10KSB 1 aspen10ksb063003.txt FORM 10-KSB (6-30-2003) ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ---------------------- FORM 10-KSB (Mark One) [ X ] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934. For the fiscal year ended June 30, 2003 [ ] 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, 2003 were $1,323,673. At September 22, 2003, the aggregate market value of the shares held by non-affiliates was approximately $2,269,314. The aggregate market value was calculated by multiplying the mean of the closing bid and asked prices ($0.60) 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 (3,782,190). At September 22, 2003, there were 5,863,828 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. 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 also had a 25% interest in Aspen Power Systems, LLC, a company we incorporated to investigate, finance, and construct electrical power generation projects. Effective December 31, 2002, Aspen Power Systems, LLC wound up its affairs and ceased operations. We have also acquired some acreage in Colorado for a possible coalbed methane project. 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) with a three year term and are renewable for an additional two years. We do not intend to proceed with exploration and development of these properties on our own, rather, we intend to farm out the project to another party. To date, we have had no interest in a farmout of this project by industry partners, and we intend to let these leases expire on their own terms at the end of their primary term. Power Generation. In 1999, we formed a subsidiary named Aspen Power Systems, LLC ("APS"), a Colorado limited liability company to provide an opportunity for Aspen to participate in the growing demand for electrical power generated by turbines. Our objectives for APS were to seek opportunities or situations where our analysis indicated that a gas turbine generation plant could be constructed and operate profitably. Any plant construction would require a significant amount of capital for property acquisition, permitting, engineering and design, and construction. Neither Aspen nor the other owners of APS were able to provide this required capital. Consequently, any such activities would have required the availability of funds from third parties, and we were unable to obtain these funds. Aspen owned a 25% interest in APS. 2 Although APS attempted to undertake projects with other power producers (and received reimbursement of $246,000 in fees and expenses relating to our Solano, California, project from a third party), APS was unable to initiate any economic projects. On December 31, 2002 APS ceased operations and filed its final tax returns. See Item 12 for more information regarding APS. 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 have to 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 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 2003 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, 2003, crude oil and natural gas sales and revenues from operating oil and gas properties accounted for $1,313,821, or 99% of our total revenues; while $9,852, or 1%, 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. 3 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 2003 we obtained more than 10% of our revenues from sales to Calpine Corporation and Enserco Energy, Inc.; in 2002 more than 10% of our revenues derived from ConocoPhillips, Calpine Corporation and Slawson Corporation. 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. 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, 2003, we employed two full-time persons. We also employ independent contractors and other consultants, as needed. 4 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, 2003 we participated in the drilling of 8 gross (1.45 net) wells, of which 7 gross (1.22 net) were completed as gas wells and 1 was a dry hole. Of the 8 wells drilled, 3 operated wells (1 dry hole and 2 gas wells) were drilled in the Sour Grass Prospect, 1 operated gas well was drilled in the Millar Field, 2 operated gas wells were drilled in the Kirk Buckeye Field, 1 non-operated gas well was drilled in the South Dixon Field and 1 non-operated gas well was drilled in the West Grimes Field. In addition to the drilling activity, 9 operated gas wells were acquired in the West Grimes Field in Colusa County, California and 1 shut-in gas well was acquired in Sutter County, California. West Grimes Field, Colusa County, California -------------------------------------------- Aspen acquired nine shut-in gas wells located in the West Grimes Field, Colusa County, California, approximately 100 miles northeast of Sacramento. All of these shut-in gas wells were tested; nine of them have proven productive and one tested gas at sub-commercial rates and was plugged and abandoned. The nine productive wells have been equipped and hooked up via 5 miles of newly constructed pipeline facilities. Gas sales from these wells commenced in late March and are currently 800 MCFPD. Several of these wells have additional gas potential in behind-pipe zones, which have not yet been perforated. Aspen has also acquired in excess of 5,000 acres in this area which includes highly prospective lands for additional exploratory and development drilling. Prior to selection of the drill sites, an extensive 3-D seismic program will be acquired in October-November 2003 to better define drilling targets. Quality targets will be identified and prepared for the 2004 drilling season. Aspen has a 21.0% operated working interest in this prospect Millar Field, Yolo County, California ------------------------------------- The Pope Bypass #1-5 well located in Yolo County, California, approximately 50 miles southwest of Sacramento, was drilled to a depth of 7,800 feet and 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 interval (top of a 6 foot sand) was perforated and tested at a stabilized rate of 2,161 MCFPD of natural gas with a flowing tubing pressure of 2,780 psig and a flowing casing pressure of 2,800 psig. The shut in pressures were approximately 2,810 psig, indicating a very high permeability reservoir with slight pressure drawdown during the flow period. Aspen has a 27.75% operated working interest in this well. Gas sales commenced on June 20th and the well is currently flowing at a stable rate of 950 MCFPD with a flowing tubing pressure of 2,450 psig and a flowing casing pressure of 2,700 psig. Feather River Prospect, Sutter County, -------------------------------------- Aspen recently 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 2003 at a rate of 500 MCFPD after pipeline construction is completed. The other well commenced gas sales in mid-August and is producing a steady 200 MCFPD with no pressure decline. 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 4 attempts in this field during the last 2 fiscal years. These wells produce from multiple horizons in the Forbes formation from depths ranging from 7,500 feet to 9,500 feet. Aspen will commence drilling on its Sac Outing Farms #31-3 well in October 2003. This well will be drilled to a depth of 9,400 feet to test multiple Forbes objectives. Aspen has operated working interests in these wells ranging from approximately 15% to 36%. 5 Sour Grass Prospect, Tehama County, California ---------------------------------------------- The Sour Grass prospect area is a 2,800 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 as well as previous 2-D seismic survey information. Five to ten 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 may drill additional wells in this area next 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 did not drill any wells in this field during the 2003 fiscal year. Aspen has drilled a total of 12 productive gas wells out of 15 attempts, an 80% success rate. Cumulative gross production from the field is in excess of 9.5 BCF of natural gas. 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 in excess of 700 MCFPD of high quality natural gas (1085 BTU) with numerous behind-pipe zones in many of the wells. Drilling Activity: ------------------ The following table sets forth the results of our drilling activities during the fiscal years ended June 30, 2001, 2002 and 2003: Drilling Activity ----------------- Gross Wells Net Wells ----------- --------- Year Total Producing Dry Total Producing Dry ---- ----- --------- --- ----- --------- --- 2001 Exploratory 10 6 4 1.22 .58 .64 2002 Exploratory 6 4 2 1.32 .98 .34 2003 Exploratory 8 7 1 1.45 1.22 .23 6 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, 2003, 2002, and 2001, and the average sales prices, average production costs and direct lifting costs per unit of production. Years Ended June 30, -------------------- 2003 2002 2001 ---- ---- ---- Net Production -------------- Oil (Bbls) 768 3,055 5,206 Gas (MMcf) 248 227 377 Average Sales Prices -------------------- Oil (per Bbl) $ 26.13 $ 20.20 $ 26.64 Gas (per Mcf) $ 4.23 $ 2.78 $ 9.20 Average Production Cost1 -----------------------= Per equivalent Bbl of oil $ 12.83 $ 11.21 $ 7.53 Average Lifting Costs2 ---------------------- Per equivalent Bbl of oil $ 3.61 $ 2.86 $ 1.65 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, 2003: Producing and Shut-In Wells --------------------------- Gross Net1 ----- ---- Prospect Gas Gas -------- --- --- California: Armstrong 17-4 1 0.36000 Balsdon 3-21 1 0.05983 Balsdon 6 1 0.04134 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 0.28800 Emigh 35-1 1 0.28525 Emigh 35-2 1 0.32800 Emigh 35-3 1 0.11900 Firestone 1-10 1 0.03850 Gay Unit 2 0.42000 Grey Wolf 1 1 0.18000 HSRCC 1 1 0.01857 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 NL&F 26-1 1 0.23334 Pinheiro 1-10 1 0.01890 Pinheiro 2-10 1 0.01890 Pope Bypass 1-5 1 0.27750 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 Tiahrt 1-4 1 0.03617 Verona Farms 1 1 0.20000 West Grimes Unit 14 2 0.42000 West Grimes Unit 15 3 0.63000 West Grimes Unit 16 2 0.42000 Strain Ranches 16-3 1 0.21000 Strain Ranches 17-1 1 0.21000 Zimmerman 1-24 1 0.23334 TOTAL 47 8.01826 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. 8 Developed Acreage Table ----------------------- Aspen's Developed Acres1 Prospect Gross2 Net3 -------- ----- --- California: Denverton Creek 1,271 207 Feather River 320 64 Firestone 1-10 160 6 Grey Wolf 1 120 22 Kirk Buckeye 800 229 Malton Black Butte Field 2,023 321 McCullough 36-1 583 115 Phillips Acquisition 1,280 71 Pope Bypass 1-5 120 33 Sour Grass 1,184 276 West Grimes 1,920 403 ----- ------ TOTAL 9,781 747 ===== ====== 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, 2003: Overriding Royalty Interests ---------------------------- Productive Wells Gross Prospect Interest(%) Gas Acreage1 -------- ----------- --- -------- California: Denverton Creek 1.142816 1 80 Malton Black Butte 7.500000 2 645 Grimes Gas 0.101590 1 615 --- ----- TOTAL 4 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, 2003: Undeveloped Acreage ------------------- Gross Net ----- --- California: Denverton Creek 514 69 Orion 1,677 335 Sacreiter 245 245 Sour Grass 1,376 321 West Grimes 3,273 670 ------ ------ Sub Total 7,085 1,640 Colorado: Coalbed Methane Prospect 2,074 2,074 ------ ------ TOTAL 9,159 3,714 ======= ====== Delivery Commitments: We are not obligated to provide a fixed and determinable quantity of oil and gas in the future under existing contracts and agreements. Drilling Commitments: At June 30, 2003, we were committed to the following drilling, development and seismic projects in California: Project Aspen Cost ------- ---------- Mengali-Durst #22-1 $ 40,000 Sac Outing Farms #31-3 44,000 West Grimes 3-D 100,000 Verona Pipeline 70,000 --------- Total $ 254,000 --------- Reserve Information - Oil and Gas Reserves: Cecil Engineering, Inc. evaluated our oil and gas reserves attributable to our properties at June 30, 2003. 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 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. 10 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, 2003 and 2002. See Note 9 to the Consolidated Financial Statements and the above discussion. Estimated Proved Reserves ------------------------- Proved Reserves Oil (Bbls) Gas (Mcf) --------------- ---------- --------- Estimated quantity, June 30, 2001 13,000 2,243,000 --------- --------- Revisions of previous estimates 2,000 (115,000) Discoveries 0 258,000 Production (3,000) (227,000) Purchased reserves 0 51,000 Sold reserves (1,000) 0 --------- --------- 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 ========= ========= Developed and Undeveloped Reserves ---------------------------------- Developed Undeveloped Total --------- ----------- ----- Oil (Bbls) June 30, 2002 7,000 4,000 11,000 June 30, 2003 - 3,000 3,000 Gas (Mcf) June 30, 2002 482,000 1,728,000 2,210,000 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 9 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, 2003. 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 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. 11 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, 2003 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 pay $730 per month for the Bakersfield, California office, which consists of approximately 546 square feet. The Bakersfield, California lease 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, 2003, 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, 2002 and 2003, we believe that we were in full compliance with these rules. Quarter Ended Sept., Dec., March, June 30, 2002 2002 2003 2003 ---- ---- ---- ---- Common Stock ("ASPN") High $.58 $.38 $.52 $.86 Low $.21 $.31 $.34 $.40 Quarter Ended Sept., Dec., March, June 30, 2001 2001 2002 2002 ---- ---- ---- ---- Common Stock ("ASPN") High $1.35 $1.00 $.73 $.73 Low $0.77 $0.63 $.54 $.55 12 Holders: As of June 30, 2002 and 2003, there were approximately 1,197 and 1,182 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.' 13

