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. Our participation in the oil and gas exploration and development segment consists of two different lines of business –ownership of working interests and operating properties.

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     With the assistance of our management, independent contractors retained from time to time by us, 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 areas of interest are in the state of California and in the state of Montana.

     We hold working interests in oil and gas properties, many of which have wells producing oil or natural gas. Where we acquire an interest in a property or 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, and as such have entered into industry standard joint operating agreements with other parties. In such cases, we may retain a carried working interest, a reversionary interest, or other promotional interest, and we generally are required to fin ance 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. Fees assessed for the participation in these prospects are credited to the full-cost pool.

     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”). During the year ended June 30, 2007, we participated in the drilling of 2 farm-in wells.

     In addition to properties having producing wells or reserves, Aspen also owns some unproved properties that it believes may have value for oil and gas exploration and development. These properties are disclosed in more detail, below. We do not believe that our capitalized costs associated with these unproved properties are, at June 30, 2007, material in amount. Such costs include lease acquisition, geological and geophysical work, delay rentals. These costs are capitalized in our full cost pool and included in our amortization computation. We review the capitalized costs of all properties against our full-cost pool on a quarterly basis.

     We also occasionally acquire unevaluated acreage in conjunction with the purchase of oil and gas leases. While unproved properties are properties we believe are valuable for oil and gas exploration based on the exploration work performed, unevaluated properties are properties that have been acquired but which have not been evaluated based on exploration work known to have been performed by others. Costs attributable to unevaluated acreage are considered immaterial at June 30, 2007. These costs are included in our full cost pool and amortization computation.

     From time-to-time we may also engage in mineral and natural resource exploration and similar business activities not associated with the oil and gas industry. To date, we have not devoted a material amount of resources to these other business activities nor have we generated material revenues from these other business activities.

     Principal Products Produced and Services Rendered. Our principal products during fiscal 2007 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, 2007, our crude oil and natural gas sales totaled $4,418,231.

     Both our produced crude oil and natural gas are subject to pricing in the local markets where the production occurs. It is customary that such products are priced based on local or regional supply and demand factors. California heavy crude sells at a discount to WTI, the U.S. benchmark for crude oil, primarily due to the additional cost to refine gasoline or light product out of a barrel of heavy crude. Natural gas field prices are normally priced off of Henry Hub NYMEX price, the benchmark for U.S. natural gas. Aspen’s gas prices are based on the PG&E Citygate Index. While we attempt to contract for the best possible price in each of our producing locations, there is no assurance that past price differentials will continue into the future. Numerous factors may influence local pricing, such as refinery capacity, pipeline capacity and specifications, upsets in the mid-stream or downstream sec tors of the industry, trade restrictions, governmental regulations, and other factors. We may be adversely impacted by a widening differential on the products sold.

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     Distribution Methods of the Products or Services. We are not involved in the distribution aspect of the oil and gas industry. We sell our produced natural gas and oil to third parties for distribution.

     Status of any Publicly Announced New Products or Services. During our 2007 fiscal year we did 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, during our 2007 fiscal year we did not made a public announcement of, nor have we made information otherwise public about, any such product or service.

     As outlined above, from time-to-time we may also engage in business activities not associated with the oil and gas industry. In January 2007 we announced that we entered into a joint venture with Hemis Corporation whereby Hemis will be the operator of a venture engaged in permit acquisition and exploration for commercial quantities of gold in and near Cook Inlet, Alaska. We were paid $50,000 upon entering the agreement and will be paid $50,000 on each anniversary date until production of gold begins. Additionally, we retained a 5% gross royalty on production. In June 2007, Hemis announced that it had begun a preliminary oceanographic survey of the gold project and was optimistic regarding the project’s potential. However, Hemis will continue to survey the area with additional equipment and is continuing to negotiate with contractors for potential drilling later this calendar year.

     Competitive Business Conditions. The exploration for, and development, production and acquisition of, oil, gas, precious metals and other minerals are subject to intense competition. 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)     stipulations requiring exploration and production commitments by the lessee.

     In addition, the availability of a ready market for oil and gas depends upon numerous factors beyond our control, including the overall amount of domestic production and imports of oil and gas, the proximity and capacity of pipelines, and the effect of federal and state regulation of oil and gas sales, as well governmental environmental regulations applicable to the exploration, production 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.

     Sources and Availability of Raw Materials. As part of the business of engaging in the operation of oil and gas properties, we depend on such items as drilling rigs and other equipment, casing pipe, drilling mud and other supplies and equipment necessary for our operations. At the present time, drilling rigs are in short supply, and are demanding a premium price. Nevertheless, we have been able to obtain the services of drilling rigs when needed for our exploration and development activities.

     Most other items that we need have been commonly available from a number of sources. Although we do not foresee a shortage in supply or foresee having difficulty in acquiring any equipment relevant to the conduct of business, we cannot offer any assurances that the necessary equipment 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 2007 and 2006 we obtained more than 10% of our revenues from sales to Calpine Corporation and Enserco Energy, Inc., (15% and 77%, respectively). 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.

     Need for Governmental Approval of Principal Products or Services. We do not need to seek government approval of our principal products.

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     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. Part of the regulatory environment in which we operate includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. These regulations affect our operations and limit the quantity of oil and natural gas we may produce and sell. 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. P>

     A major risk inherent in our drilling plans is the need to obtain drilling permits from state, and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a negative effect on our ability to explore on or develop its properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability.

     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.

     As of June 30, 2007, we have 2 full-time employees and 1 part-time employee. We also employ independent contractors and other consultants, as needed.

     We have a significant amount of information regarding the proven developed and undeveloped oil and gas reserves which can be found below in this Item 2 as well as in the notes to our financial statements.

     During the fiscal year ended June 30, 2007, we participated in the drilling of 11 gross (2.927 net) operated wells, eight of which were completed as gas wells, for a 73% success ratio. The estimated lives of the individual wells drilled during the fiscal year range from 1 to 13 years. Of the eight successful gas wells drilled during the 2007 fiscal year, four gas wells were drilled in the West Grimes Field, one gas well was drilled in the Grimes Field, 1 gas well was drilled in the Malton Black Butte Field, and 1 gas well was drilled in the Kirk Buckeye Field. Aspen also purchased an interest in 33 producing gross oil wells (4.125 net) in certain oil producing assets encompassing 22,600 acres in the East Poplar Unit and the Northwest Poplar Field in Roosevelt County, Montana located in the Williston Basin.

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     Our decisions to develop and operate prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often uncertain. Even when used and properly interpreted, 3-D seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or producible economically. In addition, the use of 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies. Because of these factors, we could incur losses as a result of exploratory drilling expenditures. Poor results from exploration activities could have a material adverse effect on our future cash flows, results of operations and financial position.

     Below is a summary of our primary drilling and acquisition activity occurring during our 2007 fiscal year and our activities to-date conducted during our 2008 fiscal year by geographic areas.

     The first 16 wells drilled in the West Grimes Gas Field were successful with 15 wells currently producing and 1 well waiting on completion. These wells were drilled based on a 10.5 square mile 3-D seismic program located over a portion of Aspen’s 10,000 plus leased acres in this field. We believe several additional excellent drilling prospects have been identified. The wells in this field produce from multiple Forbes intervals ranging in depth from 6,000 feet to 8,500 feet and have produced over 80 billion cubic feet (BCF) of gas to date. Numerous wells in this immediate area have produced at very prolific flow rates (4,000 MCFPD), have yielded excellent per well reserves (3 to 4 BCF per well), and have long productive well lives. Several of the 10 producing wells that Aspen acquired in this field in 2003 have been producing for 40 years. Aspen believes that several of these wells may have addit ional gas potential in behind-pipe zones, which have not yet been perforated. Aspen’s operated working interests in this field range from 21% to 34%.

