised on August 16, 2004; and stock options to purchase 200,000 shares of restricted common stock that were exercised on February 27, 2001. Additionally, Aspen issued 30,733 shares of common stock to the Aspen Exploration Profit Sharing Plan for the benefit of Robert A. Cohan as a corporation contribution to Mr. Cohan's 401(k) account. (iii) This number includes 20,000 shares of common stock granted December 13, 1996, 20,000 shares of common stock granted November 1, 1997; stock options to purchase 150,000 shares of restricted common stock, which includes 50,000 shares of restricted common stock that were exercised on May 14, 2004; and stock options granted for 80,000 shares of common stock that were exercised on December 17, 2001. (iv) This includes warrants to purchase 300,000 shares of our common stock with an exercise price of $1.10 per share through June 30, 2006 ($1.20 per share if exercised after June 30, 2005). If the holder exercises the warrant before March 31, 2005, the holder will receive an additional warrant exercisable to purchase 300,000 shares at $1.25 per share (also through June 30, 2006), which is also included in the foregoing calculation. Except with respect to the employment agreement between Aspen and R. V. Bailey and between Aspen and Robert Cohan, we know of no arrangement, the operation of which may, at a subsequent date, result in change in control of Aspen. See Item 5, above, for information regarding securities authorized for issuance under equity compensation plans in the form required by Item 201(d) of Regulation S-B. ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS -------------------------------------------------------- The following sets out information regarding transactions between officers, directors and significant shareholders of Aspen during the most recent two fiscal years and during the subsequent fiscal year. Working Interest Participation: Some of the directors and officers of Aspen are engaged in various aspects of oil and gas and mineral exploration and development for their own account. Aspen has no policy prohibiting, nor does its Certificate of Incorporation prohibit, transactions between Aspen and its officers and directors. We plan to enter into cost-sharing arrangements with respect to the drilling of its oil and gas properties. Directors and officers may participate, from time to time, in these arrangements and such transactions may be on a non-promoted basis (actual costs), although they have participated mainly on a promoted basis, but must be approved by a majority of the disinterested directors of our Board of Directors. R. V. Bailey, vice president and director of Aspen, Robert A. Cohan, president and director of Aspen, and Ray K. Davis, consultant to Aspen, each have working and royalty interests in certain of the California oil and gas properties operated by Aspen. The affiliates paid for their proportionate share 32 of all costs to acquire, develop and operate these properties. As of June 30, 2004, working interests of the Company and its affiliates in certain producing California properties are set forth below: GROSS WELLS NET WELLS GAS GAS --- --- Aspen Exploration 58 11.11 R. V. Bailey 39 1.04 R. A. Cohan 39 .66 R. K. Davis 46 .87 J. L. Shelton 28 .07 Amended Royalty and Working Interest Plan: The allocations for royalty under Aspen's "Royalty and Working Interest Plan" for employees are based on a determination of whether there is any "room" for royalties in a particular transaction. In some specific cases an oil or gas property or project is sufficiently burdened with existing royalties so that no additional royalty burden can be allocated to our employees for that property or project. In other situations a determination may be made that there are royalty interests available for assignment to our employees. The determination of whether royalty interests are available and how much to assign to employees (usually less than 3%) is made on a case by case basis by Robert A. Cohan, president, and R. V. Bailey, vice president, both of whom may benefit from royalty interests assigned. During fiscal 2002, assignments to Mr. Cohan and Mr. Bailey have been on an equal basis, while Ms. Judy Shelton, the corporate office manager, was assigned a lesser amount. For fiscal 2003 Mr. Bailey and Ms. Shelton shared a proportionately lesser amount. A discussion of specific royalties assigned is included in Item 10 "Executive Compensation" above. Aspen Power Systems, LLC: When we operated Aspen Power Systems, LLC, certain affiliates also became members. This business has not been operating for more than the past two years, and there are no plans to recommence its operations. Employment Agreements See Item 10, Executive Compensation -- Employment contracts and termination of employment and change in control arrangements, for a discussion of the current employment contracts between Aspen and Messrs. Cohan and Bailey. As part of our employment agreement with our former president (Mr. Bailey, currently vice president), in 1991 we purchased a split dollar life insurance policy for his benefit. We paid total premiums of $360,000 on his behalf, of which a portion (the "split") constituted compensation to him. At each anniversary we paid Mr. Bailey an amount as a bonus to reimburse him for personal income tax on his split. No additional compensation has been recognized as reimbursement to him for income taxes for the years ended June 30, 2004 and 2003. We paid no premiums during fiscal 2004 and 2003. In June 2003, the plan was terminated and we received a payment of $239,095, the accumulated corporate premium payments due us. We have fulfilled our obligations under this plan and no further action is required of us. Other Arrangements: During the fiscal years 2004 and 2003, Aspen paid for various hospitality functions and for travel, lodging and hospitality expenses for spouses who occasionally accompanied directors when they were traveling on company business. Our president has also supplied Aspen with certain promotional items. The net effect of these items has been a cost to Aspen of less than $5,000 for the fiscal years ended June 30, 2004 and 2003, respectively. Management believes that the expenditures were to Aspen's benefit. During the years ended June 30, 2004 and 2003, Aspen provided one vehicle each to Aspen's president and vice president. We also have entered into a Stock Purchase Agreement, which also expired, with our vice president, as discussed in "Item 10 - Employee Compensation" and "Item 11 - Security Ownership." 33 We subleased a portion of our vice president's office in a building owned by him in Castle Rock, Colorado on a month to month basis for a monthly fee of $500. This sublease terminated on April 30, 2003 per the revised employment agreement with Mr. Bailey. See Item 10, R. V. Bailey Employment Contract. Certain Business Relationships: None. (1)-(5) Indebtedness of Management: None. Transactions with Promoters: Not applicable. 34 ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K. Exhibits Pursuant to Item 601 of Regulation S-B: Exhibit No. Title ----------- ----------------------------------------------------------- 3.01 Certificate of Incorporation (1) 3.02 Registrant's Bylaws. (1) 3.03 Bylaws - Subsidiary (1) 3.20 Registrant's Amended and Restated Bylaws(10) 4.01 Specimen Common Stock Certificate. (1) 10.01 Royalty and Working Interest Plan (1) 10.02 Employment Agreement between Aspen Exploration Corporation and Robert A. Cohan dated January 1, 2003 (10) 10.03* Employment Agreement between Aspen Exploration Corporation and R.V. Bailey dated May 1, 2003, as amended 10.08 Stock Purchase Agreement between Aspen Exploration Corporation and R.V. Bailey dated January, 1983 (7) 10.13 Split-Dollar Life Insurance Plan for R.V. Bailey (8) 10.15 Stock Purchase Agreement between Aspen Exploration Corporation and R.V. Bailey dated June, 1993 (9) 22.1 Subsidiaries of Aspen Exploration Corporation Aspen Gold Mining Company, a Colorado corporation Aspen Power Systems, LLC, a Colorado limited liability company 31* Certification pursuant to Rule 13a-14 32* Certification pursuant to 18 U.S.C.ss.1350 * Filed herewith. 1 Incorporated by reference from Commission File No. 2-69324. 7 Incorporated by reference from Annual Report on Form 10-K dated June 30, 1991 (filed on September 27, 1991). 8 Incorporated by reference from Annual Report on Form 10-K dated June 30, 1992 (filed on October 3, 1992). 9 Incorporated by reference from Annual Report on Form 10-KSB dated June 30, 1993 (filed on September 27, 1993). 10 Incorporated by reference from Annual Report on form 10-KSB dated June 30, 2003 (filed on September 22, 2003). ITEM 14. PRINCIPAL ACCOUNTANT'S FEES AND SERVICES. --------------------------------------------------- (a) Audit Fees. Our principal accountant, Gordon Hughes & Banks LLP, billed us aggregate fees in the amount of approximately $23,000 for the fiscal year ended June 30, 2004 and approximately $21,500 for the fiscal year ended June 30, 2003. These amounts were billed for professional services that Gordon Hughes & Banks LLP provided for the audit of our annual financial statements, review of the financial statements included in our report on 10-QSB and other services typically provided by an accountant in connection with statutory and regulatory filings or engagements for those fiscal years. (b) Audit-Related Fees. Gordon Hughes & Banks LLP billed us aggregate fees in the amount of $18,300 and $16,900 for the fiscal years ended June 30, 2004 and 2003 for assurance and related services that were reasonably related to the performance of the audit or review of our financial statements. 35 (c) Tax Fees Gordon Hughes & Banks LLP billed us aggregate fees in the amount of approximately $4,750 for the fiscal year ended June 30, 2004 and approximately $4,600 for the fiscal year ended June 30, 2003, for tax compliance, tax advice, and tax planning. (d) All Other Fees Gordon Hughes & Banks LLP billed us aggregate fees in the amount of $-0- for the fiscal years ended June 30, 2004 and 2003 for other fees. (e) Audit Committee's Pre-Approval Practice Inasmuch as Aspen does not have an audit committee, Aspen's board of directors performs the functions of its audit committee. Section 10A(i) of the Securities Exchange Act of 1934 prohibits our auditors from performing audit services for us as well as any services not considered to be "audit services" unless such services are pre-approved by the board of directors (in lieu of the audit committee) or unless the services meet certain de minimis standards. The board of directors has adopted resolutions that provide that the board must: Preapprove all audit services that the auditor may provide to us or any subsidiary (including, without limitation, providing comfort letters in connection with securities underwritings or statutory audits) as required by ss.10A(i)(1)(A) of the Securities Exchange Act of 1934 (as amended by the Sarbanes-Oxley Act of 2002). Preapprove all non-audit services (other than certain de minimis services described in ss.10A(i)(1)(B) of the Securities Exchange Act of 1934 (as amended by the Sarbanes-Oxley Act of 2002) that the auditors propose to provide to us or any of its subsidiaries. The board of directors considers at each of its meetings whether to approve any audit services or non-audit services. In some cases, management may present the request; in other cases, the auditors may present the request. The board of directors has approved Gordon Hughes & Banks LLP performing our audit for the 2004 and 2003 fiscal years, as well as tax services for the 2003 and 2004 fiscal years. The percentage of the fees for audit, audit-related, tax and other services were as set forth in the following table: ------------------- ------------------------------------- Percentage of total fees paid to Gordon Hughes & Banks LLP ------------------- ------------------------------------- Fiscal Year 2004 Fiscal Year 2003 ------------------- ---------------- ---------------- Audit fees 67% 70% ------------------- ---------------- ---------------- Audit-related fees 14% 8% ------------------- ---------------- ---------------- Tax fees 19% 22% ------------------- ---------------- ---------------- All other fees 0% 0% ------------------- ---------------- ---------------- 36 SIGNATURES In accordance with Section 13 or 15(d) of the Exchange Act, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. September 23, 2004 ASPEN EXPLORATION CORPORATION, a Delaware Corporation By: /s/ Robert A. Cohan ------------------------------------- Robert A. Cohan President, Chief Executive Officer, and Chief Financial Officer Pursuant to the requirement of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated: Date Name and Title Signature September 23, 2004 Robert A. Cohan /s/ Robert A. Cohan Principal Executive Officer, ---------------------- Principal Financial Officer Director September 23, 2004 R. V. Bailey /s/ R. V. Bailey Chairman of the Board ---------------------- Director September 23, 2004 Robert F. Sheldon /s/ Robert F. Sheldon Director ---------------------- 37 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Page Report of Independent Auditors ............................................40 Financial Statements as of June 30, 2004 and June 30, 2003: Consolidated Balance Sheets................................................41-42 Consolidated Statements of Operations......................................43 Consolidated Statement of Stockholders' Equity.............................44 Consolidated Statements of Cash Flows......................................45 Notes to Consolidated Financial Statements.................................46-67 39 INDEPENDENT AUDITORS' REPORT Board of Directors Aspen Exploration Corporation and Subsidiary Denver, Colorado We have audited the consolidated balance sheets of Aspen Exploration Corporation and Subsidiary as of June 30, 2004 and 2003 and the related consolidated statements of operations, stockholders' equity, and cash flows for the years ended June 30, 2004 and 2003. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits 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 consolidated financial position of Aspen Exploration Corporation and Subsidiary as of June 30, 2004 and 2003, and the results of their consolidated operations and cash flows for the years ended June 30, 2004 and 2003 in conformity with accounting principles generally accepted in the United States of America. /s/ GORDON, HUGHES & BANKS, LLP --------------------------------- GORDON, HUGHES & BANKS, LLP Greenwood Village, Colorado August 13, 2004 40