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, 2003, 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, 2003. ----------------------------------------------------------------------------------------------- Equity Compensation Plan Information (1) ----------------------------------------------------------------------------------------------- Plan Category and Number of Weighted-average Number of securities Description Securities to be exercise price of remaining available for issued upon outstanding future issuance under equity exercise of options, warrants, compensation plans outstanding and rights (excluding securities options, reflected in column (a)) warrants, and rights (a) (b) (c) ----------------------------------------------------------------------------------------------- Equity compensation plans approved by security holders -0- $-0- -0- ----------------------------------------------------------------------------------------------- Equity compensation plans not approved by security holders 676,000 $0.57 NA ----------------------------------------------------------------------------------------------- Total 676,000 $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. 14

Recent Sales of Unregistered Securities -- Item 701 Disclosure. The following sets forth information regarding sales of unregistered securities within the past two years as required by Item 701 of Regulation S-B. ----------------------- ------------- ------------- ------------ ---------------- ----------- Name and Principal Date Number of Offering Registration Option Position Common Price Exemption Exercise Shares Sold ($) Price Per (#) Share ($) ----------------------- ------------- ------------- ------------ ---------------- ----------- R. F. Sheldon, 12/17/2001 80,000 20,800 Rule 144 .26 director, options exercised ----------------------- ------------- ------------- ------------ ---------------- ----------- Total 80,000 20,800 .26 ----------------------- ------------- ------------- ------------ ---------------- ----------- ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION OR PLAN OF ------------------------------------------------------------------------------- OPERATION --------- Overview: Founded in 1980, Aspen Exploration Corporation is an oil and gas company, which participates in the oil and gas segment by acquiring interest in producing oil and gas properties, and participating in drilling operations. Historically we have also participated in exploration for precious minerals and, in uranium exploration. In fiscal 2000, we expanded our business scope to include a goal of participating in the electric power segment. We are not currently actively pursuing either precious minerals exploration or participation in the electric power segment (although we had a 25% interest in APS as described above). As of December 31, 2002, APS ceased operations and went out of business. We have also acquired an interest in leases for approximately 2,074 acres which we believe contain coalbed methane gas deposits. 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 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. 15