     The WGU #14-10 well was directionally drilled in May 2007 to a depth of 8,460 feet and encountered approximately 55 feet of potential net gas pay in several intervals in the Forbes formation. One of these intervals was perforated and tested gas on a 12/64 inch choke at a stabilized flow rate of 2,678 MCFPD with a flowing tubing pressure of 3,300 psig and a flowing casing pressure of 3,480 psig. The shut in tubing and casing pressures were 3,810 psig. Gas sales commenced on May 30, 2007.

     The WGU #15-13 well was directionally drilled in May and June 2007 to a depth of 8,300 feet and encountered approximately 50 feet of potential gas pay in several intervals in the Forbes formation. One of these intervals was perforated and tested gas on a 1/4 inch choke at a stabilized flow rate of 1,764 MCFPD. The shut in tubing pressure was 4,020 psig and the shut in casing pressure was 4,030 psig. Gas sales commenced on June 30, 2007.

     In August 2007, the WGU #15-14 well was directionally drilled to a depth of 7,770 feet and encountered approximately 80 feet of potential gross gas pay in several intervals in the Forbes formation. One of these intervals was perforated and tested gas on a 1/4 inch choke at a stabilized flow rate of 1,130 MCFPD. The shut in tubing and shut in casing pressures were 3,200 psig. Gas sales commenced on August 28, 2007.

     The Morris #12-4 well was drilled in July 2007 to a depth of 8,007 feet and encountered approximately 115 feet of potential gross gas pay in several intervals in the Forbes formation. Production casing was run based on favorable mud log and electric log responses. Several of these intervals were perforated and tested gas on a ¼ inch choke at a stabilized flow rate of 500 MCFPD. The shut in tubing and shut in casing pressures were 3,150 psig. This was the sixteenth successful gas well out of sixteen attempts by Aspen in this field. Aspen is currently drilling one additional well in this field.

     The Nelson #1-10 well was directionally drilled in June and July 2007 to a depth of 8,320 feet and encountered approximately 100 feet of potential net gas pay in several intervals in the Forbes formation. The first interval perforated in this well tested gas on a 1/4 inch choke at a stabilized flow rate of 2,642 MCFPD. An additional zone was perforated and tested gas on a 1/4 inch choke at a stabilized flow rate of 1,836 MCFPD. The combined test rate from the two zones is approximately 4,500 MCFPD. Gas sales commenced on July 25, 2007. Aspen has a 30.0% operated working interest in this well.

       The Reason Farms #18-1 was drilled in June 2007 to a depth of 7,200 feet and was plugged and abandoned.

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     The Heidrick #11-2 well was drilled in May 2007 to a depth of 8,300 feet and encountered approximately 145 feet of potential gross gas pay in several intervals in the Forbes formation. One of these intervals was perforated and tested gas on a 1/4 inch choke at a stabilized flow rate of 5,047 MCFPD with a flowing tubing pressure of 3,490 psig and a flowing casing pressure of 3,760 psig. The shut in tubing pressure was 3,700 psig and the shut in casing pressure was 3,850 psig. Gas sales commenced on June 6, 2007. Aspen has a 41.60% operated working interest in this well before payout and a 46.55% operated working interest after payout.

      This was the fifth successful gas well out of six attempts by Aspen in this field.

     Aspen has successfully drilled 8 gas wells out of 10 attempts in this field during the last 4 fiscal years. These wells produce from multiple horizons in the Kione and Forbes formation from depths ranging from 1,700 feet to 5,000 feet. Aspen has operated working interests in these wells ranging from 21% to 36%.

     The Johnson Unit #12 well was drilled to a depth of 4,700 feet and encountered potential gas pay in several intervals in the Forbes formation. Production casing was run based on favorable mud log and electric log responses. One of these Forbes intervals was perforated and tested gas on a 3/16 inch choke at a stabilized rate of 141 MCFPD. Gas sales commenced on October 27, 2006. We have a 36% operated working interest in this well.

     In February 2007, we purchased from Nautilus Poplar, LLC, a non-operating working interest in certain oil producing assets encompassing 22,600 acres in the East Poplar Unit and the Northwest Poplar Field in Roosevelt County, Montana located in the Williston Basin. These properties contain a total of 33 producing oil wells, and 7 salt-water disposal wells. Current production is 230 gross BOPD from the Charles “B” reservoir. Our interest in revenues from the Poplar Field will remain at 12.5% of the total interest acquired by Nautilus (about a 10% net revenue interest based on an average 80% NRI) until Aspen receives a return of 110% of its investment. Thereafter, Aspen’s interest will be reduced to 10% of that acquired by Nautilus (approximately an 8.0% net revenue interest to Aspen). The crude oil is 40^o API sweet and is readily marketed at the lease boundary. All produced water is disposed within the Unit boundary.

     We believe that the acquisition has provided us with diversification into long-lived oil reserves. There is also upside reserve potential via increased water disposal capacity, re-activation of old wells, water shut off techniques, behind-pipe potential in the Charles A, B, & C, and drilling potential in the Mission Canyon and Nisku. This acquisition also provides ownership in 3-D seismic data over 22,600 acres. We do not expect to realize any material revenue from this acquisition for the first two years.

     Aspen will pay 12.5% of the costs for a 10% working interest in the project. During the first year, Aspen will also receive 12.5% of the net revenues (after deduction for royalties, taxes, operating expenses, etc.) until 110% payout, at which time Aspen’s working interest reverts to 10%. After the first year, even if 110% payout has not occurred, Aspen will only pay 10% of the costs and receive 12.5% of the net revenues until 110% payout. After 110% payout, Aspen will have a 10% working interest and receive 10% of the net revenues.

     The initial cost to Aspen for its 12.5% before payout working interest (including its share of the acquisition costs) was approximately $1,450,000, which is approximately $1,075,000 after deduction of $375,000 (12.5% of the $3,000,000 loan proceeds obtained by Nautilus in connection with the purchase), with an additional $400,000 of anticipated capital expenditures during the first year. Aspen funded its participation in this project with a combination of bank debt of $600,000, cash on hand, and the sale of approximately 100,000 shares of UR Energy stock (which yielded about $330,000). Closing of this acquisition occurred on February 13, 2007.

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     The following table sets forth the results of our drilling activities during the fiscal years ended June 30, 2006 and 2007:

Aspen did not drill any development wells during the past three fiscal years, or subsequently.

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, 2007 and 2006, and the average sales prices, average production costs and direct lifting costs per unit of production.

¹ Production costs include 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.

Gross and Net Productive Gas Wells, Developed Acres, and Overriding Royalty Interests

     Leasehold Interests - Productive Wells and Developed Acres: The tables below set forth Aspen's leasehold interests in productive and shut-in gas wells, and in developed acres, at June 30, 2007:

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¹ A net well is deemed to exist when the sum of fractional ownership working intetests 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.

¹ Consists of acres of 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 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 frractional 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, 2007:

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¹ Consists of acres spaced or assignable to productive wells.

     Leasehold Interests Undeveloped Acreage: The following table sets forth Aspen's leasehold interest in undeveloped acreage at June 30, 2007:

     We have entered into a series of gas sales contracts with Enserco. In each of the contracts, Enserco was required to purchase the stated quantities at stated prices, less transportation and other expenses. The contracts contain monetary penalties for non-delivery of the gas. The following table sets forth some additional information about those contracts:

We expect to have sufficient gas available for delivery to Enserco from anticipated production from our California fields. Aspen’s sales of natural gas under the contracts qualify for the “Normal Purchases and Normal Sales” exception in paragraph 10(b) of FAS 133. The contract is a normal industry sales contract that provides for the sale of gas over a reasonable period of time in the normal course of business.