Item 7. Financial Statements and Supplementary Data ------- ------------------------------------------- ASPEN EXPLORATION CORPORATION AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS ASSETS June 30, 2004 2003 ----------- ----------- Current Assets: Cash and cash equivalents, including $1,127,874 and $516,365 of invested cash in 2004 & 2003, respectively (Note 1) ................................................ $ 1,329,376 $ 776,566 Precious metals (Note 1) .................................. 18,823 18,823 Accounts & trade receivables .............................. 556,558 269,259 Accounts receivable - related party (Notes 1 and 7) ....... 12,742 6,302 Prepaid expenses .......................................... 16,737 22,181 ----------- ----------- Total current assets ...................................... 1,934,236 1,093,131 ----------- ----------- Investment in oil & gas properties, at cost (full cost method of accounting) (Note 9) ................................. 8,216,136 6,723,579 Less accumulated depletion and valuation allowance ...... (3,235,171) (2,674,469) ----------- ----------- 4,980,965 4,049,110 ----------- ----------- Property and equipment, at cost: Furniture, fixtures & vehicles ............................ 112,562 112,562 Less accumulated depreciation ........................... ( 81,958) ( 64,178) ----------- ----------- 30,604 48,384 ----------- ----------- Total assets ................................................ $ 6,945,805 $ 5,190,625 =========== =========== (Statement Continues) See Summary of Accounting Policies and Notes to Consolidated Financial Statements 41

Item 7. Financial Statements and Supplementary Data ------- ------------------------------------------- ASPEN EXPLORATION CORPORATION AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS (Continued) LIABILITIES AND STOCKHOLDERS' EQUITY June 30, 2004 2003 ----------- ----------- Current liabilities: Accounts payable and accrued expenses ........... $ 932,814 $ 581,895 Accounts payable - related party (Note 7) ....... 70,774 17,685 Advances from joint interest owners ............. 621,015 150,821 Notes payable - current (Note 6), net of discount 410,719 -0- ----------- ----------- Total current liabilities ....................... 2,035,322 750,401 ----------- ----------- Asset retirement obligation (Note 15) ........... 79,582 17,841 Deferred income taxes (Note 5) .................. 296,320 131,350 ----------- ----------- Total long term liabilities ..................... 375,902 149,191 ----------- ----------- Total liabilities ............................. 2,411,224 899,592 ----------- ----------- Stockholders' equity: (Notes 1 and 4): Common stock, $.005 par value: Authorized: 50,000,000 shares Issued and outstanding: At June 30, 2004, 5,958,979 shares and June 30, 2003, 5,863,828 shares ........................................ 29,796 29,320 Capital in excess of par value .................. 6,064,602 6,025,797 Accumulated deficit ............................ (1,556,225) (1,756,900) Deferred compensation ........................... (3,592) (7,184) ----------- ----------- Total stockholders' equity ...................... 4,534,581 4,291,033 ----------- ----------- Total liabilities and stockholders' equity ...... $ 6,945,805 $ 5,190,625 =========== =========== See Summary of Accounting Policies and Notes to Consolidated Financial Statements 42