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: ----------------------------- Effective July 1, 2002, 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 5%. 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. Liquidity and Capital Resources: During prior years, we had to finance many of our oil and gas operations through short-term borrowings, which were paid back out of the funds generated from our operations. During fiscal 2003 and 2002, we were able to finance all of our oil and gas operations from funds generated from operations and through farmout agreements and other forms of third party participation. In fiscal 2003 we received cash flow from operations of approximately $900,000. Net income before taxes and change in accounting principle was approximately $103,000 compared to a loss of approximately $237,000 during fiscal 2002. The net income before taxes and changes in accounting principle of $103,000 was the result of an increase in the average price we received for natural gas sales from $2.78 in fiscal 2002 to $4.23 in fiscal 2003, an increase of $1.45, or 52%. Production for the period increased 3% on a barrels of oil equivalent ("BOE") basis when comparing fiscal 2003 to 2002. We also increased our accounts payable and accrued expenses by almost $262,000 and decreased our accounts receivable by nearly $103,000 which had a positive impact on cash flow from operations. During fiscal 2003 we also received cash of $239,095 from a split dollar life insurance policy held jointly with our former president and now vice president R. V. Bailey. At the end of 2002 we had working capital of approximately $845,000. We used these funds to finance our use of cash used by investing activities ($1,280,000) resulting in working capital of approximately $343,000 at June 30, 2003. We did not have sufficient cash available to assist us in financing our operations in prior years, and we may not in future years, since our ability to generate working capital depends almost entirely on the prices we receive for 16 our natural gas production. Because of our working capital surpluses through 2003, we did not need to borrow any funds for operations or investing activities. We cannot now predict whether we will be required to borrow funds or find alternative means of financing operations during the fiscal year ending June 30, 2004. June 30, 2003 as compared to June 30, 2002 ------------------------------------------- June 30, 2003 June 30, 2002 ------------- ------------- Current Assets $ 1,093,131 $ 1,333,221 Current Liabilities $ 750,401 $ 488,622 Working Capital $ 342,730 $ 844,599 Investments in Oil & Gas Properties/Drilling Activities $ 1,378,356 $ 1,195,535 Compared to fiscal 2002, there was a 59% decrease in working capital. Our investment in drilling projects and the acquisition of producing properties of approximately $1,380,000 accounted for much of the decline in current assets. Fiscal 2003 was a successful drilling year for us, having participated in the drilling of six wells in California, five of them successful, for a 83% success ratio. During 2003 we also acquired various interests in producing properties located in California as well as increasing our working interests in three wells in the Denverton Creek field. We believe that the increased revenues derived from the late year drilling activities and acquisitions will have a positive effect on next year's working capital and contribute significantly to our cash flow in the year ahead provided that the average prices we receive from our natural gas production do not decrease materially. The average price we received during fiscal 2003 for our oil and gas was $26.13 per barrel and $4.23 per MCF compared to $20.20 per barrel and $2.78 per MCF for fiscal 2002. Given the current downturn of our economy and estimates of a range of $4.00 to $5.00 per MCF for gas in the coming 12 months, we do not see any significant improvement, other than seasonal adjustments, to natural gas prices in the short term. The price for oil has been stable to improving due to unrest in the Middle East, but we derive only a small portion of our revenue from oil sales. Our capital requirements can fluctuate over a twelve month period because our drilling activities are usually carried out during California's dry season (from late April until October) after which wet weather either precludes further activity or makes it cost prohibitive. Investments in Oil and Gas Properties/Drilling Activities --------------------------------------------------------- We invested $1,378,356 and $1,195,535 in our oil and gas properties for the fiscal years ended June 30, 2003 and 2002. While we have not finalized drilling plans for fiscal 2004, we have committed to participate in the drilling of 2 wells through June 2004 with our share of drilling costs estimated to be approximately $84,000, and we anticipate additional drilling will occur in fiscal 2004. 3-D seismic studies and pipeline construction will add an additional $170,000 to our projected costs for fiscal 2004. We believe that internally generated funds will be sufficient to finance our drilling and operating expenses for the next twelve months. We have eliminated our outstanding loans in fiscal 2001 but may be required to again seek outside funding to facilitate our fiscal 2004 drilling program. Aspen Power Systems, LLC ------------------------ During fiscal 1999 and 2000, we dedicated certain cash resources to APS to investigate the economic possibilities of the sale, design, construction and/or operation of gas turbines to produce electricity. Through June 30, 2000, we expended approximately $130,000 on this project, $45,657 of which was expensed in the twelve months ended June 30, 2000. During fiscal 2001, we advanced a further $20,000 to defray APS operating costs which were recorded as a receivable at June 30, 2001. During fiscal 2002 an additional $5,500 was advanced to APS to retire existing obligations of APS. Both the $20,000 and $5,500 advances were expensed by us at June 30, 2002. The funding to APS came from our operating funds derived from oil and gas production. As discussed above, we did not assign a value to the $130,000 note receivable due from APS and do not anticipate any significant future requirements to fund further projects of APS, because APS ceased operations effective December 31, 2002. 17

Contractual Obligations We had contractual and other obligations that will require use of our working capital resources as of June 30, 2003. The following table lists our significant obligations at June 30, 2003: Payments Due By Period -------------------------------------------------------------------- Less than Contractual Obligations 1 year 2-3 years 4-5 years After 5 years Total ----------------------- ------ --------- --------- ------------- ----- Employment Obligations $202,485 $373,300 $153,300 $60,300 $789,385 Operating leases 16,326 15,240 -0- -0- 31,566 --------- --------- --------- -------- --------- Total contractual cash obligations $218,811 $388,540 $153,300 $60,300 $820,951 ======== ======== ======== ======= ======== At June 30, 2003, we were committed to the following drilling and development projects in California: Project Aspen Cost ------- ---------- Mengali-Durst #22-1 $ 40,000 Sac Outing Farms #31-3 44,000 West Grimes 3-D 100,000 Verona Pipeline 70,000 --------- Total $ 254,000 --------- 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, 2003 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, 2003 and 2002 were $28,536 and $26,663, 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 $21,500 per year. 18

Results of Operations: We continued to focus our operations on the production of oil and gas and the investigation for possible acquisition of producing oil and gas properties during the twelve months ended June 30, 2003. June 30, 2003 as compared to June 30, 2002 ------------------------------------------ The following table sets forth, for the periods indicated, certain statement of operations data. The table and the discussion below should be read in conjunction with the audited financial statements and the notes thereto appearing elsewhere in this report. Year Ended June 30 ------- 2003 2002 ---- ---- Oil and gas revenues (a) $1,313,821 $ 828,150 Oil and gas production expenses (159,948) (117,014) Aspen Power Systems -0- (25,500) Depreciation, depletion and amortization (428,964) (358,912) Selling, general and administrative expense (632,035) (605,085) ---------- ---------- Income before other items and income taxes 92,874 278,361 Other income 9,852 41,372 ---------- ---------- Operating income (loss) 102,726 (236,989) Income tax (expense) recovery (42,100) 114,904 ---------- ---------- Income (loss) before cumulative effect of change in accounting principle 60,626 (122,085) Cumulative effect of change in accounting principle, net of income taxes (2,849) -0- ---------- ---------- Net income (loss) $ 57,777 $ (122,085) ========== ========== (a) Oil and gas revenues includes income from management fees Oil and Gas Revenues -------------------- For the twelve months ended June 30, 2003, oil and gas revenues increased approximately $486,000, a 59% increase. Revenue increases were primarily due to an increase in gas prices from $2.78 per MMBTU in 2002 to $4.23 per MMBTU in 2003. The average price in fiscal 2003 was impacted positively by an improving American economy and the continued high price of oil, which can be used as an alternative fuel, due to global political uncertainties. Production of oil declined 1287 barrels, or 42%, reflecting the sale of our final two producing oil wells in the first quarter of fiscal 2003. Gas production increased by 9.3% and was the result of the addition of five new exploratory wells during fiscal 2003 and the acquisition of fifteen producing gas wells in the current fiscal year. These additions were partially offset by the abandonment of five gas wells which proved to be at the end of their economic life during fiscal 2003. Oil and Gas Production Expenses ------------------------------- Oil and gas production expenses increased approximately $43,000, or 37%. We had a larger number of producing wells in fiscal 2003 and our recompletion and workover expenses increased because marginal gas wells were put on compressors and the initial costs to put acquired wells on production were substantial. Depletion, depreciation and amortization increased $70,052, or 19.5%, from $358,912 in fiscal 2002 to $428,964 in fiscal 2003. The depletable assets in the full cost pool increased by approximately $1,296,000 in fiscal 2003, the proved, recoverable reserves of oil and gas increased from BOE 380,000 (barrel of oil equivalent) in fiscal 2002 to BOE 416,000 in fiscal 2003, a 9.5% increase. Our reserves increased 9.5% and our production rate increased by approximately 3%, thus the depletion rate held fairly constant and the increase in depletion was primarily due to an increase in the full cost pool. Selling, general and administrative expenses increased $26,950, or 4.5%, during fiscal 2003, due to higher salary, consulting, audit and temporary services. We anticipate lower general and administrative expenses in fiscal 2004 19