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     We are currently the operator of 63 gas wells, have a non-operated interest in 21 additional gas wells, and have a non-operating working interest in approximately 33 oil wells in Montana. In February 2007 we announced plans to drill approximately 9 gas tests in the Sacramento Valley gas province of northern California and 2 oil tests in Kern County, California.

     As of the date of this report, of these 63 gas wells one is in the process of drilling, and none of the oil wells are currently in the process of drilling.

     We have a proposed drilling budget for the period July 2007 through June 2008. The budget includes drilling eight gas wells in the Sacramento gas province of northern California and one oil well test in the San Joaquin Basin near Bakersfield, California. Our share of the estimated costs to complete this program is set forth in the following table:

     Cecil Engineering, Inc. evaluated our oil and gas reserves attributable to our properties at June 30, 2007. 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 on 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. Estimat es 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 oil and 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.

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     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, 2007 and 2006. See Note 6 to the Consolidated Financial Statements and the above discussion.

Estimated Proved Reserves

     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 6 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 during the fiscal year ended June 30, 2007, or subsequently thereafter.

     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 fro m 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.

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     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 month-to-month lease agreement on January 1, 2005 for a lease rate of $1,261 per month.

     We entered into a lease agreement for our Bakersfield, California office, which consists of approximately 546 square feet. The Bakersfield, California lease payments are $901-$934 per month over the term of the lease, which expires July 31, 2008.

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, 2007, or any subsequent period.

ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

     Our common stock is quoted on the Over-the-Counter Bulletin Board (“OTCBB”) under the symbol "ASPN". The OTCBB rules provide that companies not current in their reporting requirements under the Securities Exchange Act of 1934 will be removed from the quotation service. At present and at June 30, 2007 and June 30, 2006, we believe that we were in full compliance with these rules.

     The table below sets forth the high and low closing prices of the Company’s Common Stock during the periods indicated as reported by the Internet source Yahoo Finance (http://finance.yahoo.com). The quotations reflect inter-dealer prices without retail mark-up, mark-down or commission and may not reflect actual transactions. The market data and dividends for 2007 and 2006 are shown below:

     As of June 30, 2007, there were approximately 1,046 holders of record of our Common Stock. This does not include an indeterminate number of persons who hold our Common Stock in brokerage accounts and otherwise in ‘street name.’

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     Holders of common stock are entitled to receive such dividends as may be declared by Aspen’s Board of Directors. On November 8, 2006, the Company declared a cash dividend in the amount of $0.05 per share. A total of $357,981 was paid to the shareholders on December 6, 2006, as determined by shareholders of record as of November 20, 2006. Decisions concerning dividend payments in the future will depend on income and cash requirements. 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, 2007.

¹ This does not include options held by management and directors that were not granted as pursuant to a compensation plan or compensation arrangement. In each case, the disclosure refers to options or warrants unless otherwise specifically stated.

Recent Sales of Unregistered Securities – Item 701 Disclosure:

     The following sets forth information regarding sales of unregistered securities during the June 30, 2007 fiscal year and subsequently as required by Item 701 of Regulation S-B.

On August 11, 2006, our chairman, R. V. Bailey, exercised options for 50,000 shares of our common stock granted March 14, 2002, at an average price of $0.57 per share. Mr. Bailey paid us $28,500 to exercise his options on the 50,000 shares.

(a) The options were exercised on August 11, 2006, to purchase 50,000 shares of our common stock.

(b) No underwriter, placement agent, or finder was involved in the transaction. The Chairman is an accredited

(c) The total exercise price for the options was $28,500, which was paid in cash. No underwriting discounts or commission were paid.

(d) We relied on the exemption from registration provided by Section 4(2) and 4(6) under the Securities Act of 1933 for this transaction and Regulation D for the issuance. We did not engage in any public advertising or general solicitation in connection with this transaction, and we provided the accredited investor with disclosure of all aspects

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of our business, including providing the accredited investor with our reports filed with the Securities and Exchange Commission, our press releases, access to our auditors, and other financial, business, and corporate information. Based on our investigation, we believe that the accredited investor obtained all information regarding Aspen Exploration it requested, received answers to all questions it (and its advisors) posed, and otherwise understood the risks of accepting our securities for investment purposes.

(e)      The common stock issued in this transaction is not convertible or exchangeable.

(f)      We used the proceeds for working capital, as well as expenses of drilling and (when warranted) completing oil and gas wells.

On August 14, 2006, an employee performed a cashless exercise of an option which resulted in an acquisition of 17,000 shares of our common stock. The option to acquire 17,000 shares was originally granted March 14, 2002, at an exercise price of $0.57 per share.

(a)      The options were exercised on August 14, 2006, to purchase 17,000 shares of our common stock. The option holder exercised options to acquire 17,000 shares in the cashless exercise which had a value of $9,690 by surrendering 2,019 shares of Aspen’s common stock with a fair value based on a ten-day average bid price immediately prior to the exercise date of $4.80.

(b)      No underwriter, placement agent, or finder was involved in the transaction. The employee is an accredited investor.

(c)      The total exercise price for the options was $9,690, which was paid by surrendering 2,019 shares to purchase 17,000 shares. No underwriting discounts or commission were paid.

(d)      We relied on the exemption from registration provided by Section 4(2) under the Securities Act of 1933 for this transaction and Regulation D for the issuance. We did not engage in any public advertising or general solicitation in connection with this transaction, and we provided the accredited investor with disclosure of all aspects of our business, including providing the accredited investor with our reports filed with the Securities and Exchange Commission, our press releases, access to our auditors, and other financial, business, and corporate information. Based on our investigation, we believe that the accredited investor obtained all information regarding Aspen Exploration it requested, received answers to all questions it (and its advisors) posed, and otherwise understood the risks of accepting our securities for investment purposes.

(e)      The common stock issued in this transaction is not convertible or exchangeable.

(f)      We received no proceeds from the exercise of this transaction.

On September 11, 2006, we granted our then newly appointed non-employee director an option to purchase 10,000 shares of Aspen common stock.

     Aspen appointed Kevan B. Hensman a director of Aspen effective September 11, 2006. In connection with that appointment, Aspen granted Mr. Hensman an option to purchase 10,000 shares of Aspen common stock.

(a)      On September 11, 2006, we issued an option to purchase 10,000 shares of Aspen’s common stock to Kevan B. Hensman. The options are exercisable at $3.70, expire September 11, 2011 and vested immediately.

(b)      No underwriters were involved in this transaction.

(c)      The stock options were issued in consideration of Mr. Hensman joining the board of directors and Aspen received no cash therefore.

(d)      The transaction was exempt from registration under the Securities Act of 1933, as amended by reason of Section 4(2) and 4(6) of the Securities Act of 1933.

(e)      The options are exercisable to purchase shares of common stock as described above.

(f)      No proceeds were received.

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On April 9, 2007, our President and CEO, Robert Cohan, exercised options for 100,000 shares of our common stock granted March 14, 2002, at an average price of $0.57 per share. Mr. Cohan paid $57,000 to exercise his options on the 100,000 shares.

(a)      The options were exercised on April 9, 2007, to purchase 100,000 shares of our common stock.

(b)      No underwriter, placement agent, or finder was involved in the transaction. Mr. Cohan is an accredited investor.

(c)      The total exercise price for the options was $57,000, which was paid in cash. No underwriting discounts or commission were paid.

(d)      We relied on the exemption from registration provided by Section 4(2) and 4(6) under the Securities Act of 1933 for this transaction and Regulation D for the issuance. We did not engage in any public advertising or general solicitation in connection with this transaction, and we provided the accredited investor with disclosure of all aspects of our business, including providing the accredited investor with our reports filed with the Securities and Exchange Commission, our press releases, access to our auditors, and other financial, business, and corporate information. Based on our investigation, we believe that the accredited investor obtained all information regarding Aspen Exploration it requested, received answers to all questions it (and its advisors) posed, and otherwise understood the risks of accepting our securities for investment purposes.