Item 7. Financial Statements and Supplementary Data ------- ------------------------------------------- ASPEN EXPLORATION CORPORATION AND SUBSIDIARY CONSOLIDATED STATEMENTS OF OPERATIONS Year ended June 30, ------------------- 2004 2003 ----------- ----------- Revenues: Oil and gas (Note 9) ...................................... $ 1,588,250 $ 1,068,798 Management fees (Note 9) .................................. 232,430 245,023 Interest and other income ................................. 3,256 9,852 ----------- ----------- Total revenues .............................................. 1,823,936 1,323,673 ----------- ----------- Costs and expenses: Oil and gas production .................................... 242,472 159,948 Depreciation, depletion and amortization .................. 581,402 428,964 Interest expense .......................................... 6,152 -0- Selling, general and administrative ....................... 628,265 632,035 ----------- ----------- Total costs and expenses .................................... 1,458,291 1,220,947 ----------- ----------- Operating income ............................................ 365,645 102,726 Provision for income taxes .................................. (164,970) (42,100) ----------- ----------- Income before cumulative effect of change in accounting principle .................................................. 200,675 60,626 ----------- ----------- Cumulative effect of change in accounting principle, net of income taxes ............................................... -0- (2,849) ----------- ----------- Net income .................................................. $ 200,675 $ 57,777 =========== =========== Basic earnings per common share Income before cumulative effect of change in accounting principle ...................................... $ .03 $ .01 Cumulative effect of change in accounting principle, net of income taxes ............................................ -- -- ----------- ----------- Net income ................................................ $ .03 $ .01 =========== =========== Diluted earnings per common share Income before cumulative effect of change in accounting principle ...................................... $ .03 $ .01 Cumulative effect of change in accounting principle, net of income taxes ............................................. -- -- ----------- ----------- Net income ................................................ $ .03 $ .01 =========== =========== Basic weighted average number of common shares outstanding .............................................. 5,876,081 5,863,828 =========== =========== Diluted weighted average number of common shares outstanding .............................................. 6,686,932 6,083,528 =========== =========== See Summary of Accounting Policies and Notes to Consolidated Financial Statements 43

Item 7. Financial Statements and Supplementary Data ------- ------------------------------------------- ASPEN EXPLORATION CORPORATION AND SUBSIDIARY CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY Common Stock (par $.005) ----------------------- Accumulated Deferred Total Shares Par Value APIC Deficit Compensation Equity ----------- ----------- ----------- ----------- ----------- ----------- Balance, June 30, 2002 5,863,828 $ 29,320 $ 6,025,797 $(1,814,677) $ (14,152) $ 4,226,288 Amortization of deferred compensation -- -- -- -- 6,968 6,968 Net income -- -- -- 57,777 -- 57,777 ---------------------------------------------------------------------------------- Balance, June 30, 2003 5,863,828 $ 29,320 $ 6,025,797 $(1,756,900) $ (7,184) $ 4,291,033 Options exercised by directors and officers 74,337 $ 372 $ (372) -- -- -- Options exercised by consultant 12,389 62 (62) -- -- -- Options exercised by employee 8,425 42 (42) -- -- -- Amortization of deferred compensation -- -- -- -- 3,592 3,592 Warrants issued and debt discounted -- -- 39,281 -- -- 39,281 Net income -- -- -- 200,675 -- 200,675 ---------------------------------------------------------------------------------- Balance, June 30, 2004 5,958,979 $ 29,796 $ 6,064,602 $(1,556,225) $ (3,592) $4,534,581 ================================================================================== See Summary of Accounting Policies and Notes to Consolidated Financial Statements 44

Item 7. Financial Statements and Supplementary Data ------- ------------------------------------------- ASPEN EXPLORATION CORPORATION AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended June 30, 2004 2003 ---- ---- Cash flows from operating activities: ------------------------------------- Net income ..................................................... $ 200,675 $ 57,777 Adjustments to reconcile net income to net cash provided by operating activities: Amortization of deferred compensation ..................... 3,592 6,968 Depreciation, depletion, and amortization ................. 581,402 431,813 Deferred income tax provision ............................. 164,970 42,100 Changes in assets and liabilities: Decrease (increase) in receivable and prepaid expenses .... (288,295) 100,655 Increase in accounts payable, accrued expenses and advances from joint owners ....................................... 874,202 261,779 ----------- ----------- Net cash provided by operating activities ........................ 1,536,546 901,092 Cash flows from investing activities: ------------------------------------- Additions to oil and gas properties ............................ (1,026,531) (1,378,356) Producing oil and gas properties purchased ..................... (421,583) -0- Sale of oil and gas equipment .................................. 14,378 28,865 Sale of oil and gas properties ................................. -0- 69,869 ----------- ----------- Net cash (used) by investing activities .......................... (1,433,736) (1,279,622) Cash flows from financing activities: ------------------------------------- Proceeds from split dollar life insurance ...................... -0- 239,095 Proceeds from notes payable .................................... 525,000 -0- Payment of notes payable ....................................... (75,000) -0- ----------- ----------- Net cash provided by financing activities ........................ 450,000 239,095 ----------- ----------- Net increase (decrease) in cash and cash equivalents ............. 552,810 (139,435) Cash and cash equivalents, beginning of year ..................... 776,566 916,001 ----------- ----------- Cash and cash equivalents, end of year ........................... $ 1,329,376 $ 776,566 =========== =========== Other information: Interest paid .................................................... $ 6,152 $ -0- =========== =========== Income taxes paid ................................................ $ 800 $ -0- =========== =========== Non-cash investing and financing activities: Asset retirement obligation .................................... $ (66,454) $ (16,223) =========== ============ See Summary of Accounting Policies and Notes to Consolidated Financial Statements 45

