Edgar Filing: ASPEN EXPLORATION CORP

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FORM 10-Q

SECURITIES AND EXCHANGE COMMISSION

Washington D.C. 20549

MARK ONE

[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2009

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________to ________

Commission File Number 0-9494

ASPEN EXPLORATION CORPORATION
(Exact Name of Registrant as Specified in its Charter)


Delaware		84-0811316
(State or other jurisdiction of		(IRS Employer
incorporation or organization)		Identification No.)

Suite 208, 2050 S. Oneida St.
Denver, Colorado		80224-2426
(Address of Principal Executive Offices)		(Zip Code)

Issuer’s telephone number: (303) 639-9860

Indicate by check mark whether Aspen (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that Aspen was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes ¨ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o			Accelerated filer o
Non-accelerated filer o(Do not check if a smaller reporting company)			Smaller reporting company þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

Indicate the number of shares outstanding of each of the Issuer's classes of common stock as of the latest practicable date.

Class		Outstanding at May 15, 2009
Common stock, $.005 par value		7,259,622

	1

TABLE OF CONTENTS


		Page
Part One – Financial Information

Item 1. Financial Statements

Condensed Consolidated Balance Sheets		3

Condensed Consolidated Statements of Operations		5

Condensed Consolidated Statements of Cash Flows		6

Notes to Condensed Consolidated Financial Statements		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		12

Item 3. Quantitative and Qualitative Disclosures about Market Risk		22

Item 4T. Controls and Procedures		22

Part II

Item 1. Legal Proceedings		23

Item 1A. Risk Factors		23

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		23

Item 3. Defaults Upon Senior Securities		23

Item 4. Submission of Matters to a Vote of Security Holders		23

Item 5. Other Information		23

Item 6. Exhibits		24

Part One. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS


		March 31,			June 30,
		2009			2008
		(unaudited)
ASSETS

Current assets:
Cash and cash equivalents	$	4,978,296		$	1,595,150
Marketable securities		151,887			930,818
Accounts and trade receivables		912,461			2,287,519
Other current assets		79,229			39,474

Total current assets		6,121,873			4,852,961

Property and equipment
Oil and gas property		20,288,722			23,677,355
Support equipment		96,560			183,374

		20,385,282			23,860,729
Accumulated depletion and impairment - full cost pool		(15,323,066	)		(10,479,466	)
Accumulated depreciation - support equipment		(29,510	)		(70,570	)

Net property and equipment		5,032,706			13,310,693

Other assets:
Deposits		250,000			263,650
Deferred income taxes, net		159,500			-

Total other assets		409,500			263,650

Total assets	$	11,564,079		$	18,427,304

(Statement Continues)
The accompanying notes are an integral part of these condensed consolidated financial statements.

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)


		March 31,			June 30,
		2009			2008
		(unaudited)

LIABILITIES AND STOCKHOLDERS' EQUITY


Current liabilities:
Accounts payable	$	628,321		$	2,260,611
Other current liabilities and accrued expenses		-			620,875
Deposits on sale of gas property		2,401,100			-
Notes payable - current portion		166,667			475,000
Asset retirement obligation, current portion		30,900			56,400
Deferred income taxes, current		-			122,000

Total current liabilities		3,226,988			3,534,886

Long-term liabilities
Notes payable, net of current portion		-			116,667
Asset retirement obligation, net of current portion		495,350			675,955
Deferred income taxes, net		-			2,398,000

Total long-term liabilities		495,350			3,190,622

Stockholders' equity:

Common stock, $.005 par value:
Authorized: 50,000,000 shares
Issued and outstanding: At March 31, 2009,
and June 30, 2008, 7,259,622 shares		36,298			36,298
Capital in excess of par value		7,676,458			7,676,458
Accumulated other comprehensive loss		(566,046	)		(281,849	)
Retained earnings		695,031			4,270,889

Total stockholders' equity		7,841,741			11,701,796

Total liabilities and stockholders' equity	$	11,564,079		$	18,427,304

The accompanying notes are an integral part of these condensed consolidated financial statements.


ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

		Three Months Ended						Nine Months Ended
		March 31,						March 31,
		2009			2008			2009			2008

Revenues:
Oil and gas sales	$	452,757		$	1,325,261		$	2,606,637		$	3,910,858

Operating expenses:
Oil and gas production		234,756			371,501			940,452			1,047,302
Accretion, depreciation,
depletion and amortization		299,000			546,912			1,340,238			1,910,003
Impairment of full cost pool assets		1,300,000			-			3,550,000			-
Selling, general and administrative		149,923			135,322			516,271			363,333

Total operating expenses		1,983,679			1,053,735			6,346,961			3,320,638

Income (loss) from operations		(1,530,922	)		271,526			(3,740,324	)		590,220

Other income (expenses)
Interest and other income		3,784			9,474			17,477			105,892
Interest and other (expenses)		(81,943	)		(13,981	)		(107,681	)		(50,840	)
Loss on conveyances of property		(2,157,000	)		-			(2,157,000	)		-
Gain on sale of marketable securities		12,049			4,834			12,049			4,834
Gain (loss) on sale of equipment		(36,289	)		-			(24,240	)		-

Total other income (expenses)		(2,259,399	)		327			(2,259,395	)		59,886

Income (loss) before income taxes		(3,790,321	)		271,853			(5,999,719	)		650,106
Provision for income taxes		1,453,063			(67,014	)		2,423,861			(133,439	)

Net income (loss)	$	(2,337,258	)	$	204,839		$	(3,575,858	)	$	516,667

Basic net income (loss) per share	$	(0.32	)	$	0.03		$	(0.49	)	$	0.07

Diluted net income (loss) per share	$	(0.32	)	$	0.03		$	(0.49	)	$	0.07

Weighted average number of common shares outstanding
used to calculate basic net income (loss) per share :		7,259,622			7,259,622			7,259,622			7,259,622
Effect of dilutive securities:
Equity based compensation		-			39,912			-			39,912
Weighted average number of common shares outstanding
used to calculate diluted net income (loss) per share :		7,259,622			7,299,534			7,259,622			7,299,534

Unaudited Condensed Statements of Comprehensive Income (Loss)
Three and Nine Month Periods Ended March 31, 2009 and 2008

		Three Months Ended						Nine Months Ended
		March 31,						March 31,
		2009			2008			2009			2008

Net income (loss)	$	(2,337,258	)	$	204,839		$	(3,575,858	)	$	516,667
Unrealized losses on available-for-sale securities,
net of income tax of $(4,949) and $(187,520), respectively.		(7,425	)		(258,131	)		(281,286	)		(354,095	)

Other Comprehensive Income (loss)	$	(2,344,683	)	$	(53,292	)	$	(3,857,144	)	$	162,572

The accompanying notes are an integral part of these condensed consolidated financial statements.

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)


		Nine Months Ended March 31,
		2009			2008

Cash Flows from Operating Activities:
Net income (loss)	$	(3,575,858	)	$	516,667
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
Accretion and depreciation, depletion, and amortization		1,340,238			1,910,003
Impairment of oil and gas properties		3,550,000			-
Deferred income taxes		(2,494,881	)		280,994
Compensation expense related to stock options granted		-			47,298
Loss on conveyances of property		2,157,000			-
Realized (gain) on marketable securities		(12,050	)		(4,834	)
Loss on sale of equipment		24,241			-
Changes in assets and liabilities:
(Increase) decrease in current assets other than cash, cash
equivalents, and short-term marketable securities		1,410,303			181,244
Increase (decrease) in current liabilities other than notes payable
and asset retirement obligation		(2,253,165	)		1,920,366

Net Cash Provided by Operating Activities		145,828			4,851,738

Cash Flows from Investing Activities:
Sale of oil and gas properties		918,078			-
Deposits on sale of gas property		2,401,100			-
Additions to oil & gas property		(212,310	)		(2,653,991	)
Sales of marketable securities		322,165			-
(Purchases) of marketable securities		-			(280,184	)
Sale of property and equipment		10,875			-

Net Cash Provided by (Used in) Investing Activities		3,439,908			(2,934,175	)

Cash Flows from Financing Activities:
Payment of long-term debt		(202,590	)		(206,250	)

Net Cash (Used in) Financing Activities		(202,590	)		(206,250	)

Net Increase (Decrease) in Cash and Cash Equivalents		3,383,146			1,711,313

Cash and Cash Equivalents, beginning of year		1,595,150			4,057,279

Cash and Cash Equivalents, end of year	$	4,978,296		$	5,768,592

Supplemental disclosures of cash flow information:
Interest paid	$	30,670		$	50,840

Supplemental non-cash activity
Decrease in fair value of marketable securities (net of
income taxes of $187,520 and $243,494, respectively)	$	281,297		$	354,095

Note receivable on sale of oil & gas properties	$	75,000		$	-

Note payable relieved on sale of oil & gas properties	$	222,410		$	-

Increase (decrease) in asset retirement obligation	$	(206,105	)	$	95,973

The accompanying notes are an integral part of these condensed consolidated financial statements.
6

ASPEN EXPLORATION CORPORATION

Notes to Condensed Consolidated Financial Statements
(Unaudited)
March 31, 2009

NOTE 1 – BASIS OF PRESENTATION

The accompanying condensed consolidated financial statements of Aspen Exploration Corporation (the “Company”) are unaudited. However, in the opinion of management, the accompanying condensed consolidated financial statements reflect all adjustments, consisting of only normal recurring adjustments, necessary for fair presentation for the interim period.