due to the new employment agreement with our former president, now vice president, R. V. Bailey. Salary, rent and insurance expense should decline in the coming year. We continue our commitment to contain costs and increase cash flow wherever possible. As a result of our operations for the fiscal year ended June 30, 2003, we ended the year with operating income of approximately $103,000 before income tax expense of $42,000 and a change of accounting principle charge of approximately $3,000, compared to an operating loss of approximately $237,000 before recovery of income taxes of nearly $115,000 for the year ended June 30, 2002. The improvement can be attributed, as discussed above, to a substantial increase in prices received for our oil and gas, a modest increase in our rate of production and an increase of $110,294, or 82%, in management fees received from well operations. 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, participation in APS stock ownership, 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. (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) Although we currently do not have active operations in the mining segment, mining exploration and mining have inherent risks including the environment, low prices for commodities, competition from better financed companies and the risk of failure in either exploration or mining. There is no assurance we will be able to compete successfully in the exploration and mining business should that course of action be undertaken. (9) We currently do not have active operations in the power generation business. Risks involved in power generation include permitting, availability of fuel and power lines on an economical basis, a market for the product, availability of equipment, and competition from other better financed companies. There is no assurance we will be able to compete successfully in the power generation business should an opportunity be found. (10) 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 2,849,367 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. 20 ITEM 7. FINANCIAL STATEMENTS ----------------------------- The information required by this item begins on page 35 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. 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. Director Name Age Position Class Since ---- --- -------- ----- ----- Robert A. Cohan 47 President, Chief Executive I 1998 Officer,Chief Financial Officer, Treasurer and Director Robert F. Sheldon 80 Director II 1981 R. V. Bailey 71 Vice President, Secretary, and III 1980 Director 21 Each of the directors will be up for reelection at the next annual meeting of stockholders and 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 2004. 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. He has approximately 24 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. R. V. Bailey. R. V. Bailey obtained a Bachelor of Science degree in Geology from the University of Wyoming in 1956. He has approximately 41 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. Meetings of the Board and Committees: The Board of directors held one formal meeting during the fiscal year ended June 30, 2003. 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 three times during fiscal 2002 and four times subsequently through June 30, 2003. 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. 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. 22 Family Relationships: As of June 30, 2003, 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 22, 2003, all filing requirements applicable to its officers, directors and greater-than-ten-percent shareholders were complied with. However, there was one untimely-filed filing (Form 4) for one director, Robert F. Sheldon. 23

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, 2001, 2002 and 2003. No other person who is currently an executive officer of Aspen earned salary and bonus compensation exceeding $100,000 during any of those years. This includes all compensation paid to each by Aspen and any subsidiary. ---------------------------- -------------------------------- -------------------------------------- Annual compensation Long-term Compensation Awards ------------------------------------------------------------- -------------------------- ----------- Awards Payout ------------------------------------------------------------- -------------------------- ----------- (a) (b) (c) (d) (e) (f) (g) (h) (i) ------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- ----------------- Securities Name and ($) Underlying All Other Principal Fiscal ($) ($) ($) Restricted Options & LTIP Compensation Position Year Salary Bonus Other (1) Awards SARs (#) Payout (1) ------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- ----------------- R. A. Cohan 2001 101,250 0 146,400 0 0 0 0 President and 2002 123,300 0 34,850 0 0 0 200 CEO 2003 127,100 0 35,600 0 0 0 9,700 ------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- ----------------- R. V. Bailey, 2001 100,000 0 143,600 0 0 0 12,663 Vice President 2002 122,900 0 34,850 0 0 0 11,565 and Chairman 2003 111,700 0 33,250 0 0 0 23,487 ------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- ----------------- (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, 2003, 2002 and 2001. Mr. Bailey's taxable amount was $-0- for fiscal 2003, 2002 and 2001, equal to the "economic benefit" attributed to the vice president as defined by the Internal Revenue Code. The Company paid no premiums during fiscal 2003, 2002 and 2001. We adopted a Profit-Sharing 401(k) Plan which took effect July 1, 1990. All employees are immediately eligible to participate in this Plan. Aspen's contribution (if any) to this plan is determined by the Board of Directors each year. At June 30, 2002 and 2001, we contributed $-0- to the plan; during fiscal 2003 we contributed $7,388 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 its officers and directors for out-of-pocket costs and expenses incurred on behalf of Aspen. 24

During fiscal 2003, we assigned to employees royalties, which accumulated during the fiscal year ended June 30, 2003, 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 ------ ----- ------- McCullough 36-1 1.683938% 1.683937% 0.641500% Pope Bypass 1-5 1.065339% 1.566676% 0.501336% 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, 2003. No stock options were exercised during the fiscal year ended June 30, 2003. Aggregated Option Exercises in Last Fiscal Year and Fiscal Year End Option Values: One of our directors exercised stock options during the fiscal year ended June 30, 2002: 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, 2003. Number of securities underlying unexercised Value of unexercised Shares options/SARs in-the-money options/SARs acquired on Value at June 30, 2003 at June 30, 2002 Name and Principal Position exercise (#) realized Exercisable/Unexercisable Exercisable/Unexercisable --------------------------- ------------ -------- ------------------------- ------------------------- R. V. Bailey Vice President & Chairman... -0- -0- 0 /150,000 $-0- Robert A. Cohan President & CEO............. -0- -0- 0 /250,000 $-0- Robert F. Sheldon Director....................... 80,000 $20,800 0 /150,000 $-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, 2003. 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 this year 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. 25

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(a) Transactions with Management and Others. ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. ------------------------------------------------------------------------- The following table sets forth as of September 22, 2003 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 1,444,403i 24.63% Robert A. Cohan 790,619ii 13.48% Robert F. Sheldon 284,783iii 4.86% All Officers and Directors as a Group 2,519,805 42.97% (3 persons) The address for all of the above directors and executive officers is: 2050 S. Oneida St., Suite 208, Denver, CO 80224 (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; 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. 26 (ii) This number includes 300,000 shares of common stock granted; stock options to purchase 250,000 shares of restricted common stock; 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; and stock options granted for 80,000 shares of common stock that were exercised on December 17, 2001. Except with respect to the employment agreement between Aspen and R. V. Bailey, 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 of all costs to acquire, develop and operate these properties. As of June 30, 2003, 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 52 7.07 R. V. Bailey 39 .87 R. A. Cohan 40 .60 R. K. Davis 46 .65 J. L. Shelton 24 .05 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. 27 Aspen Power Systems, LLC: In order to provide an opportunity for Aspen to participate in the growing demand for electrical power generated by turbines, our management established an 85% owned subsidiary named Aspen Power Systems, LLC ("APS"), a Colorado limited liability company. On March 1, 2000 our interest in APS was reduced to 25%. The transaction is more fully described in Item 1 "Aspen Power Systems, LLC". APS organized Solano Power, LLC on December 27, 1999 for the purpose of carrying out The Solano Project. Solano Power plans to find a joint venture partner to develop a 50 MW natural gas powered electric generation plant in Solano County, California. We own a 25% interest in Solano Power, the managers; Larry Baccari, R. V. Bailey and Ray K. Davis each contributed $5,000 to fund Solano operations and own a 25% interest each in the project. The managers are seeking an industry partner in order to financially assist Solano Power to build and operate the plant. At June 30, 2000 APS had expended approximately $28,400 on behalf of Solano Power as well as accruing expenses for consulting fees of R. V. Bailey and Ray K. Davis of $31,050 and $7,462, respectively. At June 30, 2002 Solano had no outstanding obligations and was inactive for most of the year. APS has assumed the responsibilities of finding partners to fund the power plant. At June 30, 2001 Solano transferred its operations to Aspen Power Systems and APS has assumed the responsibility for pursuing this project. On September 17, 2001, we were advised by the State of California that our 25% owned project in Solano County, California has not been selected by the California Power Commission for further negotiations. Effective December 31, 2002 APS ceased operations and went out of business. Aspen Borrowings: During the fiscal years ending June 30, 2002 and 2003, we had no outstanding loans or borrowing obligations. Other Arrangements: During the fiscal years 2003 and 2002 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, 2003 and 2002, respectively. Management believes that the expenditures were to Aspen's benefit. During the years ended June 30, 2003 and 2002, Aspen provided one vehicle each to Aspen's president and vice president. We also have entered into an employment agreement, which has expired, and a Stock Purchase Agreement, which also expired, with our vice president, as discussed in "Item 10 - Employee Compensation" and "Item 11 - Security Ownership." 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. 28 Compensation Agreements: Please refer to the prior section, Item 10. Executive Compensation, describing the employment agreements between the Company and Messrs. Bailey and Cohan. 29 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 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 (10) 10.08 Stock Purchase Agreement between Aspen Exploration Corporation and R.V. Bailey dated January, 1983 (7) 10.11 Employment Agreement between Aspen Exploration Corporation and R.V. Bailey dated November 8, 1991 (8) 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). Reports on Form 8-K. No Report on Form 8-K was filed by the Company during the fiscal year ending June 30, 2003 or subsequently. 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 $15,200 for the fiscal year ended June 30, 2003 and approximately $15,500 for the fiscal year ended June 30, 2002. 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. 30