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Nature of Business ------------------ We were incorporated under the laws of the State of Delaware on February 28, 1980 for the primary purpose of acquiring, exploring and developing oil and gas and other mineral properties. Our principal executive offices are located at 2050 S. Oneida St., Suite 208, Denver, Colorado 80224. Our telephone number is (303) 639-9860, and our facsimile number is 303-639-9863. We are currently engaged primarily in the exploration and development of oil and gas properties in California, although we have a significant amount of geologic data regarding uranium prospects in Wyoming and precious mineral prospects in Alaska. Oil and Gas Exploration and Development. Our major emphasis has been our participation in the oil and gas segment acquiring interests in producing oil or gas properties and participating in drilling operations. We engage in a broad range of activities associated with the oil and gas business in an effort to develop oil and gas reserves. With the assistance of our management, independent contractors retained from time to time by Aspen, and, to a lesser extent, unsolicited submissions, we have identified and will continue to identify prospects that we believe are suitable for drilling and acquisition. Currently, our primary area of interest is in the state of California. We have acquired a number of interests in oil and gas properties in California, as described below in more detail. In addition, we also act as operator for a number of our producing wells and receive management fee revenues for these services. A summary of our Company's significant accounting policies follows: Consolidated Financial Statements -------------------------------- The consolidated financial statements include our Company and its wholly-owned subsidiary, Aspen Gold Mining Company. Significant intercompany accounts and transactions, if any, have been eliminated. The subsidiary is currently inactive. Statement of Cash Flows ----------------------- For statement of cash flows purposes, we consider short-term investments with original maturities of three months or less to be cash equivalents. Cash restricted from use in operations beyond three months is not considered a cash equivalent. Management's Use of Estimates ----------------------------- Accounting principles generally accepted in the United States of America require us to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent liabilities at the date of the financial statements and reported amounts of revenues and expenses. Actual results could differ from those estimates. The mining and oil and gas industries are subject, by their nature, to environmental hazards and cleanup costs for which we carry catastrophe insurance. At this time, we know of no substantial costs from environmental accidents or events for which we may be currently liable. In addition, our oil and gas business makes it vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future. By definition, proved reserves are based on current oil and gas prices and estimated reserves. Price declines reduce the estimated quantity of proved reserves and increase annual depletion expense (which is based on proved reserves). 46 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Investment in Unconsolidated Companies -------------------------------------- The equity method of accounting is used for all investments in which our interest is 20% or more. Under the equity method, we record our share of the investee's net income or (loss) as an increase or (decrease) of its investment less its share of dividends or distributions from the investee. Investments in business entities in which we own less than 20% of the company are recorded using the cost basis of the investment. Under the cost method, our share of net income or loss is not recorded. Our share of the investee's dividends or distributions is recorded as income on the accrual basis. Impairment of Long-lived Assets ------------------------------- Long-lived assets and identifiable intangibles are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the expected undiscounted future cash flow from the use of the assets and their eventual disposition is less than the carrying amount of the assets, an impairment loss is recognized and measured using the asset's fair value or discounted cash flows. Financial Instruments --------------------- The carrying value of current assets and liabilities reasonably approximates their fair value due to their short maturity periods. The carrying value of our debt obligations reasonably approximates their fair value as the stated interest rate approximates current market interest rates of debt with similar terms. Precious Metals and Revenues ---------------------------- Precious metals inventories are valued at the lower of cost (specific identification method) or market. There is no allowance for unrealized losses against inventories due to market decline. There were no sales of gold from inventory for the years ended June 30, 2004 and 2003. Oil and Gas Properties ---------------------- We follow the "full-cost" method of accounting for our oil and gas properties. Under this method, all costs associated with property acquisition, exploration and development activities, including internal costs that can be directly identified with those activities, are capitalized within one cost center. No gains or losses are recognized on the receipt of prospect fees or on the sale or abandonment of oil and gas properties, unless the disposition of significant reserves is involved. Depletion and amortization of our full-cost pool is computed using the units-of-production method based on proved reserves as determined annually by us and independent engineers. An additional depletion provision in the form of a valuation allowance is made if the costs incurred on our oil and gas properties, or revisions in reserve estimates, cause the total capitalized costs of our oil and gas properties in the cost center to exceed the capitalization ceiling. The capitalization ceiling is the sum of (1) the present value of our future net revenues from estimated production of proved oil and gas reserves applicable to the cost center plus (2) the lower of cost or estimated fair value of our cost center's unproved properties less (3) applicable income tax effects. The valuation allowance was $281,719 at June 30, 2004 and 2003 (Note 9). Depletion and amortization expense was $560,701 and $410,596 for the years ended June 30, 2004 and 2003, respectively. 47

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Property and Equipment ---------------------- Depreciation and amortization of our property and equipment are expensed in amounts sufficient to relate the expiring costs of depreciable assets to operations over estimated service lives, principally using the straight-line method. Estimated service lives range from three to eight years. When assets are sold or otherwise disposed of, the cost and accumulated depreciation are removed from the accounts and any resulting gain or loss is reflected in operations in the period realized. Depreciation expense was $17,780 and $18,368 for the years ended June 30, 2004 and 2003, respectively. Deferred Compensation Costs --------------------------- We record the fair value of stock bonuses to employees and consultants as an expense and an increase to paid-in capital in the year of grant unless the bonus vests over future years. Bonuses that vest are deferred and expensed ratably over the vesting period. During the fiscal year ended June 30, 2004 and 2003, we expensed $3,592 and $6,968, respectively, in stock bonuses. Allowance for Bad Debts ----------------------- We consider accounts receivable to be fully collectible as recorded as of June 30, 2004 and 2003; accordingly, no allowance for doubtful accounts is required. Revenue Recognition ------------------- Sales of oil and gas production are recognized at the time of delivery of the product to the purchaser. Management fees from outside parties are recognized at the time the services are rendered. Earnings Per Share ------------------ We follow Statement of Financial Accounting Standards ("SFAS") No. 128, addressing earnings per share. SFAS No. 128 established the methodology of calculating basic earnings per share and diluted earnings per share. The calculations differ by adding any instruments convertible to common stock (such as stock options, warrants, and convertible preferred stock) to weighted average shares outstanding when computing diluted earnings per share. The following is a reconciliation of the numerators and denominators used in the calculations of basic and diluted earnings per share. 2004 2003 ------------------------- ------------------------ Per Per Net Share Net Share Income Shares Amount Income Shares Amount ------ ------ ------ ------ ------ ------ Basic earnings per share: Net income and share amounts $200,675 5,876,081 $ .03 $57,777 5,863,828 $ .01 Dilutive securities stock options 484,000 776,000 Convertible debt and warrants 600,000 -- Repurchased shares (273,149) (556,300) -------------------------------------------------------------- Diluted earnings per share: Net income and assumed share conversion $200,675 6,686,932 $.03 $57,777 6,083,528 $.01 ======== ========= ==== ======= ========= ===== 48

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Segment Reporting ----------------- We follow SFAS No. 131, "Disclosure about Segments of an Enterprise and Related Information", which amended the requirements for a public enterprise to report financial and descriptive information about its reportable operating segments. Operating segments, as defined in the pronouncement, are components of an enterprise about which separate financial information is available that is evaluated regularly by us in deciding how to allocate resources and in assessing performance. The financial information is required to be reported on the basis that is used internally for evaluating segment performance and deciding how to allocate resources to segments. Income Taxes ------------ We account for income taxes under SFAS No. 109, "Accounting for Income Taxes". Temporary differences are differences between the tax basis of assets and liabilities and their reported amounts in the financial statements that will result in taxable or deductible amounts in future years. Stock Award and Stock Option Plans ---------------------------------- We grant common stock and stock options to employees and non-employees and apply Accounting Principles Board (APB) Opinion No. 25 (APB 25), "Accounting for Stock Issued to Employees", and related Interpretations in accounting for all stock award and stock option plans for employees and directors. Following the guidance of APB 25, compensation cost has been recognized for stock options issued to employees and directors as the excess of the market price of the underlying common stock on the date of the grant over the exercise price of the Company's stock options on the date of the grant. SFAS No. 123, "Accounting for Stock-Based Compensation", requires us to provide pro forma information regarding net income as if compensation cost for the Company's stock option plans had been determined in accordance with the fair value based method prescribed in SFAS No. 123. To provide the required pro forma information, we estimate the fair value of each stock option at the grant date by using the Black-Scholes option-pricing model. In certain circumstances, we issue common stock for invoiced services, to pay creditors and in other similar situations. In accordance with SFAS No. 123, payments in equity instruments to non-employees for goods or services are accounted for by the fair value method, which relies on the valuation of the service at the date of the transaction, or public stock sales price, whichever is more reliable as a measurement. Options were granted but not vested to directors and employees during the fiscal year 2002. An adjustment to net income for compensation expense to recognize annual vesting would be recorded under SFAS No. 123, on a pro forma basis, as reflected in the following table: 49