ITEM 6.      MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION OR PLAN OF OPERATION

     The management discussion and analysis and other portions of this report contain forward-looking statements (as such term is defined in Section 21E of the Securities Exchange Act of 1934, as amended). These statements reflect our current expectations regarding our possible future results of operations, performance, and achievements. These forward-looking statements are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995.

     Wherever possible, we have tried to identify these forward-looking statements by using words such as “anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend,” and similar expressions. These statements reflect our current beliefs and are based on information currently available to us. Accordingly, these statements are subject to certain risks, uncertainties, and contingencies, which could cause our actual results, performance, or achievements to differ materially from those expressed in, or implied by, such statements.

     Aspen Exploration Corporation was organized in 1980 for the purpose of acquiring, exploring and developing oil and gas properties. Since 1996, we have focused our efforts on the exploration, development and operation of natural gas properties in the Sacramento Valley of northern California, and in 2007 we acquired interests in oil properties in Montana. Our business activities are primarily focused in two separate aspects of the oil and gas industry:

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     We are currently the operator of 63 gas wells in the Sacramento Valley of northern California. Additionally, we have a non-operated interest in 21 gas wells in the Sacramento Valley of northern California and non-operating working interest in approximately 33 oil wells in Montana When appropriate we may engage in business activities related to the exploration and development of other minerals and resources.

     Where possible, we attempt to be the operator of each property in which we invest. We believe that our knowledge of drilling and operating wells in the Sacramento Valley allows us to maximize the potential return of each property. In addition, the other working interest owners are obligated to pay us fees pursuant to the “overhead reimbursement” provisions of the COPAS Accounting Procedures which are included as an attachment to the operating agreements. These accounting procedures define the overhead expenses that are charged to the joint accounts and permit us to charge some expenses (such as “salaries, wages and Personal Expenses of Technical Employees directly employed on the Joint Property” and drilling expenses) directly to the joint interest owners. In almost all cases, Aspen also charges a general monthly producing overhead rate per well. We do not recognize these fees rec eived from the joint interest owners as revenues; rather they are offset against (and are a deduction from) our general and administrative expenses as reflected in our statement of operations. During the fiscal year ended June 30, 2007, these administrative charges to the properties help cover approximately 37.6% of our selling, general and administrative expenses.

     We believe the following critical accounting policies affect our most significant judgments and estimates used in the preparation of our Consolidated Financial Statements.

     Our estimates of oil and natural gas reserves, by necessity, are projections based on an interpretation of geologic and engineering data. 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 assu mptions 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.

     Many factors will affect actual future net cash flows, including:

·     the amount and timing of actual production;
·     supply and demand for oil and natural gas;
·     curtailments or increases in consumption by purchasers; and
·     changes in governmental regulations or taxation.

     We have entered into a contract for sale and purchase of natural gas with Enserco Energy Inc. The original, master contract is dated November 1, 2005. Aspen and Enserco have continuously renewed this contract since then. Aspen’s sales of natural gas under the Enserco Contract qualify for the “Normal Purchases and Normal Sales” exception in paragraph 10(b) of FAS 133. The Enserco Contract is a normal industry sales contract that provides for the sale of gas over a reasonable period of time in the normal course of business. The contract contains net settlement provisions should Aspen fail to deliver natural gas when required under the Enserco Contract. Those provisions are mutual and establish the sole and exclusive remedy of the parties in the event of a breach of a firm obligation to deliver or receive natural gas as agreed.

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     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. All capitalized costs are depleted on a composite units-of-production method based on estimated proved reserves attributable to the oil and gas properties owned by Aspen. Costs associated with production and general corporate activities are expensed in the period incurred. When the Company acts as operator of our producing wells, we receive management fees for these services, which serve to offset our selling, general, and administrative expenses. 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:

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 Statement of Financial Accounting Standard (“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.

     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, “Asset Retirement Obligations”. 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. The increase in the asset will be amortized over time and recognize accretion expense in connection with the discounted liability over the remaining life of the respective well. Any asset retirement costs capitalized pursuant to Statement 143 are subject to the full cost ceiling limitation under Rule 4-10(c)(4) of Regulation S-X. 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 risk-free rate of 8%. 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.

     The Company computes income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes”. SFAS No. 109 requires an assets and liability approach which results in the recognition of deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the Company’s financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not. Additionally, the Company’s federal and state income tax returns are generally not filed before the financial statements are prepared; therefore the Company estimates the tax basis of its asset and liabilities at the end of each calendar year as well as the effects of tax rate changes, tax credits, and tax credit carryforwards. A valuation allowance is recognized if it is determined that deferred tax assets may not be fully utilized in future periods. Adjustments related to differences between the estimates used and actual amounts reported are recorded in the period in which income tax returns are filed. These adjustments and changes in estimates of asset recovery could have an impact on results of operations. Due to uncertainties involved with tax matters, the future effective tax rate may vary significantly from the estimated current year effective tax rate.

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     We adopted SFAS No. 123(R) beginning July 1, 2006. Prior to July 1, 2006, the Company accounted for these plans under the recognition and measurement provisions of Accounting Principles Board ("APB") Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations, as permitted by Statement of Financial Accounting Standards("SFAS") No. 123, Accounting for Stock-Based Compensation. No stock-based employee compensation expense was recognized in the Company's Consolidated Statement of Operations prior to July 1, 2006, as all options granted under the Company's stock-based compensation plans had an exercise price equal to the market value of the underlying common stock on the date of grant. Effective July 1, 2006, the Company adopted the fair value recognition provisions of SFAS No. 123 (R), Share Based Payment, using the modified-prospective transition method as described in SFAS No .. 148, Accounting for Stock-Based Compensation - Transition and Disclosure. Under this method, compensation cost recognized in fiscal 2007 is the same as that which would have been recognized had the recognition provisions of Statement 123(R) been applied from its original effective date.

     The Company has classified all investments as Trading Securities in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities. These securities are marked to market each period with the realized and unrealized gain or loss recorded in the statement of operations.

     At the outset of our 2007 fiscal year we expected our natural gas production to increase during this fiscal year due to recent drilling successes. Total production for the year will depend on the number of wells successfully completed, the date they are put on line, their initial rate of production, and their production decline rates. During the last fiscal year,

gas sales decreased approximately 14.1% from 696,105 Mcf to 597,660 Mcf;

oil sales increased to 3,986 barrels due to the acquisition of operating interests in Poplar fields in Montana; and

reserves have increased approximately 26% to 3,480,000 net equivalent Mcf (MCFEQ) from 2,762,000 MCFEQ.

     During the last fiscal year, the average price received for our gas production decreased approximately 10% from $7.76 per Mcf to $7.00 per Mcf and the costs of production and accretion, depletion, depreciation, and amortization, increased 36%.

     Over the past five years we have been able to replace the majority of our produced reserves and maintain our yearly natural gas production through the drilling of new wells and the acquisition of producing properties which have offset the oil and gas we produce. These additions resulted primarily from 8 newly drilled gas wells and the acquisition of several oil wells in Montana in which we hold interests. Such wells added a total of 874,109 Mcf of gas reserves, of which 75,063 Mcf were produced prior to June 30, 2007, and 132,072 barrels of oil, of which 3,877 were produced prior to June 30, 2007. Management uses the measurement of our produced reserves to help measure the success of our exploration and development activity. Where reserves are replaced in an amount greater than production, it is a sign that we are continuing our exploration and development activity successfully. A one-year decline or increase may not be important to investors, but seeing a decline or increase over a several year period is a trend worthy of noting, both internally by management and externally by investors.