(b) Audit-Related Fees. Gordon Hughes & Banks LLP billed us aggregate fees in the amount of $1,800 for the fiscal years ended June 30, 2003 and 2002 for assurance and related services that were reasonably related to the performance of the audit or review of our financial statements. (c) Tax Fees Gordon Hughes & Banks LLP billed us aggregate fees in the amount of approximately $4,600 for the fiscal year ended June 30, 2003 and approximately $4,400 for the fiscal year ended June 30, 2002, 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, 2003 and 2002 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 Section 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 Section 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 2003 and 2004 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 2003 Fiscal Year 2002 ------------------ -------------------------------- ------------------------- Audit fees 70% 71% ------------------ -------------------------------- ------------------------- Audit-related fees 8% 8% ------------------ -------------------------------- ------------------------- Tax fees 22% 21% ------------------ -------------------------------- ------------------------- All other fees 0% 0% ------------------ -------------------------------- ------------------------- 31

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 22, 2003 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 22, 2003 Robert A. Cohan /s/ Robert A. Cohan Principal Executive Officer, ---------------------- Principal Financial Officer Robert A. Cohan Director September 22, 2003 R. V. Bailey /s/ R. V. Bailey Chairman of the Board ---------------------- Director R. V. Bailey September 22, 2003 Robert F. Sheldon /s/ Robert F. Sheldon Director ---------------------- Robert F. Shelton 32 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Page ---- Report of Independent Auditors' Report................................... 33 Financial Statements as of June 30, 2003 and June 30, 2002: Consolidated Balance Sheets.............................................. 34-35 Consolidated Statements of Operations.................................... 36 Consolidated Statement of Stockholders' Equity........................... 37 Consolidated Statements of Cash Flows.................................... 38 Notes to Consolidated Financial Statements............................... 39-61 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, 2003 and 2002 and the related consolidated statements of operations, stockholders' equity, and cash flows for the years ended June 30, 2003 and 2002. 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 auditing standards generally accepted in the United States of America. 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, 2003 and 2002, and the results of their consolidated operations and cash flows for the years ended June 30, 2003 and 2002 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 14, 2003 33

Item 7. Financial Statements and Supplementary Data ------- ------------------------------------------- ASPEN EXPLORATION CORPORATION AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS ASSETS June 30, 2003 2002 ----------- ----------- Current Assets: Cash and cash equivalents, including $516,365 and $822,060 of invested cash in 2003 & 2002, respectively (Note 1) ................................................ $ 776,566 $ 916,001 Precious metals (Note 1) .................................. 18,823 18,823 Accounts & trade receivables .............................. 269,259 365,705 Accounts receivable - related party (Notes 1 and 7) ....... 6,302 12,872 Prepaid expenses .......................................... 22,181 19,820 ----------- ----------- Total current assets ...................................... 1,093,131 1,333,221 ----------- ----------- Investment in oil & gas properties, at cost (full cost method of accounting) (Note 9) ................................. 6,723,579 5,427,741 Less accumulated depletion and valuation allowance ...... (2,674,469) (2,262,649) ----------- ----------- 4,049,110 3,165,092 ----------- ----------- Property and equipment, at cost: Furniture, fixtures & vehicles ........................... 112,562 112,562 Less accumulated depreciation ........................... ( 64,178) ( 45,810) ----------- ----------- 48,384 66,752 ----------- ----------- Cash surrender value, life insurance (Note 2) ............... -0- 239,095 ----------- ----------- Total assets ................................................ $ 5,190,625 $ 4,804,160 =========== =========== (Statement Continues) See Summary of Accounting Policies and Notes to Consolidated Financial Statements 34

Item 7. Financial Statements and Supplementary Data ------- ------------------------------------------- ASPEN EXPLORATION CORPORATION AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS (Continued) LIABILITIES AND STOCKHOLDERS' EQUITY June 30, 2003 2002 ----------- ----------- Current liabilities: Accounts payable and accrued expenses ................................ $ 581,895 $ 236,587 Accounts payable - related party (Note 7) ............................ 17,685 21,260 Advances from joint interest owners .................................. 150,021 230,775 ----------- ----------- Total current liabilities ......................................... 750,401 488,622 ----------- ----------- Asset retirement obligation (Note 15) ................................ 17,841 -0- Deferred income taxes (Note5) ........................................ 131,350 89,250 ----------- ----------- Total long term liabilities .......................................... 149,191 89,250 ----------- ----------- Total liabilities .................................................. 899,592 577,872 ----------- ----------- Stockholders' equity: (Notes 1 and 4): Common stock, $.005 par value: Authorized: 50,000,000 shares Issued and outstanding: At June 30, 2003 and June 30, 2002: 5,863,828 ....................................................... 29,320 29,320 Capital in excess of par value ....................................... 6,025,797 6,025,797 Accumulated deficit .................................................. (1,756,900) (1,814,677) Deferred compensation................................................ (7,184) (14,152) ----------- ----------- Total stockholders' equity ........................................... 4,291,033 4,226,288 ----------- ----------- Total liabilities and stockholders' equity ........................... $ 5,190,625 $ 4,804,160 =========== =========== See Summary of Accounting Policies and Notes to Consolidated Financial Statements 35

