General

The following discussion provides information on the results of operations for the periods ended March 31, 2009 and 2008 and our financial condition, liquidity and capital resources as of March 31, 2009 and June 30, 2008. The financial statements and the notes thereto contain detailed information that should be referred to in conjunction with this discussion.

The profitability of our operations in any particular accounting period will be directly related to the realized prices of gas sold, the type and volume of gas produced and the results of development, exploitation, acquisition, and exploration activities, and the other factors set forth in this report and in our report on Form 10-KSB for the year ended June 30, 2008. The realized prices for natural gas fluctuate from one period to another due to regional market conditions and other factors. The aggregate amount of gas produced may fluctuate based on the success of development and exploitation of gas reserves pursuant to current reservoir management. Since we have not drilled any wells during the current fiscal year to replace any reserves produced, our production volumes are decreasing in accordance with the decline curves typically associated with our existing wells. Accordingly, our results of operations may fluctuate from period to period based on the foregoing principal factors, among others.

Overview

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:

(1) holding and acquiring operating interests in oil and gas properties where we act as the operator of oil and gas wells and properties; and

(2) holding non-operating interests in oil and gas properties.

Previously, we held a non-operating working interest in approximately 37 oil wells in the East Poplar Field, Roosevelt County, Montana which contributed only nominally (if at all) to our positive cash flow and profitability, and during much of the latter half of calendar 2008 resulted in operating losses. Effective January 1, 2009, we sold our entire interest in these oil properties in Montana.

We are currently the operator of 67 gas wells in the Sacramento Valley of northern California. Additionally, we have a non-operated interest in 26 gas wells in the Sacramento Valley of northern California. The Company's interest in its California oil and gas properties are subject to a contract for sale, which contract is subject to Aspen's stockholder approval and other closing conditions. We have in the past engaged in business activities related to the exploration and development of other minerals and resources. We recompleted eight wells in September 2008 in an effort to improve their productivity and extended the terms of two leases. At the present time, we are not engaged in any drilling operations or acreage acquisition programs nor have we drilled any new wells in our current fiscal year.

In the past, where possible we attempted to be the operator of each property in which we invest. Currently, we are operating 67 gas wells using the services of a consultant. As operator, 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 received 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 nine months ended March 31, 2009, these administrative charges to the properties helped cover approximately 44% of our selling, general and administrative expenses as compared to 55% for the period ending March 31, 2008 due primarily to increases in consulting, accounting, and legal service charges, while management fees decreased 9% and the prices we received for oil and gas produced decreased significantly, as has our production of oil and natural gas.

º the disproportionate cost of Aspen's general and administrative expenditures required as a result of compliance with the Securities Exchange Act of 1934, as amended (including the requirements of the Sarbanes-Oxley Act of 2002) when compared to Aspen's revenues and net income;
º the board of directors' belief that the market price of Aspen common stock does not adequately reflect the inherent value of Aspen's producing oil and gas assets and undeveloped acreage, and thus the board of directors does not believe that a transaction based on the value of Aspen's common stock would be in the best interest of Aspen's shareholders; and
º the likelihood that Aspen's president will be unable to resume his former role and responsibilities and oversee Aspen's day-to-day operations due to the effects of the stroke he suffered in January 2008.

As a result of its activities throughout the last several months of 2008 and early 2009, management reached an agreement with one of the offerors which defines a transaction for the sale of our California assets and in February 2009 Aspen sold its interest in the East Poplar filed in Montana.

The sale of the California assets will not be completed until after Aspen receives shareholder approval of the sale. The meeting is scheduled to be held on May 22, 2009. Aspen cannot offer any assurance that we will be able to conclude an appropriate transaction for the sale of certain of our assets, that either we or the potential purchaser will meet the conditions necessary to complete the transaction, or that Aspen's shareholders will approve the transaction submitted to them. If we are unable to complete the sale of our California assets either because we were unable to obtain shareholder approval or for other reasons, Aspen expects to retain competent, experienced personnel to advance and continue its gas operations in California. In the meantime, Aspen has been maintaining its California assets in the normal course, although we have not commenced or completed any drilling operations and, therefore, our reserve base is depleting.

Aspen's results of operations and financial condition are significantly affected by the success of our exploration activity, the resulting production, oil and natural gas commodity prices, and the costs related to operating our properties. As is common with companies engaged in the exploration of early resource plays, our financial position and results of operations change significantly from period to period. Based on gas prices of $3.58 per Mcf of natural gas on March 31, 2009, the value of Aspen's proved reserves as calculated under SEC guidelines did not support the costs included in the full cost pool. Consequently, the Company recorded an asset impairment of $1.3 million during the three month period ended March 31, 2009 and had previously recorded an impairment of $2.25 million during the period ended December 31, 2008. The impairment primarily relates to a change in commodity prices, and depleting reserves.

Outlook and Trends

Total production for the year depends on a variety of factors set forth herein and in our Form 10-KSB for the year ended June 30, 2008. Until December 31, 2007, we were 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 although we were not able to do so during the last half of our 2008 fiscal year and during our 2009 fiscal year due to significantly fewer drilling operations, and therefore, fewer discoveries than in recent years. We have suspended our oil and gas drilling and acquisition activity due to our efforts to investigate the sale of our assets or another business combination.