     Our ability to replace reserves, dissipated through production or recalculation, will depend largely on how successful our drilling and acquisition efforts will be in the future. While we cannot predict the future, our historic success drilling ratio over the past 6 years has been 84%. With the use of 3-D seismic and well control data, interpreted by our geological and geophysical consultants, we feel we can manage our dry hole risk adequately.

     The prices that we receive for the oil and natural gas (including natural gas liquids) produced are impacted by many factors that are outside of our control. Historically, these commodity prices have been volatile and we

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expect them to remain volatile. Prices for oil and natural gas are affected by changes in market demands, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, the world political situation, basis differentials and other factors. As a result, we cannot accurately predict future oil, natural gas and NGL (natural gas liquids) prices, and therefore, we cannot determine what effect increases or decreases in production volumes will have on future revenues.

     On regulatory and operational matters, we actively manage our exploration and production activities. We value sound stewardship and strong relationships with all stakeholders in conducting our business. We attempt to stay abreast of emerging issues to effectively anticipate and manage potential impacts to our operations.

     The average price received during fiscal 2007 for our natural gas was approximately $7.00 per MMBTU as compared to $7.74 per MMBTU during fiscal 2006. In order to reduce the risk of natural gas price fluctuations, we have entered into a series of gas sales contracts with Enserco as described above in Item 2 – Properties – Gas Delivery Commitments, set forth above.

     We have historically financed our operations with internally generated funds, limited borrowings from banks and third parties, and farmout arrangements, which permit third parties (including some related parties) to participate in our drilling prospects. During the year ended June 30, 2007, we also borrowed $600,000 to purchase an interest in the Poplar Field and became obligated for an additional $375,000 indebtedness as part of that purchase. During our fiscal 2007 year, we have also received approximately $600,000 from the sale of investment securities that we owned, as compared to $116,000 in fiscal 2006.

     Our principal uses of cash are for operating expenses, the acquisition, drilling, completion and production of prospects, the acquisition of producing properties, working capital, servicing debt and the payment of income taxes.

     During the 2007 fiscal year, we used more than $2.4 million of cash in our operations, investing activities and financing activities as compared to those activities generating more than $3.0 million during the same period of our 2006 fiscal year. This resulted from reduced cash generated from operations and an increase in cash used in investing activities offset by a small reduction in cash used in financing activities, as described below.

     We generated cash of $2.5 million from operations for the year ended June 30, 2007, as compared to $6.9 million in cash generated from operating activities for the year ended June 30, 2006. This negative change of approximately $4.4 million was due to a number of factors, including a reduction of our net income of approximately $2 million (as discussed below in results of operations), and a use of cash to retire current liabilities (which were more than $6 million at June 30, 2006 as compared to less than $5 million at June 30, 2007). Our current liabilities decreased by about $1.4 million during the 2007 period as compared to an increase in current liabilities of approximately $4.5 million during the 2006 period.

     Our investing activities used cash to increase capitalized oil and gas costs and office equipment of $5.1 million during the 2007 fiscal year as compared to $4.3 million in 2006. Investing activities during 2007 were for oil and gas property acquisition ($1.1 million), lease acquisition, seismic work, intangible drilling and well workovers and equipment ($4 million), and support equipment of ($89,000). These expenditures are net of the sale of interests in wells to be drilled that will be charged to third party investors.

     Cash provided by financing activities decreased approximately $192,500 from $411,500 in 2006 to $219,000 during the year ended June 30, 2007. This decrease was due primarily to the payment of $357,981 in cash dividends in 2007, where no dividends were paid in 2006. In addition, employees exercised stock options totaling $411,500 in 2006 compared to only $85,500 in 2007. These decrease in cash from financing activities during the 2007 fiscal year were partially offset by the net proceeds of $492,000 in long-term debt (borrowings less repayments), which provided a portion of the cash used to acquire our oil interests in Montana.

     Our working capital surplus (current assets less current liabilities) at June 30, 2007, was $2.04 million, which reflects a $1.8 million decrease from our working capital at June 30, 2006. As detailed above, this decrease was due primarily to our negative cash flow of more than $5 million for investing activities and use of cash to significantly reduce our current liabilities.

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     We have a proposed drilling, completion and construction budget for the period July 2007 through June 2008. The budget includes drilling eight gas wells in the Sacramento gas province of northern California and one oil well test in the San Joaquin Basin near Bakersfield, California. Our share of the estimated costs to complete this program is set forth in the following table.

     We anticipate that our working capital and anticipated cash flow from operations and future successful drilling activities will be sufficient to finance our planned drilling and operating expenses and to pay our other obligations. As discussed herein, this is dependent, in part, on maintaining or increasing our level of production and the national and world market maintaining its current prices for our oil and gas production.

     If our drilling efforts are successful, the anticipated increased cash flow from the new gas discoveries, in addition to our existing cash flow, should be sufficient to fund our share of planned future completion and pipeline costs.

     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 month-to-month lease agreement beginning January 1, 2005 for a lease rate of $1,261 per month. The Bakersfield, California office has 546 square feet and a monthly rental fee of $901 to $934 over the term of the lease. The two-year lease expires July 31, 2008. Rent expense for the years ended June 30, 2007 and 2006 was $26,264 and $22,817, respectively.

Employment Contracts and Termination of Employment and Change in Control Arrangements

     Mr. Bailey: Effective May 1, 2003 the Company entered into an 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, the Company has 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.

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     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, 2007. During 2007 or thereafter, Mr. Bailey may purchase the vehicle for $500.

     The Company 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, the Company 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: In April 2005 Mr. Cohan’s employment agreement was renewed to December 31, 2008 with a salary increase to $160,000 per year. Other benefits and duties will remain the same as the previous employment contract.

     The following table sets forth certain items from our Consolidated Statements of Operations as expressed as a percentage of total revenues, shown by year for fiscal 2007 and 2006:

     To facilitate discussion of our operating results for the years ended June 30, 2007 and 2006, we have included the following selected data from our Consolidated Statements of Operations:

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     In general, our operations during 2007 have been adversely affected by reduced production and average prices received for our production, together with increasing costs of production and accretion, depletion, depreciation, and amortization, and increased general and administrative expenses. Aspen is aware of these changes, but believes that some of the negative trend in cash flow is temporary as a result of the addition of our Poplar Field properties acquired in the current year. As previously noted, oil and gas prices are subject to national and international pressures, and Aspen has no control over those prices.

     For year ended June 30, 2007, our operations continued to be focused on the production of oil and gas, and the acquisition of producing oil and gas properties in California and we also acquired properties in Montana. Our gas production decreased from 696,000 Mcf sold during the year ended June 30, 2006, to 598,000 Mcf sold during 2007 (a decrease of approximately 14%). As a result of our decreased production and decreased prices during the 2007 fiscal year ($7.00 per Mcf during 2007 as compared to $7.74 per Mcf during the same period in 2006), our revenues from oil and gas sales decreased during 2007 by approximately $980,000 from approximately $5.4 million (2006) to approximately $4.4 million (2007).

     Oil and gas production costs increased approximately 56%, as compared to 2006, from approximately $537,000 to more than $837,000. The increase can be attributed to the addition of 8 gross operated gas wells, from 51 wells to 59 wells and our percentage working interests in these wells were somewhat higher than the average of wells owned at June 30, 2006. The increase was also due to the addition of 33 producing oil wells and 7 saltwater disposal wells in Montana. Equipment rental and water disposal fees increased due to the addition of compressors and increased water production in our more mature wells. Additionally, all of the costs for the service companies who perform work on Aspen's wells increased dramatically during the past twelve months.