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2004 2003 ------- -------- Net Income (loss): As Reported $200,675 $57,777 Pro Forma 176,414 33,516 Basic Earnings Per Share: As Reported .03 .01 Pro Forma .03 .01 Diluted Earnings Per Share: As Reported .03 .01 Pro Forma .03 .01 Reclassification ---------------- Certain 2003 amounts have been reclassified to conform to 2004 presentation. Note 2 EMPLOYEE BENEFIT PLANS Defined Contribution Plan ------------------------- We have a 401(k) defined contribution plan that covers all employees. Under the amended terms of the plan, an employee is eligible to participate in the plan immediately upon being hired to work at least 1,000 hours per year and having attained age 21. Participants may contribute up to a maximum of 14.95% of their pre-tax earnings (not to exceed $13,000) to the plan. Under the plan, we may make discretionary contributions to the plan. We made contributions for fiscal 2004 and 2003 in the amount of $8,550 and $8,722, respectively. Split Dollar Life Insurance Plan -------------------------------- As part of the former President's (current Vice President's) employment agreement, we purchased a split dollar life insurance policy for the former President's benefit. We paid total premiums of $360,000 on behalf of the former President, of which a portion ("split") constituted compensation for the former President. At each anniversary we paid the former President an amount as a bonus to reimburse the former President for personal income tax on his split. No additional compensation has been recognized as reimbursement to the former President for income taxes for the years ended June 30, 2004 and 2003. The former President's taxable amount was $-0- for fiscal 2004 and 2003, equal to the "economic benefit" attributed to the former President as defined by the Internal Revenue Code. We paid no premiums during fiscal 2004 and 2003. In June 2003, the plan was terminated and we received a payment of $239,095, the accumulated corporate premium payments due us. We have fulfilled our obligations under this plan and no further action is required of us. Medical Benefit Plan -------------------- For the fiscal years ended June 30, 2004 and 2003, we had a policy of reimbursing employees for medical expenses incurred but not covered by our paid medical insurance plan. Expenses reimbursed for fiscal 2004 and fiscal 2003 were $8,939 and $19,358, respectively. Under the terms of a revised employment agreement (see Note 11) with Mr. Bailey, effective May 1, 2003 he will be responsible for his own medical insurance premiums and will no longer be reimbursed excess medical expenses. Note 3 MAJOR CUSTOMERS We derived in excess of 10% of revenue from our major customers as follows: 50

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Company ------- A B C ----- ----- ----- Year ended: June 30, 2004 21% 52% 15% June 30, 2003 26% 51% * * Less than 10% for fiscal 2003. Note 4 STOCKHOLDERS' EQUITY Common Stock ------------ During 2004, we issued a convertible debenture and detachable warrants to one accredited investor in exchange for the investor's payment to us of $300,000. Subsequent to year end, the debt was converted to 300,500 share of common stock as consideration for payment of principal and interest. See Note 6. The convertible debenture included a potential 600,000 common stock warrants exercisable as follows: If the holder exercises the first warrant before June 30, 2005, we will receive an additional $330,000 ($1.10 per share) and issue 300,000 shares of stock; if the holder exercises the warrant before June 30, 2006 but after June 30, 2005, we receive an additional $360,000 ($1.20 per share) instead of $330,000. If the holder exercises the warrant before March 31, 2005, the holder will receive an additional warrant exercisable to purchase another 300,000 shares at $1.25 per share. In any case, the warrant (and any additional warrant) will expire unless exercised by June 30, 2006. The warrants were valued using the Black-Scholes valuation method at $39,281 and have been recorded as a discount to the debt. The discount will be amortized over the life of the note. Stock Options ------------- On March 2, 2000, stock options were granted to the President of Aspen Power Systems, LLC for 100,000 shares of the Company's common stock at a grant price of $0.625 per share. These options vest 25,000 shares per annum from March 15, 2000 through March 15, 2003. The options are exercisable through March 15, 2004. As of this filing, no options have been exercised, and they have expired by their own terms. During fiscal 2004, two officers, one director, a consultant and an employee exercised their options for 192,000 shares of our common stock granted March 14, 2002 at an average price of $0.57 per share. As consideration for the option shares purchased, the individuals surrendered common stock with a fair value equal to the exercise price of the option shares and held longer than 6 months. The fair value of the shares surrendered was based on a ten-day average bid price immediately prior to the exercise date. Total shares surrendered were 96,849. The effect of the transaction is a net increase to the common stock par value of $476 and a corresponding decrease to additional paid in capital of $476. Total compensation expense in the statement of operations includes amortization of prior stock awards of $3,592 and $6,968 for the years ended June 30, 2004 and 2003, respectively. As of June 30, 2004, we had an aggregate of 484,000 common shares reserved for issuance under our stock option plans. These plans provide for the issuance of common shares pursuant to stock option exercises, restricted stock awards and other equity based awards. 51

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following information summarizes information with respect to options granted under our equity plans: Number of Weighted Average Exercise Shares Price of Shares Under Plans ------ --------------------------- Outstanding balance June 30, 2002 776,000 $ .58 ======= Granted -0- - ======= Exercised -0- - ======= Forfeited or expensed -0- - ------- ======= Outstanding balance June 30, 2003 776,000 .58 ======= Granted -0- - ======= Exercised (192,000) .57 ======= Forfeited or expensed (100,000) .625 ------- ======= Outstanding balance June 30, 2004 484,000 $ .57 ======== ======= The following table summarizes information concerning outstanding and exercisable options as of June 30, 2004: Outstanding Exercisable ---------------------------- ------------------------- Weighted Average Weighted Weighted Remaining Average Average Exercise Number Contractual Exercisable Number Exercise Price Outstanding Life In Years Price Exercisable Price -------- ----------- ------------- ----------- ----------- -------- $.57 284,000 08/15/2005(1) $.57 -0- $.57 .57 200,000 08/15/2007(1) .57 -0- .57 ------- 484,000 ======= (1) The term of the option will be the earlier of the contractual life of the options or 90 days after the date the optionee is no longer an employee, consultant or director of the Company. We account for the two stock option plans using APB No. 25 for directors and employees and SFAS No. 123 for consultants. There were 676,000 options granted in 2002. Directors and employees were granted 601,000 and consultants were granted 75,000. The consultant options were valued using the fair value method of SFAS No. 123 as calculated by the Black-Scholes option-pricing model. The fair value of each option grant, as opposed to its exercisable price, is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions: no dividend yield, expected volatility of 14.9%, risk free interest rates of 8.5% and expected lives of 3.4 to 4.4 years. The resulting compensation expense relating to the consultant option grant will be included as an operating expense as the options vest. 52