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 (as occurred during our fiscal 2008) 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, As reflected in the full cost pool

Quantitative and Qualitative Disclosure About Risk

Our ability to replace reserves, dissipated through production or recalculation, will depend largely on how successful our drilling and acquisition efforts will be in the future. While we cannot predict the future, our historic success drilling ratio over the past seven 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. However, as noted above, we have suspended our oil and gas exploration and acquisition activities except that we did extend the terms of two of our existing leases.

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 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 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. The average price we received during the third quarter of 2009 for our natural gas was approximately $4.55 per MMBTU as compared to $8.20 per MMBTU during the same period of the prior year.

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.

Liquidity and Capital Resources

We have historically financed our operations with internally generated funds and limited borrowings from banks and third parties, and farmout arrangements, which permit third parties (including some related parties) to participate in our drilling prospects. During the year ended June 30, 2007, we borrowed $600,000 to purchase an interest in the Poplar Field. The total amount outstanding on this loan is $166,667 and is classified as current.

Our principal uses of cash during the past fifteen months have been for operating expenses, recompletion of certain wells, and expenses incurred in connection with the investigation and the efforts toward the completion toward the sale of the assets. Previously we had expended our cash for the acquisition, drilling, completion and production of prospects, the acquisition of producing properties, working capital, servicing debt and the payment of income taxes. As a result of the stroke suffered by our president in January 2008, we have been required to increase our use of oil and gas consultants. Our efforts to investigate and complete the sale of our assets have resulted in significant greater legal, accounting, and other general and administrative expenses.

To illustrate the changes in our cash flows for the period, all amounts presented are approximate. During the first nine months of our 2009 fiscal year, we increased our cash by $3.4 million from our operating, investing and financing activities as compared to $1.7 million during the same period of our 2008 fiscal year. In part this increase was due to the sale of our oil properties and securities. Our operational expenditures decreased due to the fact that we did not commence any drilling operations during the period. A significant increase in our cash during the quarter ended March 31, 2009 was due to the receipt of a $2.4 million refundable deposit for the prospective sale of our California oil and gas properties. In addition to recognizing the receipt of this cash, it is also included as a current liability on our financial statements, so the net effect on our working capital of this cash is nil.

We generated cash of $144,000 from operations for the nine months ended March 31, 2009, as compared to $4.85 million in cash generated from operating activities for the nine months ended March 31, 2008. This decrease of approximately $4.7 million was primarily due to a decrease in income from operations of approximately $3 million (as discussed below in results of operations), and a use of cash to retire current liabilities which decreased $2.25 million in the current period compared to an increase of $1.9 million during the period ending March 31, 2008. The decrease in current liabilities during the period impacts cash flows immediately in that more cash was used in the period to satisfy those liabilities. In addition, there were collections of accounts receivable of $1.45 million in 2009 compared to $181,000 in 2008.

Our financing activities consist of retirement of long-term debt of $202,600 for the period ending March 31, 2009 compared to $206,250 in the same period of the prior year.

Our working capital surplus (current assets less current liabilities) at March 31, 2009, was $2.9 million, which reflects a $1.6 million increase from our working capital at June 30, 2008. As detailed above, this increase was due primarily to the sale of our oil interest in properties in the East Poplar Field in Roosevelt County, Montana and securities and costs saved as a result of the lack of any drilling operations during our 2009 fiscal year.

Future Commitments

The Company has not commenced any drilling operations since June 30, 2008. Since the beginning of our 2009 fiscal year, the Company has recompleted 8 wells with mixed results. In addition, the Company has extended two leases (one at Denverton Creek and one at West Grimes), and has obtained permits to drill four wells in Colusa County, California and in the West Grimes/Strain Ventures area. Although the Company has a number of oil and gas leases that are not held by production, the Company has no obligation to drill any wells.

Pending shareholder approval, the Company has accepted an offer to sell substantially all of its gas producing assets in California and has received a potentially refundable deposit of $2,401,100. Aspen will have to refund the entire deposit, together with interest, if the transaction does not close other than as a result of a breach of the terms of the agreement by the prospective purchaser.

Results of Operations

Three and Nine Months Ending March 31, 2009 Compared to March 31, 2008

The following table sets forth certain items from our Condensed Consolidated
Statements of Operations as expressed as a percentage of total revenues, shown
for the nine months of fiscal 2009 and 2008:

                                             For the Nine Months Ended
                                          March 31, 2009    March 31, 2008

Total Revenues                                  100.0%             100.0%

Oil and Gas Production Costs                     36.1%              26.8%

Gross Profit                                     63.9%              73.2%

Cost and Expenses

   Depreciation and depletion                   187.6%              48.8%
   Selling, general and administrative           19.8%               9.3%

Total Cost and Expenses                         207.4%             58.1 %

Income from Operations                         -143.5%              15.1%

Other Income and Expenses                       -86.7%               1.5%

Income Before Income Taxes                     -230.2%              16.6%

Provision for Income Taxes                       93.0%              -3.4%

Net Income                                     -137.2%              13.2%