     Depletion, depreciation and amortization expense increased 30%, from approximately $1.6 Million for the year ended June 30, 2006 as compared to more than $2 million during 2007. DD&A expense per net equivalent Mcf produced increased from $2.31 to $3.25. This increase can be attributed to the continued level of investment in oil and gas-producing properties, without an immediate corresponding increase in proved reserves.

     Our general and administrative expenses, net of management fees, increased 110%, from approximately $406,000 during the year ended June 30, 2006 to approximately $851,000 during 2007 because of increased audit and accounting fees, officers salaries including a non-cash charge of $109,700 as a result of recognition of additional share-based compensation expense in accordance with the implementation of FAS 123(R), a non-cash charge of $23,500 for stock options issued to a Director, and the amortization of deferred compensation for the initiation of an investor relations service of $119,233 settled in shares of our common stock in the prior year.

     Central to the issue of success of the twelve months operations ended June 30, 2007 is the discussion of changes in oil and gas sales, volumes of natural gas sold and the price received for those sales. We present them here in tabular form:

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     Oil and gas revenue and volumes sold of our product have shown a general decrease during fiscal 2007. As the table above notes, gas revenue has decreased approximately 23.5% when comparing the year ended June 30, 2007 and 2006, while oil revenue increased 1528% due to the acquisition of the Poplar Field. Gas volumes sold decreased approximately 14%, while the price received for our product decreased 10%. Oil and NGL volume increased 2165%, due to the property acquisition, while the price per barrel decreased 28%.

     When the Company acts as operator for our producing wells, we receive management fees for these services, which serve to offset our SG&A expenses. When comparing SG&A for 2007 and 2006, costs increased by $473,515, or 53%, due primarily to increases in accounting and audit fees, promotional expense and corporate reporting expense and the issuance of equity instruments as compensation for services, while management fees remained consistent. As a result, management fees as a percentage of SG&A decreased 19.8% for the period ending June 30, 2007 compared to 2006.

       Results of operations and net income (loss) before income taxes are presented in the following table:

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¹ Operating income is oil and gas sales less oil and gas production costs, depreciation, depletion and amortization, and selling, general and administrative expenses.

     Income before taxes decreased from approximately $4 million for the year ended June 30, 2006 to $1.5 million in 2007 primarily due to lower production and prices, increased operating expenses, and decreased gains on trading securities.

     Our future success in the oil and gas industry will depend on the cost of finding oil or gas reserves to replace our production, the volume of our production and the prices we receive for sale of our production. These factors are subject to all of the risks associated with operations in the oil and gas industry, many of which are beyond our control.

     Investing in shares of our common stock is highly speculative and involves a high degree of risk. In addition to the other information included in this report, you should carefully consider the risks described below before purchasing shares of our common stock. If any of the following risks actually occur, our business, financial condition and results of operations could materially suffer. As a result, the trading price of our common stock could decline, and you might lose all or part of your investment. These factors include, but are not limited to:

     Oil and gas production operations are inherently risky and our ability to succeed in that business depends on a number of factors. Our revenues, profitability and future growth and reserve calculations depend substantially on three different but inter-related factors:

     These factors are interrelated and are dependent in part on world markets for oil and natural gas and other energy fuels. When prices increase for oil or natural gas because of world economic or political factors, our access to drilling rigs and other necessary supplies become more difficult and expensive because of competition from other producers. These are described in more detail in the next several risk factors.

     Oil and gas prices are volatile, and a decline in oil and natural gas prices is likely to have a material adverse impact on our business. As is evidenced by the average prices received for our oil and natural gas production over the last three fiscal years ($6.23 per MMBTU during 2005; $7.74 per MMBTU during 2006; and $7.00 per MMBTU during 2007), the prices that the market offers for our oil and natural gas production are volatile and are dependent in large part on factors beyond our control, including those described below. Higher prices result in higher revenues for the same level of production; conversely, lower prices result in lower revenues. Price volatility impacts our cash flow and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and gas that we can produce e conomically. Among the factors that can cause price fluctuations are:

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     Market conditions or operational impediments may hinder our access to crude oil and natural gas markets or delay our production. Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and refineries owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm o ur business. We may be required to shut-in wells for a lack of a market or because of inadequate or a lack of natural gas pipelines, gathering system capacity, processing facilities or refineries. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver the production to market.

     Our business model depends on our ability to find, develop and acquire oil and gas reserves. To maintain or increase production levels, we must locate and develop or acquire new oil and gas reserves to replace those depleted by production. Without successful exploration, exploitation or acquisition activities, our reserves, production and revenues will decline. There are a number of factors associated with our ability or inability to replace and increase our oil and natural gas reserves which may adversely impact our operations:

     We may be required to write-down the carrying value of our oil and gas properties when oil or gas prices are low, or there are substantial downward adjustments to our estimated proved reserves, increases in estimates of development costs or deterioration in exploration or production results. We capitalize costs to acquire, find and develop our oil and gas properties under the full cost accounting method. If net capitalized costs of our oil and gas properties exceed fair value, we must charge the amount of the excess to earnings. We review the carrying value of our properties on a quarterly basis, and at any other time when events or circumstances indicate a review is necessary, based on prices in effect as of the end of the reporting period. Once incurred, a write-down of oil and gas properties is not reversible at a later date even if oil or gas prices increase.

     Actual quantities of recoverable of oil and gas reserves may be lower than our estimates. Estimating reserves of oil and gas is complex. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires certain economic assumptions, such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes

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and availability of funds, some of which are mandated by the SEC. The accuracy of a reserve estimate is a function of quality and quantity of available data, interpretation of that data, and accuracy of various mandated economic assumptions.

     Any significant variance could materially affect the quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of development and exploration and prevailing oil and gas prices.

     In accordance with requirements of the Securities and Exchange Commission, we base the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.

     We have limited control over the activities on properties that we do not operate. Although we operate many of the properties in which we have an interest, other companies operate some of the properties, including all of the wells in Montana where we hold working interests. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund their operation. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could have a material adverse effect on the realization of our targeted returns or lead to unexpected future costs.

     We may incur losses as a result of title deficiencies. We purchase working and revenue interests in the oil and natural gas leasehold interests upon which we will perform our exploration activities from third parties or directly from the mineral fee owners. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. Title insurance covering mineral leaseholds is not generally available and often we forego the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease until the drilling block is assembled and ready to be drilled. As is customary in our in dustry, we rely upon the judgment of oil and natural gas lease brokers or independent landmen who perform field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest. Where, despite our efforts, title deficiencies exist, we risk loss of some or all of our interest in the affected properties.

     We sell a significant amount of our production to two customers. We generally sell our oil and gas production to a limited number of companies. In fiscal 2007 and 2006 (as in prior years) we obtained a majority of our revenues from sales to Calpine Corporation and Enserco Energy, Inc., (15% and 77%, respectively). Calpine’s ongoing bankruptcy could result in failure of Calpine to continue purchasing natural gas from us and may result in Calpine’s inability to pay for the natural gas purchased. Because we believe that oil and gas sales are primarily market driven and are not dependent on particular purchasers we do not believe the loss of these customers would adversely impact our revenues. However, we cannot guarantee that the loss of either of these major customers would not negatively impact our business operations and revenues.

     Hedging transactions may limit our potential gains. We have entered into certain price hedging arrangements with respect to a significant portion of our expected production. Such transactions may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which our production is less than expected, there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement, or the counterparties to our hedging agreements fail to perform under the contracts.