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 5 INCOME TAXES We recorded a deferred income tax liability of $296,320 and $131,350 as of June 30, 2004 and 2003, respectively. We paid $800 in California state income taxes in fiscal 2004. During 2004, we used approximately $189,000 in net operating loss carryforwards leaving approximately $1,684,000 in available federal net operating loss carryforwards as of June 30, 2004. During 2003, we added approximately $159,000 in net operating loss carryforwards for a total of approximately $1,873,000. At June 30, 2004 and 2003, no net operating loss carryforwards expired. The deferred tax consequences of temporary differences in reporting items for financial statement and income tax purposes are recognized, if appropriate. Realization of future tax benefits related to the deferred tax assets is dependent on many factors, including our ability to generate taxable income within the net operating loss carryforward period. We have considered these factors in reaching our conclusion as to the valuation allowance for financial reporting purposes. Primarily, our proved oil and gas reserves substantially exceed our expected future costs and hence, we believe it more likely than not that the benefit will be realized. The income tax effect of temporary differences comprising the deferred tax assets and deferred tax liabilities on the accompanying balance sheet is the result of the following: 2004 2003 ---------- ----------- Deferred tax assets: Federal tax loss carryforwards $ 669,929 $ 699,646 Asset retirement obligations 4,727 -- --------- --------- 674,656 699,646 --------- --------- Deferred tax (liabilities): Property, plant and equipment (2,684) (3,324) Oil and gas properties (968,292) (827,672) --------- --------- (970,976) (830,996) ---------- --------- $ (296,320) $(131,350) ========== ========= 53 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A reconciliation between the statutory federal income tax rate (34%) and the effective rate of income tax expense for the two years ended June 30 is as follows: 2004 2003 --------- --------- Statutory federal income tax rate 34% 34% Statutory state income tax rate, net of federal benefit 9% 9% Other 2% (2%) --------- --------- Effective rate 45% 41% ========= ========= The provision for income taxes consists of the following components: 2004 2003 --------- --------- Current tax expense (refund), state $ -0- $ -0- Deferred tax expense 164,970 42,100 --------- --------- Total income tax provision $ 164,970 $ 42,100 ========= ========= We have available federal net operating loss carryforwards of approximately $1,684,000 (net operating losses expire beginning June 30, 2011 through the year ending June 30, 2023). 54 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 6 NOTES PAYABLE The Company incurred the following debt: June 30, June 30, 2004 2003 ------------------------- Note payable to a bank $ 150,000 $ -0- Convertible debenture issued to a privately held corporation 300,000 -0- ---------- ---------- 450,000 -0- ---------- ---------- Less discount (39,281) -0- ---------- ---------- $ 410,719 $ -0- ========== ========== Proceeds from the note payable to a bank was used for the acquisition of producing gas properties located in several counties in the Sacramento Valley, California. The note matures in June 2005, principal payments are $12,500 per month plus interest at the bank's prime rate plus 2%. The rate was 6.5% at June 30, 2004. The loan is collateralized by accounts receivable, other rights to payments and all inventory. On June 28, 2004, a privately-held Oklahoma corporation purchased a $300,000 convertible debenture from Aspen Exploration Corporation. We also issued warrants to purchase 300,000 shares of our common stock which, if exercised before March 31, 2005, will result in the purchaser acquiring warrants to purchase an additional 300,000 shares. The transaction was completed effective June 28, 2004. We issued the convertible debenture to the accredited investor in exchange for the investor's payment to us of $300,000. The convertible debenture with a principal amount of $300,000, bears interest at 4% per annum and 300,000 common stock warrants. See Note 4. Another 300,000 shares are potentially issuable under certain circumstances. On July 15, 2004 the debenture was automatically converted into shares of our restricted common stock after our shares traded at prices greater than $1.00 per share for ten trading days. We issued 300,500 shares of our restricted common stock in satisfaction of the principal and interest due the investor. As of June 30, 2004 and 2003, the weighted average interest rate on the above outstanding borrowings is 4.85% and $-0-, respectively. Note 7 SEGMENT INFORMATION We operate in one industry segment within the United States: oil and gas exploration. Identified assets by industry are those assets that are used in our operations in each industry. Corporate assets are principally cash, furniture, fixtures and vehicles. We have adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information". The adoption of SFAS No. 131 requires the presentation of descriptive information about reportable segments which is consistent with that made available to our management to assess performance. The oil and gas segment derives its revenues from the sale of oil and gas and prospect generation and management fees charged to participants in our oil and gas ventures. 55 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS During the years ended June 30, 2004 and 2003, there were no intersegment revenues. The accounting policies applied by each segment are the same as those used by us in general. Net sales in the oil and gas segment to three customers were approximately $831,000 and $332,000 and $232,000, or 52%, 21% and 15%, respectively, for fiscal 2004. Net sales to two customers were approximately $544,000 and $277,000, or 51% and 26%, respectively, for fiscal 2003. There have been no differences from the last annual report in the basis of measuring segment profit or loss. There have been no material changes in the amount of assets for any operating segment since the last annual report except for the oil and gas segment which capitalized approximately $1,448,000 for the development and acquisition of oil and gas properties in fiscal 2004 and approximately $1,378,000 for the development of oil and gas properties in fiscal 2003. 56

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Segment information consists of the following: Oil and Gas Corporate Consolidated ----------- --------- ------------ Revenues: 2004 $1,820,680 $ 3,256 $1,823,936 2003 1,313,821 9,852 1,323,673 Income (loss) from operations: 2004 $1,008,434 $ (642,789) $ 365,645 2003 743,277 (640,551) 102,726 Identifiable assets: 2004 $5,550,265 $1,395,540 $6,945,805 2003 4,324,671 865,954 5,190,625 Income tax expense: 2004 $ 164,970 $ -0- $ 164,970 2003 42,100 -0- 42,100 Depreciation, depletion and valuation charged to identifiable assets: 2004 $ 563,622 $ 17,780 $ 581,402 2003 410,596 18,368 428,964 Capital expenditures: 2004 $ 1,448,114 $ -0- $1,448,114 2003 1,378,356 -0- 1,378,356 Note 8 RELATED PARTY TRANSACTIONS During the years ended June 30, 2004 and 2003, we provided one vehicle each to our president and vice president. We also paid travel, lodging and meal expenses for spouses who, from time to time, accompanied directors or officers when they were traveling or entertaining on company business. The cost of these items to us totaled less than $5,000 in each of the years ended June 30, 2004 and 2003. We believe that the expenditures were to our benefit. In January 1983, we entered into a Stock Purchase Agreement with our former president, R. V. Bailey, whereby Mr. Bailey granted us an option to purchase up to 75% of our common stock owned by him at his death. The agreement was replaced by a Stock Purchase Agreement dated June 4, 1993 which required us to apply 75% of any key man insurance proceeds it received upon Mr. Bailey's death towards the purchase of up to 75% of the common shares owned by him at the time of his death. Mr. Bailey's estate was obligated to sell such shares to us. The purchase price of the shares acquired under the Agreement was the fair market value of the shares on the date of death. We and Mr. Bailey agreed that the fair market value of the shares on the date of death would not necessarily be the market price of the stock on the date of death as quoted on the OTC Bulletin Board, or as reported by another NASDAQ quotation service or any exchange on which our common stock was quoted. The 1993 Agreement further required that we maintain one or more life insurance policies on Mr. Bailey's life in the amount of $1,000,000 for the purpose of this Agreement. Premiums for this policy were $-0- and $6,970 for each of the fiscal years ended June 30, 2004 and 2003, respectively. In June 2003 the stock purchase agreement expired by its own terms and was not renewed or replaced. On August 22, 2003, Mr. Bailey's life insurance policy expired and was not renewed. 57