Item 7. Financial Statements and Supplementary Data ------- ------------------------------------------- ASPEN EXPLORATION CORPORATION AND SUBSIDIARY CONSOLIDATED STATEMENTS OF OPERATIONS Year ended June 30, 2003 2002 ----------- ----------- Revenues: Oil and gas (Note 9) ...................................... $ 1,068,798 $ 693,421 Management fees (Note 9) .................................. 245,023 134,729 Interest and other income ................................. 9,852 41,372 ----------- ----------- Total revenues .............................................. 1,323,673 869,522 ----------- ----------- Costs and expenses: Oil and gas production .................................... 159,948 117,014 Aspen Power Systems expense (Note 14) ..................... -0- 25,500 Depreciation, depletion and amortization .................. 428,964 358,912 Interest expense .......................................... -0- 479 Selling, general and administrative ...................... 632,035 604,606 ----------- ----------- Total costs and expenses .................................... 1,220,947 1,106,511 ----------- ----------- Operating income (loss) ..................................... 102,726 (236,989) (Provision for) recovery of income taxes .................... (42,100) 114,904 ----------- ----------- Income (loss) before cumulative effect of change in accounting principle ...................................... 60,626 (122,085) ----------- ----------- Cumulative effect of change in accounting principle, net of income taxes .............................................. (2,849) -0- ----------- ----------- Net income (loss) ........................................... $ 57,777 $ (122,085) =========== =========== Basic earnings (loss) per common share Income (loss) before cumulative effect of change in accounting principle ...................................... $ .01 $ (.02) Cumulative effect of change in accounting principle, net of income taxes ............................................. $ -- $ -- ----------- ----------- Net income (loss) ......................................... $ .01 $ (.02) =========== =========== Diluted earnings (loss) per common share..................... Income (loss) before cumulative effect of change in accounting principle ...................................... $ .01 $ (.02) Cumulative effect of change in accounting principle, net of income taxes ............................................. $ -- $ -- ----------- ----------- Net income (loss) ......................................... $ .01 $ (.02) =========== =========== Basic weighted average number of common shares outstanding .............................................. 5,863,828 5,863,828 =========== =========== Diluted weighted average number of common shares outstanding .............................................. 6,083,528 5,863,828 =========== =========== See Summary of Accounting Policies and Notes to Consolidated Financial Statements 36

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY Common Stock (par $.005) Shares ------------------------ Retained Deferred Total outstanding Par Value APIC Earnings Compensation Equity ----------- ----------- ----------- ----------- ----------- ----------- Balance, June 30, 2001 .............. 5,812,205 $ 29,060 $ 6,015,279 $(1,692,592) $ (17,208) $ 4,334,539 Options exercised by director ....... 51,623 260 (260) -- -- -- Amortization of deferred compensation -- -- -- -- 13,834 13,834 Options granted to consultant ....... -- -- 10,778 -- (10,778) -- Net loss ............................ -- -- -- (122,085) -- (122,085) ----------- ----------- ----------- ----------- ----------- ----------- 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 =========== =========== =========== =========== =========== =========== See Summary of Accounting Policies and Notes to Consolidated Financial Statements 37

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended June 30, 2003 2002 ----------- ----------- Cash flows from operating activities: ------------------------------------- Net income (loss) ........................................................... $ 57,777 $ (122,085) Adjustments to reconcile net income to net cash provided (used) by operating activities: Amortization of deferred compensation .................................. 6,968 13,834 Depreciation, depletion, and amortization .............................. 431,813 358,912 Changes in assets and liabilities: Decrease in receivable and prepaid expenses ............................ 100,655 190,660 Increase (decrease) in accounts payable, accrued expenses and advances from joint owners ........................................... 261,779 (993,025) Increase (decrease) in deferred income taxes payable ................... 42,100 (89,250) ----------- ----------- Net cash provided (used) by operating activities .............................. 901,092 (640,954) Cash flows from investing activities: ------------------------------------- Additions to oil and gas properties ......................................... (1,378,356) (1,122,906) Producing oil and gas properties purchased .................................. -0- (72,629) Office equipment purchased .................................................. -0- (8,194) Sale of oil and gas equipment ............................................... 28,865 26,998 Sale of oil and gas properties .............................................. 69,869 38,103 ----------- ----------- Net cash (used) by investing activities ....................................... (1,279,622) (1,138,628) Cash flows from financing activities: ------------------------------------- Proceeds from Split dollar life insurance ................................... 239,095 -0- ----------- ----------- Net increase (decrease) in cash and cash equivalents .......................... (139,435) (1,779,582) Cash and cash equivalents, beginning of year .................................. 916,001 2,695,583 ----------- ----------- Cash and cash equivalents, end of year ........................................ $ 776,566 $ 916,001 =========== =========== Other information: ------------------ Interest paid ................................................................. $ -0- $ 479 =========== =========== Income taxes paid (refunded).................................................. $ -0- $ (24,954) =========== =========== Non-cash investing and financing activities: -------------------------------------------- Asset retirement obligation ................................................. $ (16,223) $ -0- =========== =========== Exercise of stock options ................................................... $ -0- $ 260 =========== =========== See Summary of Accounting Policies and Notes to Consolidated Financial Statements 38

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. We also have a 25% interest in Aspen Power Systems, LLC, a company we incorporated to investigate, finance, and construct electrical power generation projects. 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. Power Generation. In 1999, we formed a subsidiary named Aspen Power Systems, LLC ("APS"), a Colorado limited liability company to provide an opportunity for Aspen to participate in the growing demand for electrical power generated by turbines. Our objectives for APS were to seek opportunities or situations where our analysis indicated that a gas turbine generation plant could be constructed and operate profitably. Any plant construction would require a significant amount of capital for property acquisition, permitting, engineering and design, and construction. Neither Aspen nor the other owners of APS were able to provide this required capital. Consequently, any such activities would have required the availability of funds from third parties, and we could not offer any assurance that such funding would be available when needed on commercially-reasonable terms. Accordingly, APS ceased operations effective December 31, 2002. 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. The equity method was used to account for our Company's 25% interest in APS. Using the equity method, an investment in a company is recorded at acquisition cost which is subsequently adjusted for the Company's share of dividends, earnings, or losses. Effective December 31, 2002 APS ceased operations. 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. 39 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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). 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 at June 30, 2003. There were no sales of gold from inventory for the years ended June 30, 2003 and 2002. 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 40 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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, 2003 and 2002 (Note 9). Depletion and amortization expense was $410,596 and $341,236 for the years ended June 30, 2003 and 2002, respectively. 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 $18,368 and $17,676 for the years ended June 30, 2003 and 2002, 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, 2003 and 2002, we expensed $6,968 and $13,834, respectively, in stock bonuses. Allowance for Bad Debts ----------------------- We consider accounts receivable to be fully collectible as recorded as of June 30, 2003 and 2002; 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. 41 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following is a reconciliation of the numerators and denominators used in the calculations of basic and diluted earnings per share. We had a net income of $57,777 for the year ended June 30, 2003 and a net loss of $122,085 for the year ended June 30, 2002. Because of the net loss for the year ended June 30, 2002, the basic and diluted average outstanding shares are considered the same, since including the shares would have an antidilutive effect on loss per share calculation. 2003 ----------------------------- Per Net Share Income Shares Amount ------ ------ ------ Basic earnings per share: Net income and share amounts $57,777 5,863,828 $ .01 Dilutive securities stock options 776,000 Repurchased shares (556,300) ------------------------------- Diluted earnings per share: Net income and assumed share conversion $57,777 6,083,528 $ .01 ========= ========= ===== 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. 42 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. Recent Accounting Pronouncements -------------------------------- In June 2002, the Financial Accounting Standards Board ("FASB") issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities". SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity". SFAS No. 146 generally requires a liability for a cost associated with an exit or disposal activity to be recognized and measured initially at its fair value in the period in which the liability is incurred. The pronouncement is effective for exit or disposal activities initiated after December 31, 2002. The adoption of SFAS No. 146 has had no impact on its financial position or results of operations. SFAS No. 147, "Acquisitions of Certain Financial Institutions," was issued in December 2002 and is not expected to apply to the Company's current or planned activities. In December 2002, the FASB approved SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of FASB Statement No. 123". SFAS No. 148 amends SFAS No. 123, "Accounting for Stock-Based Compensation" to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. SFAS No. 148 is effective for financial statements for fiscal years ending after December 15, 2002. The Company will continue to account for stock based compensation using the methods detailed in the stock-based compensation accounting policy. In April 2003, the FASB approved SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities". SFAS No. 149 is not expected to apply to the Company's current or planned activities. In June 2003, the FASB approved SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity". SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. This Statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. SFAS No. 150 is not expected to have an effect on the Company's financial position. 43 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 11.75% of their pre-tax earnings (not to exceed $12,000) to the plan. Under the plan, we may make discretionary contributions to the plan. We made a contribution for fiscal 2003 in the amount of $8,722 and no contribution for fiscal 2002. 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, 2003 and 2002. The former President's taxable amount was $-0- for fiscal 2003 and 2002, equal to the "economic benefit" attributed to the former President as defined by the Internal Revenue Code. We paid no premiums during fiscal 2003 and 2002. 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, 2003 and 2002, we had a policy of reimbursing employees for medical expenses incurred but not covered by our paid medical insurance plan. Expenses reimbursed for fiscal 2003 and fiscal 2002 were $19,358 and $7,786, respectively. Under the terms of a revised employment agreement (see Note 10) 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 our revenue from various sources (oil and gas sales and mineral royalties) as follows: The Company ------------- A B C D ----- ----- ----- ----- Year ended: June 30, 2003 * 26% 51% * June 30, 2002 30% * 33% 13% * Less than 10% for fiscal 2003 and 2002. 44 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 4 STOCKHOLDERS' EQUITY 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. During fiscal 2002 one director exercised his option for 80,000 shares of our common stock granted November 1, 1997 at an average price of $0.26 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 average bid price immediately prior to the exercise date. Total shares surrendered were 28,377. The effect of the transaction is a net increase to the common stock par value of $260 and a corresponding decrease to additional paid in capital of $260. Total compensation expense in the statement of operations includes amortization of prior stock awards of $6,968 and $13,834 for the years ended June 30, 2003 and 2002, respectively. As of June 30, 2003, we had an aggregate of 776,000 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. 45