     The oil and gas business involves many operating risks that can cause substantial losses; insurance may not protect us against all of these risks. Among the risks faced by all operators in the oil and gas industry are the risks of fires, explosions, blow-outs, uncontrollable flows of oil, gas, formation water or drilling fluids, natural disasters; pipe or cement failures, casing collapses, embedded oilfield drilling and service tools, abnormally pressured formations, major equipment failures, including cogeneration facilities, and environmental hazards such as oil spills, natural gas leaks, pipeline ruptures and discharges of toxic gases. If any of these events occur, we could incur substantial losses as a result of injury or loss of life, severe damage or destruction of property, natural resources and equipment, pol lution and other environmental damage, investigatory and clean-up responsibilities, regulatory investigation and penalties, suspension of operations, and repairs to resume operations.

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     If we experience any of these problems, our ability to conduct operations could be adversely affected. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect us. In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We do not carry business interruption insurance. We may elect not to carry insurance if our Management believes that the cost of available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations. While we intend to obtain and maintain appropriate insurance coverage for these risks, there can be no assurance that our operations will not expose us to liabilities exceeding such insurance coverage or to liabilities not covered by insurance.

     We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business. Our development, exploration, production and marketing operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Under these laws and regulations, we could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and crimi nal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations oppose certain drilling projects and/or access to prospective lands.

     Our actual results may differ materially from our estimates and projections. In planning drilling programs, we either estimate costs and the likelihood of success, or we review estimates prepared by others. Furthermore, the preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and related disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable l ikelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from these estimates and assumptions used in preparation of its financial statements. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities, the related present value of estimated future net cash flows therefrom, and the costs to develop and abandon oil and gas properties.

      Competitive industry conditions may negatively affect our ability to conduct profitable operations.   Competition in the oil and gas industry is intense, particularly with respect to the acquisition of producing properties and proved undeveloped acreage. Major and independent oil and gas companies actively bid for desirable oil and gas properties, as well as for the equipment and labor required to operate and develop their properties. Many of our competitors have financial resources that are substantially greater, which may adversely affect our ability to compete within the industry.

     The loss of key personnel could adversely affect our business. We depend to a large extent on the efforts and continued employment of our executive Management team and other key personnel. The loss of the services of these or other key personnel could adversely affect our business. We do maintain key man insurance on Robert A. Cohan, President and CEO, in the amount of $1,000,000. Our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, landmen and other professionals. Competition for many of these professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.

     We have made, and will need to continue to make substantial financial and man-power investments in order to assess our internal controls over financial reporting and our internal controls over financial reporting may be found to be deficient. Section 404 of the Sarbanes-Oxley Act of 2002 requires management to assess our internal controls over financial reporting and requires auditors to attest to that assessment. Current regulations of the Securities and Exchange Commission, or SEC, will require us to include this assessment and attestation in our annual report commencing with the annual report we file with the Securities and Exchange commission for our fiscal year ended June 30, 2008. We have expanded our staff through the use of outside consultants to prepare for the Section 404 requirements, and we will likely ha ve to add additional staff to obtain an unqualified assessment. We may also have to invest in additional accounting and software systems. If we are unable to favorably assess the effectiveness of our internal control over financial reporting when we are required to, or if our

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independent auditors are unable to provide an unqualified attestation report on such assessment, we may be required to change our internal control over financial reporting to remediate deficiencies. In addition, investors may lose confidence in the reliability of our financial statements causing our stock price to decline.

     Our common stock has and may continue to experience price volatility. Our common stock is traded on the OTC Bulletin Board. Since July 1, 2006, our stock has traded as high as $4.09 per share, and as low as $2.23 per share. During that period, our trading volume has ranged from as low as 1,000 shares per day to 80,000 shares per day. Until a larger secondary market for our common stock develops, the price of and trading volume for our common stock will likely continue to fluctuate substantially. The price of and trading volume for our common stock is impacted not only by our performance and announcements, but also by general market conditions and other factors that are beyond our control or influence and which may be unrelated to our performance.

     We do not have any off balance sheet accounting arrangements. We do enter into joint ventures and operating agreements for the ownership and drilling of wells with third parties. Aspen’s balance sheet only reflects its own interest in these arrangements, however, and has no interest in any ownership by third parties (some of whom are related parties).

     In June 2006, the FASB issued Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, and provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. This Interpretation is effective for fiscal years beginning after December 15, 2006. The Company is currently assessing the potential impact of this Interpretation on its financial statements. The Company has evaluated the effects of adopting this interpretation as immate rial to its financial statements accompanying this annual report on Form 10-KSB.

     In September 2006, Statement of Financial Accounting Standards (SFAS) No. 157, Fair Value Measurements was issued by the Financial Accounting Standards Board (FASB). This statement defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 will become effective for the Company’s fiscal year beginning after November 15, 2007, and the Company is currently assessing the potential impact of this Statement on its financial statements.

     In September 2006, the SEC issued Staff Accounting Bulletin (“SAB”) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements. Registrants must quantify the impact on current period financial statements of correcting all misstatements, including both those occurring in the current period and the effect of reversing those that have accumulated from prior periods. This SAB will be applied beginning with the first fiscal year ending after November 15, 2006. The Company has evaluated the effects of adopting SAB No. 108 as immaterial to its financial statements accompanying this annual report on Form 10-KSB.

     In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, which permits an entity to measure certain financial assets and financial liabilities at fair value. The objective of SFAS No. 159 is to improve financial reporting by allowing entities to mitigate volatility in reported earnings caused by the measurement of related assets and liabilities using different attributes, without having to apply complex hedge accounting provisions. Under SFAS No. 159, entities that elect the fair value option (by instrument) will report unrealized gains and losses in earnings at each subsequent reporting date. The fair value option election is irrevocable, unless a new election date occurs. SFAS No. 159 establishes presentation and disclosure requirements to help financial statement users understand the effect of the entity’s election on its earnings, but does not eliminate disclosure requirements of other accounting standards. Assets and liabilities that are measured at fair value must be displayed on the face of the balance sheet. This statement is effective beginning January 1, 2008 and we are evaluating the effects of this pronouncement on our financial statements.

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     The information required by this item begins on page 45 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

     Dismissal of Gordon, Hughes & Banks, LLP. On February 21, 2006, our Board of Directors informed Gordon, Hughes & Banks, LLP (“Gordon Hughes”) that it had dismissed Gordon Hughes as our independent registered public accounting firm effective immediately.

     On February 21, 2006, the Board of Directors informed Hein & Associates LLP (“Hein”), certified public accountants, that such firm was appointed as the Company’s registered accounting firm effective immediately. Gordon Hughes’ report on our financial statements for either of the two prior fiscal years (ending June 30, 2005 and 2004, including interim periods) did not contain an adverse opinion or disclaimer of opinion; neither were such reports qualified as to uncertainty, audit scope, or accounting principles. No report prepared by Gordon Hughes on any subsequent period up to the dismissal of Gordon Hughes as the Company’s independent registered public accounting firm contained an adverse opinion or disclaimer of opinion or were qualified as to uncertainty, audit scope, or accounting principles.

     There were no disagreements with Gordon Hughes on any matters of accounting principles, practices, financial statement disclosure, or auditing scope or procedure. The Company provided Gordon Hughes with a copy of the disclosures set forth in its Form 8-K reporting an event of February 21, 2006 (filed February 22, 2006) and requested Gordon Hughes to furnish to the Company with a letter addressed to the Securities and Exchange Commission stating whether Gordon Hughes agrees with the statements by the Company in this report. Gordon Hughes’ letter was attached as Exhibit 16.1 to that Form 8-K.

     Dismissal of Hein & Associates, LLP. On March 1, 2007, the Board of Directors informed Hein that it had been dismissed as the Company’s independent registered public accounting firm effective immediately. On the same date we informed Gordon Hughes that such firm was reappointed as the Company’s independent registered accounting firm effective immediately.