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS During fiscal 2002 we entered into a rental agreement with R. V. Bailey to rent office space in Castle Rock, Colorado in an office building owned by Mr. Bailey. The rental amount was $6,000 per year on a month to month basis. This lease was terminated on April 30, 2003. During fiscal 2004, we assigned the following overrides at no cost to employees: R. V. R. A. J. L. Bailey Cohan Shelton ------ ----- ------- Anderson Farms 1 1.360000% 2.000000% 0.640000% Chickohominy 1-12 0.850000% 1.250000% 0.400000% Emigh 35-6 0.144121% 0.211943% 0.067822% Ettl 1-10 1.020000% 1.500000% 0.480000% R. V. Bailey, Vice President and former President and director of the Company, Robert A. Cohan, President and director of the Company, have working and royalty interests in certain of the California oil and gas properties operated by us. The related parties paid for their proportionate working interest share of all costs to acquire, develop and operate these properties on the same terms as other unaffiliated participants. Mr. Bailey and Mr. Cohan purchased working interests amounts totaling $166,005 and $77,325, respectively, for the year ended June 30, 2004, and $82,013 and $77,752, respectively, for the year ended June 30, 2003. Mr. Bailey and Mr. Cohan also received royalty interest payments totaling $55,840 and $51,022, respectively, for the year ended June 30, 2004, and $31,919 and $31,919, respectively, for the year ended June 30, 2003. As of June 30, 2004, working interests of us and related parties in certain producing California properties are as set forth below: GROSS WELLS NET WELLS GAS GAS --- --- Aspen Exploration 58 11.11 R. V. Bailey 39 1.04 R. A. Cohan 39 .66 R. K. Davis 46 .87 J. L. Shelton 28 .07 We have received advances from Messrs. Bailey, Cohan and Davis for working interests in uncompleted wells of $27,410, $18,269 and $16,573, respectively, as of June 30, 2004 and $5,895, $5,895 and $5,895 as of June 30, 2003, respectively. Additionally, we owed Mr. Bailey and Mr. Cohan $6,062 and $2,460 for reimbursement of expenses made on our behalf as of June 30, 2004 and we owe Mr. Bailey $928 for reimbursed expenses on our behalf in 2003. Messrs. Bailey, Cohan and Davis owed us $8,252, $1,694 and $2,796, respectively, as of June 30, 2004 and $3,474, $1,944 and $987, respectively, as of June 30, 2003 for their portion of well operating expenses. See Note 11 for additional related party disclosure. Note 9 CONCENTRATION OF CREDIT RISK Financial instruments, which potentially subject us to concentrations of credit risk, consist principally of cash and cash equivalents, accounts receivable and the cash surrender value of life insurance. While as of June 30, 2004 we have approximately $2,117,352 in excess of the Federal Deposit Insurance Corporation $100,000 limit at one 58 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS bank, we place our cash and cash equivalents with high quality financial institutions in order to limit credit risk. Concentrations of credit risk with respect to accounts receivable are distributed across unrelated businesses and individuals, with the exception of two major gas purchasers and one investor in our wells, who normally settle within 25 days of the previous month's gas purchases. During June 2003 we surrendered the insurance contract for its cash value. We believe our exposure to credit risk is minimal. Cash equivalents are invested through a quality national brokerage firm and a major regional bank. The cash equivalents consists of liquid short-term investments. The Securities Investor Protection Corporation insures the Fund's accounts at this brokerage firm and a commercial insurer up to the total amount held in the account. Note 10 OIL AND GAS ACTIVITIES Capitalized costs ----------------- Capitalized costs associated with oil and gas producing activities are as follows: June 30, 2004 2003 ---------- ---------- Proved properties $8,216,136 $6,723,579 ---------- ---------- Accumulated depreciation, depletion and amortization (2,953,452) (2,392,750) Valuation allowance (281,719) (281,719) ---------- ---------- (3,235,171) (2,674,469) ---------- ---------- Net capitalized costs $4,980,965 $4,049,110 ========== ========== 59 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Results of operations --------------------- Results of operations for oil and gas producing activities are as follows: Year ended June 30, ------------------- 2004 2003 ------- -------- Revenues* $1,820,680 $1,313,821 Production costs (242,472) (159,948) Depreciation, depletion and accretion (563,622) (412,214) Interest expense (6,152) -0- ---------- ---------- Results of operations (excluding corporate overhead) $1,008,434 $ 741,659 ========== ========== *Includes oil and gas related fees and management fees. Fees charged by us to operate the properties totaled approximately $19,370 per month in 2004 and $20,420 per month in 2003. Unaudited oil and gas reserve quantities ---------------------------------------- The following unaudited reserve estimates presented as of June 30, 2004 and 2003 were prepared by an independent petroleum engineer. There are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, reserve estimates of new discoveries that have little production history are more imprecise than those of properties with more production history. Accordingly, these estimates are expected to change as future information becomes available. Proved oil and gas reserves are the estimated quantities of crude oil, condensate, 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 reserves expected to be recovered through existing wells with existing equipment and operating methods. 60 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Unaudited net quantities of proved and proved developed reserves of crude oil (including condensate) and natural gas (all located within the United States) are as follows: Changes in proved reserves (Bbls) (MCF) -------------------------- ------ ----- (in thousands) Estimated quantity, June 30, 2002 11 2,210 Revisions of previous estimates ( 1) (184) Discoveries - 481 Purchased - 221 Production ( 1) (248) Sold ( 6) - ----- ----- Estimated quantity, June 30, 2003 3 2,480 Revisions of previous estimates ( 1) (411) Discoveries - 527 Purchased - 243 Production - (305) ----- ----- Estimated quantity, June 30, 2004 2 2,534 ===== ===== Developed Proved reserves Developed Non-Producing Total --------- ------------- ----- at year end (In Thousands) --------------- Oil (Bbls) June 30, 2004 - 2 2 June 30, 2003 - 3 3 Gas (MCF) June 30, 2004 1,236 1,298 2,534 June 30, 2003 655 1,825 2,480 61 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Unaudited standardized measure ------------------------------ The following table presents a standardized measure of the discounted future net cash flows attributable to our proved oil and gas reserves. Future cash inflows were computed by applying year-end prices of oil and gas to the estimated future production of proved oil and gas reserves. The future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pre-tax net cash flows relating to our proved oil and gas reserves and the tax basis of proved oil and gas properties and available net operating loss carryforwards. Discounting the future net cash inflows at 10% is a method to measure the impact of the time value of money. June 30, -------- 2004 2003 ---- ---- (in thousands) Future cash inflows $ 14,800 $ 12,967 Future production and development costs (1,568) (1,281) Future income tax expense (4,679) (4,027) -------- -------- Future net cash flows 8,553 7,659 10% annual discount for estimated timing of cash flows (2,609) (2,826) -------- -------- Standardized measure of discounted future net cash flows $ 5,944 $ 4,833 ======== ======== 62 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following presents the principal sources of the changes in the standardized measure of discounted future net cash flows: Years ended June 30, -------------------- 2004 2003 ---- ---- (in thousands) Standardized measure of discounted future net cash flows, beginning of year $ 4,833 $ 2,603 -------- -------- Sales and transfers of oil and gas produced, net of production costs (1,346) (909) Net changes in prices and production costs and other 638 5,153 Net change due to discoveries 1,544 981 Acquisition of reserves 711 451 Revisions of previous quantity estimates (15) 481 Development costs incurred 60 18 Accretion of discount 721 376 Sale of existing reserves - (74) Net change in income taxes (755) (1,156) Other (447) (3,091) -------- -------- 1,111 2,230 -------- -------- Standardized measure of discounted future cash flows, end of year $ 5,944 $ 4,833 ======== ======== Net changes in prices and production costs of $651 were the result of an increase in the price received for oil and gas at year end which was offset slightly by an increase in operating costs associated with more producing gas wells in 2004 than in 2003. The revision of previous estimates of $15 was the result of assigning approximately 1,062 fewer barrels of recoverable oil and reducing recoverable reserves of gas by approximately 411,000 MCF, while the volumes were reduced, the price applied to the remaining recoverable reserves increased substantially, resulting in a modest decrease. All adjustments were based on performance reviews of individual wells. A successful drilling program and the acquisition of proven reserves from third parties added $1,544 and $711, or $2.25 million to our future net cash flow. These additions represent approximately 770,000 MCF of recoverable reserves. 63