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following information summarizes information with respect to options granted under our equity plans: Weighted Average Number of Exercise Price of Shares Shares Under Plans ------ ------------------ Outstanding balance June 30, 2001 180,000 $ .46 ===== Granted 676,000 .57 ===== Exercised (80,000) .57 ===== Forfeited or expensed -0- - ======= ===== Outstanding balance June 30, 2002 776,000 .58 ===== Granted -0- - ===== Exercised -0- - ===== Forfeited or expensed -0- - ======= ===== Outstanding balance June 30, 2003 776,000 $ .58 ======= ===== The following table summarizes information concerning outstanding and exercisable options as of June 30, 2003: Outstanding Exercisable ---------------------------- ------------------------- Weighted Average Weighted Weighted Remaining Average Average Exercise Number Contractual Exercisable Number Exercise Price Outstanding Life In Years Price Exercisable Price -------- ----------- ------------- ----------- ----------- -------- $.625 100,000 03/15/2004(1) $.625 100,000 $.625 .57 426,000 08/15/2005(1) .57 -0- .57 .57 250,000 08/15/2007(1) .57 -0- .57 ------- 776,000 ======= (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 46

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. Options were granted but not exercisable to directors and employees during the fiscal year 2002. An adjustment to net income for compensation expense would be recorded under SFAS No. 123, on a pro forma basis, as reflected in the following table: 2003 2002 ------- ------- Net Income (loss): As Reported $57,777 $(122,085) Pro Forma 33,516 (128,150) Basic Earnings Per Share: As Reported .01 (.02) Pro Forma .01 (.02) Diluted Earnings Per Share: As Reported .01 (.02) Pro Forma .01 (.02) 47 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 5 INCOME TAXES We recorded deferred income taxes of $131,350 and $89,250 as of June 30, 2003 and 2002, respectively. We paid $800 in California state income taxes in fiscal 2002. During 2003, we added approximately $82,000 in net operating loss carryforwards for a total of approximately $1,796,000 in available federal net operating loss carryforwards. During 2002, we added approximately $1,100,000 in net operating loss carryforwards for a total of approximately $1,714,000. At June 30, 2003 and 2002, no net operating loss carryforwards expired; but $1,200 in general business credits expired in fiscal 2002. 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. 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: 2003 2002 --------- --------- Deferred tax assets: Federal tax loss carryforwards $ 699,646 $ 490,862 --------- --------- 699,646 490,862 --------- --------- Deferred tax (liabilities): Property, plant and equipment (3,324) (6,241) Oil and gas properties (827,672) (573,871) --------- --------- (830,996) (580,112) --------- --------- $(131,350) $( 89,250) ========= ========= 48 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: 2003 2002 --------- --------- Statutory federal income tax rate 34% 34% Statutory state income tax rate, net of federal benefit 9% 9% Utilization of net operating loss carryforwards and other (2%) 5.5% --------- -------- Effective rate 41% 48.5% ========= ======== The provision for income taxes consists of the following components: 2003 2002 --------- --------- Current tax expense (refund), state $ -0- $ (25,654) Deferred tax expense (recovery) 42,100 (89,250) --------- --------- Total income tax provision (recovery) $ 42,100 $(114,904) ========= ========= We have available federal net operating loss carryforwards of approximately $1,796,000 (net operating losses expire beginning June 30, 2011 through the year ending June 30, 2023). 49 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 6 SEGMENT INFORMATION We operate in two industry segments within the United States: oil and gas exploration and development electrical generation construction. Identified assets by industry are those assets that are used in our operations in each industry. Corporate assets are principally cash, cash surrender value of life insurance, and 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. The electrical generation construction segment would have received its revenues from the sale, design, construction and/or operation of gas turbine or other electrical generation projects. As of June 30, 2002, we were in the planning stage of this segment and no revenues have been received. However, we did advance APS $5,500 for operating expenses. As of December 31, 2002, APS ceased operations and no further business activity is anticipated in this segment. During the years ended June 30, 2003 and 2002, 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 two customers were approximately $544,000 and $277,000, or 51% and 26%, respectively, for fiscal 2003. Net sales to three customers were approximately $229,000, $205,000 and $91,000, or 33%, 30% and 13%, respectively, for fiscal 2002. 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 $1,378,000 for the development of oil and gas properties in fiscal 2003 and approximately $1,196,000 for the development and acquisition of producing properties in fiscal 2002. 50

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Segment information consists of the following: Oil and Gas Power Plant Corporate Consolidated ----------- ----------- --------- ------------ Revenues: 2003 $1,313,821 $ -0- $ 9,852 $1,323,673 2002 828,150 -0- 41,372 869,522 Income (loss) from operations: 2003 $ 743,277 $ -0- $ (640,551) $ 102,726 2002 369,900 (25,500) (581,389) (236,989) Identifiable assets: 2003 $4,324,671 $ -0- $ 865,954 $5,190,625 2002 3,543,669 -0- 1,260,491 4,804,160 Income tax expense (recovery): 2003 $ 42,100 -0- $ -0- $ 42,100 2002 (114,904) -0- -0- (114,904) Depreciation, depletion and valuation charged to identifiable assets: 2003 $ 410,596 $ -0- $ 18,368 $ 428,964 2002 341,236 -0- 17,676 358,912 Capital expenditures: 2003 $1,378,356 $ -0- $ -0- $1,378,356 2002 1,195,535 -0- 8,194 1,203,729 Note 7 RELATED PARTY TRANSACTIONS During the years ended June 30, 2003 and 2002, 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, 2003 and 2002. 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 $6,970 for each of the fiscal years ended June 30, 2003 and 2002. 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. 51