     During our two most recent fiscal years and subsequently through the date of dismissal, there were no disagreements with Hein on any matter of accounting principles, practices, financial statement disclosure, or auditing scope or procedure which if not resolved to Hein’s satisfaction would have caused Hein to make reference to the subject matter of the disagreement in connection with its principal accounting report on the financial statements for our fiscal year ended June 30, 2007, or any subsequent report. However, as discussed in our annual report for the year ended June 30, 2006, Hein advised us that they were concerned about material weaknesses in our disclosure controls based on several factors, including: corrections to our financial statements and related disclosures that they proposed, the dual functions performed by our president who is also our chief financial officer; the lack of an audit committee; and the lack of sufficient professional accounting personnel at Aspen during the 2006 fiscal year. There is no legal requirement prohibiting our president from serving as both principal executive and financial officer, and Aspen is not subject to a requirement to have an audit committee. As a result of the concerns expressed by our auditors, our president reached the conclusion that, in his opinion as of June 30, 2006, disclosure controls and procedures were not effective.

     In reaching his conclusion our president considered various mitigating factors, noting that formerly Aspen had one consultant serving us on a part-time basis. During the last quarter of our fiscal 2006, we increased our accounting staff to three part-time consultants, including two certified public accountants. Our newly-enlarged staff worked together with Aspen during the last quarter of, and after the end of our fiscal year. Although the president identified material weaknesses as of June 30, 2006, the president observed the synergies and efficiencies developed by the new accounting team working together and with other Aspen personnel during the first quarter of the 2007 fiscal year in preparing Aspen’s financial statements for the 2006 fiscal year-end audit and concluded that the material weaknesses earlier identified had been eliminated during the first quarter of our 2007 fiscal year. The p resident noted that these material weaknesses were addressed, not as a result of any changes in disclosure controls or procedures, but as a result of greater experience working together and with Aspen’s existing personnel.

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Consequently, our president concluded that as of September 30, 2006 and subsequently (as described in Item 8A, below) our disclosure controls and procedures were effective.

(a) Evaluation of Disclosure Controls and Procedures.

     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 our principal executive officer and our principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

      Our management, with the participation of our president (who is our principal executive officer and our principal financial officer) has evaluated the effectiveness of our disclosure controls and procedures as required by Exchange Act Rule 13a-15(b) as of June 30, 2007 (the end of the period covered by this report). Based on that evaluation, our president (serving as our principal executive officer and our principal financial officer) concluded that these disclosure controls and procedures were effective as of such date.

(b) Changes in Internal Controls Over Financial Reporting.

     There were no changes in our internal control over financial reporting during the quarter ended June 30, 2007, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Aspen is still evaluating and implementing additional controls to meet the requirements of Sarbanes-Oxley § 404, and will continue to implement appropriate changes as they are identified.

Not applicable. All required information has been reported herein.

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ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS, COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT

     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 of June 30, 2007. 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. Since we have held no annual meeting since February 25, 1994, the terms of each class of director expires at the next annual meeting of stockholders.

     Each of the directors will be up for reelection at the next annual meeting of stockholders and will continue to serve until his successor is elected and qualified or until his or her earlier death, resignation, or removal. We did not hold an annual meeting during fiscal 2006 or 2007, and we do not expect to hold an annual meeting during fiscal 2008.

     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. None of the directors are involved in, or have been involved in, any legal proceedings of the type that must be disclosed pursuant to Item 401(d) of SEC Regulation S-B. Only one member of the board, Mr. Hensman, can be considered to be an ‘independent director.’

     Robert A. Cohan. Mr. Cohan obtained a Bachelor of Science degree in Geology from the State University College at Oneonta, NY in 1979 and he works for Aspen on a full-time basis. He has approximately 28 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 West Coast Division (now P resident & CEO), 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).

     Kevan B. Hensman became a director of Aspen Exploration Corporation on September 11, 2006. Since April 2002, except for a one-year position as Manager of Paramount Citrus Association, Mr. Hensman has served as an Analyst for Truxtun Radiology Medical Group, LP with the duties of providing financial analysis; performing special projects; and assisting the Practice Administrator in performing various duties and assignments.

     Mr. Hensman was employed by Aera Energy, LLC as its Energy Portfolio Consultant from June 1999 to November 2001. During his tenure, his duties included providing an analysis of gas pricing and supply to upper management and the operation departments; the administration and negotiation of all gas purchase/sales contracts and gas pipeline transportation contracts and agreements; advising business partners on current Governmental

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regulations and legislation; managing the fuel budget; preparing month-, quarter- and year-end reports; and partnering with department heads to prepare the annual plan and budget forecasts.

     Mr. Hensman served as the Planner/Gas Analyst from November 1997 to May 1999 for Texaco Exploration and Production Company. His duties included evaluating the energy markets for gas pricing for the management team and production department; supporting the gas contract administration; negotiating gas contracts for natural gas purchase and sales and pipeline transportation; managing the imbalance account with vendors to minimize the company’s penalty fees; scheduling deliveries of supplies to production operations and projects; budgeting for the yearly plan and five year strategic plan for Kern River Business Unit; completing forecasts; economics evaluations; performing variance reports and month-end reports; managing project completion audits; resolving accounting and budget issues; and preparing month-end and year-end reports with accounting.

     Mr. Hensman served as the Supervisor of Fuel Supply and Acquisition Analyst from February 1991 to October 1997 for Santa Fe Energy/Monterey Resources. Mr. Hensman was responsible for administration and negotiating gas purchase/sales contracts; tracking fuel use; scheduling and balancing on gas pipelines; evaluating energy markets relating to gas pricing for the recommendation of term purchases; supporting annual planning and budget cyclic; economic evaluation of acquisition candidates; and portfolio evaluation.

     Mr. Hensman is not a director of any other public company. In 1999, Mr. Hensman received a Bachelor of Science degree in finance from California State University Bakersfield (CSUB).

     R. V. Bailey. R. V. Bailey obtained a Bachelor of Science degree in Geology from the University of Wyoming in 1956. He has approximately 45 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, b ut currently devotes only a small portion of his time to Aspen’s business.

     The Board of directors held 2 formal meetings during the fiscal year ended June 30, 2006 and one formal meeting during the fiscal year ended June 30, 2007. 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 eight times during fiscal 2006, eight times during fiscal 2007, and one time subsequently.

     Aspen does not have an audit committee, compensation committee, nominating committee, or other committee of the board that performs similar functions. Instead, the entire board acts as the Company’s audit committee and therefore, Aspen does not have a designated an audit committee financial expert.

     Aspen’s board of directors has not adopted a code of ethics because the board does not believe that, given the small size of Aspen and the limited transactions, a code of ethics is warranted.

No Nominating Committee; Procedures by which Security Holders May Recommend Nominees to the Board of Directors; Communications with Members of the Board of Directors:

     As noted above, Aspen does not have a nominating committee. We do not have a nominating committee because our board does not believe that such a committee is necessary given our small size, and because we have not held an annual meeting of shareholders since February 1994, and we have no plans to hold such a meeting. Instead, when a board vacancy occurs, the remaining board members participate in deliberations concerning director nominees.

     For the same reasons stated immediately above, the board of directors has not adopted a formal procedure by which security holders may recommend nominees to the board of directors. However, any shareholder desiring to

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nominate a person to the Board of Directors or communicate directly with any officer or director of Aspen may address correspondence to that person at our offices in Denver, Colorado. Our office staff will forward such communications to the addressee.

     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.

     As of June 30, 2007, 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.

     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 Forms 3, 4 and any amendments thereto furnished to us during the fiscal year completed June 30, 2007 and subsequently, we believe that during the period from July 1, 2006 through August 31, 2007, all filing requirements applicable to our officers, directors and greater-than-ten-percent shareholders were complied with except as set forth in the following paragraph.

     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 two years ended June 30, 2006 and 2007. 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 Aspen subsidiary.