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 11 COMMITMENTS AND CONTINGENCIES Drilling Completion & Acquisition Area Wells Costs Equipping Costs Costs Total ------------------------------- ---------- ----------- ------------------- -------------- ----------- Momentum Farmout 2 $61,000 $191,000 $252,000 Various Counties, CA West Grimes Field 2 189,000 147,000 336,000 Colusa County, CA Sour Grass Prospect 1 72,000 60,000 132,000 Tehama County, CA Lambie 3-4 1 82,500 82,500 Verona Pipeline - 70,000 70,000 ---------- ----------- ------------------- -------------- ----------- Total Expenditure 6 $322,000 $468,000 $82,500 $872,500 ========== =========== =================== ============== =========== Employment contracts and termination of employment and change in control arrangements: Mr. Bailey: Effective May 1, 2003 we entered into a new employment agreement with Chairman of the Board, R. V. Bailey. Some of the pertinent provisions include an employment period ending May 1, 2009, the title of Vice President subject to the general direction of the President, Robert A. Cohan, and the Board of Directors of Aspen. Mr. Bailey's salary will be $45,000 per year from May 1, 2003 to December 31, 2006 and $60,000 per year from January 1, 2007, ending May 1, 2009. Mr. Bailey will also participate in Aspen's stock options and royalty interest programs. During the term of the agreement, we have agreed to pay Mr. Bailey a monthly $1,700 allowance to cover such items as prescriptions, medical and dental coverage for himself and his dependents and other expenses not covered in the agreement. Mr. Bailey's keyman life insurance policy terminated in August of 2003 and will result in an annual savings of approximately $6,500. The stock purchase agreement with Mr. Bailey was cancelled and replaced by his current employment agreement. The agreement had provided that we apply 75% of the $1,000,000 keyman life insurance to purchase up to 75% of the common shares owned by him at the time of his death. Mr. Bailey will continue to use the Company vehicle and may trade the current vehicle for a similar vehicle of his choice prior to June 30, 2006. During 2007 or thereafter, Mr. Bailey may purchase the vehicle for $500. We may terminate this agreement upon Mr. Bailey's death by paying his estate all compensation that had or will accrue to the end of the year of his death plus $75,000. Should Mr. Bailey become totally and permanently disabled, we will pay Mr. Bailey one half of the salary and benefits set forth in our agreement with him for the remainder of the term of the agreement. Mr. Cohan: On April 16, 1998, we entered into an employment agreement with Robert A. Cohan, which provides for the payment of $90,000 for the first year of employment, plus reimbursement of expenses, including health insurance. We have renewed the agreement effective April 15, 1999 to April 15, 2002 at the rate of $95,000 per year for 64

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS the year commencing April 15, 1999, $100,000 for the year commencing April 15, 2000 and $105,000 for the year commencing April 15, 2001. On August 1, 2001 Mr. Cohan's salary was increased to $125,000 per year. Mr. Cohan's employment agreement expired by its own terms on April 15, 2002 and was replaced by an employment agreement dated January 1, 2003. Some of the pertinent provisions include an employment period ending December 31, 2005, salary increases from $125,000 per year to $135,000 per year effective April 15, 2003, and a further salary increase to $145,000 per year from April 15, 2004 through the end of the contract. Other benefits and duties will remain the same as the previous employment contract. Prior to February 2000, we and Mr. Cohan agreed to utilize a portion of Mr. Cohan's home in Bakersfield, California from which to conduct Aspen's business. Mr. Cohan did not charge Aspen any rent for the use of his home as a business office. Aspen agreed to pay for all office supplies, communication and copy equipment used by Mr. Cohan in his office, as well as the monthly telephone expense incurred by Mr. Cohan on behalf of Aspen. On February 7, 2000, we entered into a three-year lease of office space in Bakersfield, California thereby alleviating the necessity of home office reimbursement to Mr. Cohan. Effective May 1, 2003, our Board of Directors appointed Robert A. Cohan, President of Aspen Exploration Corporation, replacing Mr. Bailey. During fiscal 2002, we entered into a rental agreement with R. V. Bailey to rent office space in Castle Rock, Colorado in an office building owned by Mr. Bailey. The rental amount was $6,000 per year on a month to month basis. This agreement was terminated effective May 1, 2003. Gas sales contract Effective June 1, 2004, we entered a contract to sell 750 MMBTU of gas per day at a fixed price of $6.34 less transportation and other expenses. The contract is for the term June 1 - August 31, 2004 and contains monetary penalties for non-delivery of the gas. Subsequent to year-end, we completed the contract with no penalties realized. Note 12 INTERIM FINANCIAL DATA The year-end adjustment that is material to the results of the fourth quarter ending June 30, 2004 and June 30, 2003 is the adjustment to depreciation, depletion and amortization as a result of receiving the reserve study from an independent reservoir engineer. The aggregate effect of this year-end adjustment to the results of the fourth quarter was to increase depletion expense for the fiscal year 2004 from an estimated $496,000 based on prior years' reserve studies to an actual depletion expense of approximately $564,000, an increase of $68,000 or 13.7% for fiscal 2004 and approximately $464,000 to approximately $411,000, a decrease of $53,000, or 11.4% for fiscal 2003. 65

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 13 CONTRACTUAL OBLIGATIONS We had six contractual obligations as of June 30, 2004. The following table lists our significant liabilities at June 30, 2004: Payments Due By Period ------------------------------------------------------------------------------------------ Less than After Contractual Obligations 1 year 2-3 years 4-5 years 5 years Total ---------------------------------- --------------- -------------- -------------- --------------- --------------- Employment Obligations $210,400 $240,800 $147,400 -0- $598,600 Bank Loans 150,000 260,719 -0- -0- 410,719 Operating Leases 16,686 6,160 -0- -0- 22,846 --------------- -------------- -------------- --------------- --------------- Total contractual cash obligations $377,086 $507,679 $147,400 $-0- $1,032,165 =============== ============== ============== =============== =============== We maintain office space in Denver, Colorado, our principal office, and Bakersfield, California. The Denver office consists of approximately 1,108 square feet with an additional 750 square feet of basement storage. We entered into a one-year lease agreement to December 31, 2004 for a lease rate of $1,261 per month. We also subleased from R. V. Bailey, our vice president, a portion of an office building owned by Mr. Bailey in Castle Rock, Colorado on a month to month basis for $500 per month. This lease arrangement was terminated on April 30, 2003. The Bakersfield, California office has 546 square feet and a monthly rental fee of $730 to $770 over the term of the lease. The three year lease expires February 8, 2006. Rent expense for the years ended June 30, 2004 and 2003 were $24,370 and $28,536, respectively. Note 14 ASSET RETIREMENT OBLIGATION Effective July 1, 2002, we adopted the provisions of SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 requires us to recognize an estimated liability for the plugging and abandonment of our gas wells. As of June 30, 2003, we recognized the future cost to plug and abandon the gas wells over the estimated useful lives of the wells in accordance with SFAS No. 143. A liability for the fair value of an asset retirement obligation with a corresponding increase in the carrying value of the related long-lived asset is recorded at the time a well is completed and ready for production. We will amortize the amount added to the oil and gas properties and recognize accretion expense in connection with the discounted liability over the remaining life of the respective well. The estimated liability is based on historical experience in plugging and abandoning wells, estimated useful lives based on engineering studies, external estimates as to the cost to plug and abandon wells in the future and federal and state regulatory requirements. The liability is a discounted liability using a credit-adjusted risk-free rate of 5%. Revisions to the liability could occur due to changes in plugging and abandonment costs, well useful lives or if federal or state regulators enact new guidance on the plugging and abandonment of wells. Upon adoption of SFAS No. 143, we recorded a liability of $9,132, increased net oil and gas property by $6,283 and recognized a one-time cumulative effect of change in accounting principle of $2,849. We will amortize the amount added to oil and gas properties and recognize 66

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS accretion expense in connection with the discounted liability over the remaining useful lives of the respective wells. A reconciliation of our liability for the year ended June 30, 2004 is as follows: Upon adoption at July 1, 2002 $ 9,132 Liabilities incurred 7,091 Liabilities settled -0- Accretion expense 1,618 Revision to estimate -0- ---------- Asset retirement obligation as of June 30, 2003 17,841 ---------- Liabilities incurred 66,454 Liabilities settled (7,634) Accretion expense 2,921 Revision to estimate -0- ---------- Asset retirement obligation as of June 30, 2004 $ 79,582 ========== Note 15 SUBSEQUENT EVENTS (Unaudited) On August 16, 2004, one officer/director, a consultant and an employee exercised their options for 92,000 shares of our common stock granted March 14, 2002 at an average price of $0.57 per share. As consideration for the option shares purchased, the individuals surrendered common stock with a fair value equal to the exercise price of the option shares. The fair value of the shares surrendered was based on a ten-day moving average bid price immediately prior to the exercise date. Total shares surrendered were 42,359. The effect of the transaction is a net increase to the common stock par value of $248 and a corresponding decrease to additional paid in capital of $248. 67