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 2003, we assigned the following overrides at no cost to employees: R. V. R. A. J. L. Bailey Cohan Shelton ------ ----- ------- McCullough 36-1 1.683938% 1.683937% 0.641500% Pope Bypass 1-5 1.065339% 1.566676% 0.501336% 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 $82,013 and $77,752, respectively, for the year ended June 30, 2003, and $31,180 and $27,896, respectively, for the year ended June 30, 2002. Mr. Bailey and Mr. Cohan also received royalty interest amounts totaling $31,919 and $31,919, respectively, for the year ended June 30, 2003, and $34,849 and $34,844, respectively, for the year ended June 30, 2002. As of June 30, 2003, 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 52 7.07 R. V. Bailey 39 .87 R. A. Cohan 40 .60 R. K. Davis 46 .65 J. L. Shelton 24 .05 We have received advances from Messrs. Bailey, Cohan and Davis for working interests in uncompleted wells of $5,895, $5,895 and $5,895, respectively, as of June 30, 2003 and $5,306, $4,676 and $6,017 as of June 30, 2002, respectively. Additionally, we owed Mr. Bailey $928 and $5,171 for reimbursement of expenses made on our behalf as of June 30, 2003 and 2002, respectively. Messrs. Bailey, Cohan and Davis owed us $3,474, $1,944 and $987, respectively, as of June 30, 2003 and $4,638, $3,060 and $5,174, respectively, as of June 30, 2002 for their portion of well operating expenses. See Note 11 for additional related party disclosure. Note 8 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, 2003 we have approximately $823,208 in excess of the Federal Deposit Insurance Corporation $100,000 limit at one 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 limited since relatively 52 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS small amounts are due from each account, and the accounts are distributed across unrelated businesses and individuals, with the exception of two major gas purchasers, who normally settle within 25 days of the previous month's gas purchases. An international insurance company held the cash surrender value of the split dollar life insurance contract. 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 9 OIL AND GAS ACTIVITIES Capitalized costs Capitalized costs associated with oil and gas producing activities are as follows: June 30, 2003 2002 ---------- ---------- Proved properties $6,723,579 $5,427,741 ---------- ---------- Accumulated depreciation, depletion and amortization (2,392,750) (1,980,930) Valuation allowance (281,719) (281,719) ---------- ---------- (2,674,469) (2,262,649) ---------- ---------- Net capitalized costs $4,049,110 $3,165,092 ========== ========== 53 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, 2003 2002 ------- -------- Revenues* $1,313,821 $ 828,150 Production costs (159,948) (117,014) Depreciation and depletion (410,596) (341,236) ---------- ---------- Results of operations (excluding corporate overhead) $ 743,277 $ 369,900 ========== ========== *Includes oil and gas related fees and management fees. Fees charged by us to operate the properties totaled approximately $20,420 per month in 2003 and $11,230 per month in 2002. Unaudited oil and gas reserve quantities ---------------------------------------- The following unaudited reserve estimates presented as of June 30, 2003 and 2002 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. 54 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, 2001 13 2,243 Revisions of previous estimates 2 (115) Discoveries - 258 Purchased - 51 Production ( 3) (227) Sold ( 1) - ----- ----- 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 ===== ===== Proved reserves Developed at year end Developed Non-Producing Total --------------- --------- ------------- ----- (In Thousands) Oil (Bbls) June 30, 2003 - 3 3 June 30, 2002 7 4 11 Gas (MCF) June 30, 2003 655 1,825 2,480 June 30, 2002 482 1,728 2,210 55 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, 2003 2002 ---- ---- (in thousands) Future cash inflows $ 12,967 $ 6,352 Future production and development costs (1,281) (772) Future income tax expense (4,027) (1,779) -------- ------- Future net cash flows 7,659 3,801 10% annual discount for estimated timing of cash flows (2,826) (1,198) -------- ------- Standardized measure of discounted future net cash flows $ 4,833 $ 2,603 ======== ======= 56 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, 2003 2002 ---- ---- (in thousands) Standardized measure of discounted future net cash flows, beginning of year $ 2,603 $ 8,458 -------- -------- Sales and transfers of oil and gas produced, net of production costs (909) (576) Net changes in prices and production costs and other 5,153 (9,368) Net change due to discoveries 981 394 Acquisition of reserves 451 78 Revisions of previous quantity estimates 481 (468) Development costs incurred 18 459 Accretion of discount 376 1,406 Sale of existing reserves (74) (6) Net change in income taxes (1,156) 4,198 Other (3,091) (1,972) -------- -------- 2,230 (5,855) -------- -------- Standardized measure of discounted future cash flows, end of year $ 4,833 $ 2,603 ======== ======== Net changes in prices and production costs of $5,153 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 2003 than in 2002 and no oil wells. The revision of previous estimates of $481 was the result of assigning approximately 400 fewer barrels of recoverable oil and reducing recoverable reserves of gas by approximately 180,000 MCF, while the volumes were reduced, the price applied to the remaining recoverable reserves increased substantially, resulting in the increase. All adjustments were based on performance reviews of individual wells. 57 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 10 COMMITMENTS AND CONTINGENCIES At June 30, 2003, we were committed to the following drilling and development projects in California: Project Aspen Cost ------- ---------- Mengali-Durst #22-1 $ 40,000 Sac Outing Farms #31-3 44,000 West Grimes 3-D 100,000 Verona Pipeline 70,000 --------- Total $ 254,000 --------- 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 this year 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 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 58

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. Note 11 INTERIM FINANCIAL DATA The year-end adjustment that is material to the results of the fourth quarter ending June 30, 2003 and June 30, 2002 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 decrease depletion expense for the fiscal year 2003 from an estimated $464,000 based on prior years' reserve studies to an actual depletion expense of approximately $411,000, a decrease of $53,000 or 11.4% for fiscal 2003 and approximately $447,000 to approximately $341,000, a decrease of $106,000, or 24% for fiscal 2002. Note 12 CONTRACTUAL OBLIGATIONS We had five contractual obligations as of June 30, 2003. The following table lists our significant liabilities at June 30, 2003: Payments Due By Period ------------------------------------------------------------------------------------- Less than Contractual Obligations 1 year 2-3 years 4-5 years After 5 years Total ----------------------- ------ --------- --------- ------------- ----- Employment Obligations $202,485 $373,300 $153,300 $60,300 $789,385 Operating leases 16,326 15,240 -0- -0- 31,566 -------- -------- -------- ------- -------- Total contractual cash obligations $218,811 $388,540 $153,300 $60,300 $820,951 ======== ======== ======== ======= ======== We maintain office space in Denver, Colorado, our principal office; Castle Rock, Colorado 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, 2003 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, 2003 and 2002 were $28,536 and $26,663, respectively. 59

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 13 ASPEN POWER SYSTEMS, LLC During fiscal 1999 and 2000, we dedicated certain cash resources to APS to investigate the economic possibilities of the sale, design, construction and/or operation of gas turbines to produce electricity. Through June 30, 2000, we expended approximately $130,000 on this project, $45,657 of which was expensed in the twelve months ended June 30, 2000. During fiscal 2001, we advanced a further $20,000 to defray APS operating costs which were recorded as a receivable at June 30, 2001. During fiscal 2002, an additional $5,500 was advanced to APS to retire existing obligations of APS. Both the $20,000 and $5,500 advances were expensed by us at June 30, 2002. The funding to APS came from our operating funds derived from oil and gas production. As discussed above, we did not assign a value to the $130,000 note receivable due from APS and do not anticipate any significant future requirements to fund further projects of APS because APS ceased operations effective December 31, 2002. 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 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, 2003 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 ======== 60 ASPEN EXPLORATION CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following unaudited pro forma information has been prepared to give effect to the adoption of SFAS No. 143 as if it had been adopted on July 1, 2002. The effect on fiscal year 2001 is considered immaterial. Year Ended ---------- June 30, 2002 ---- Net (loss) income As reported $ (122,085) Accretion of retirement obligation (net of tax) (2,849) ---------- Pro forma $ (124,934) ========== Basic net income (loss) per common share: As reported $ (.02) Pro forma $ (.02) Diluted net income (loss) per common share: As reported $ (.02) Pro forma $ (.02) 61