Prior deferred tax amounts have been reclassified to properly present the net future deferred taxes.

The condensed consolidated financial statements included herein have been prepared by the Company pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in consolidated financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations. Management believes the disclosures made are adequate to make the information not misleading and suggests that these condensed consolidated financial statements be read in conjunction with the consolidated financial statements and notes hereto included in the Company’s Form 10-KSB for the year ended June 30, 2008.

This Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included in this Form 10-Q, including, without limitation, the statements under both “Notes to Consolidated Financial Statements” and “Item 2. Management’s Discussion and Analysis” located elsewhere herein regarding the Company’s financial position and liquidity, its strategies, financial instruments, and other matters, are forward-looking statements. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from the Company’s expectations are disclosed in this Form 10-Q in conjunction with the forward-looking statements.

NOTE 2 – SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Accounting principles generally accepted in the United States of America require certain estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent liabilities at the date of the financial statements and reported amounts of revenues and expenses to be made. Actual results could differ from those estimates. The Company’s significant estimates include the carrying value of our gas property, estimated life of long-lived assets, use of reserves in the estimation of depletion of gas properties, impairment of gas properties, asset retirement obligation abilities, and income taxes.

Cash and Cash Equivalents

For purposes of the Consolidated Balance Sheets and Statements of Cash Flows, we consider all highly liquid investments with a maturity of ninety days or less when purchased to be cash equivalents.

Investments in Debt and Equity Securities

The Company classifies all investments as available for sale securities in accordance with Financial Accounting Standards Board Statement of Financial Accounting Standards (SFAS) No. 115, Accounting for Certain Investments in Debt and Equity Securities. Changes in the fair value of the securities are reported as a separate component of shareholders’ equity until realized.

NOTE 2 – SIGNIFICANT ACCOUNTING POLICIES (Continued)

Oil and Gas Property

We utilize the full cost method of accounting for costs related to our gas property. Capitalized costs included in the full cost pool are depleted on an aggregate basis over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved gas reserves discounted at 10 percent plus the lower of cost or market value of unproved properties less any associated tax effects. If the full cost pool of capitalized gas property costs exceeds the ceiling, we will record a ceiling test write-down to the extent of such excess. We review our properties quarterly for impairment. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculation. This write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts shareholders’ equity in the period of occurrence and results in lower depreciation and depletion in future periods. The write-down may not be reversed in future periods, even though higher gas prices may subsequently increase the ceiling. Due to recent declines in gas prices and the fact that the Company has taken no action to replace reserves that have been produced, the Company recorded a ceiling write down of $3.55 million in the nine month period ended March 31, 2009 (including $1.3 million in the third quarter ended March 31, 2009).

Effective January 1, 2009, the Company sold its entire interest in an oil property in the Poplar Field of Montana for approximately $1.2 million. The disposition of these assets was significant in relation to our full cost pool, and therefore, we were required to evaluate whether the transaction had significantly altered the relationship between our capitalized costs and proved reserves, which caused us to recognize a loss in our financial statements under the full cost pool accounting rules. Accordingly, our evaluation resulted in our recognition of a $2.157 million loss on conveyance during the quarter ended March 31, 2009. During the 2008 fiscal year, we did not have any oil and gas property dispositions.

The Company’s interest in its California oil and gas properties are currently subject to a contract for sale, which contract is subject to Aspen’s stockholder approval and other closing conditions. As of this filing of our Form 10-Q, there are no assurances as to whether the sale of oil and gas properties in California will be completed.

Oil and Gas Reserves

The determination of depreciation and depletion expense as well as ceiling test write-downs, if any, related to the recorded value of our gas properties are highly dependent on the estimates of the proved gas reserves attributable to these properties. Gas reserves include proved reserves that represent estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating gas reserves and their values, including many factors beyond our control. Accordingly, reserve estimates are often different from the quantities of gas ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves. Our gas reserves are based on annual estimates prepared by an independent petroleum engineering firm, and are updated quarterly to reflect decreases from actual production and increases from new wells (company estimated).

Asset Retirement Obligations

We have obligations related to the plugging and abandonment of our gas wells, the removal of equipment and facilities, and returning the land to its original condition. SFAS No. 143, “Accounting for Asset Retirement Obligations” requires that we estimate the future cost of this obligation, discount this cost to its present value, and record a corresponding asset and liability in our Consolidated Balance Sheets. The values ultimately derived are based on many significant estimates, including the ultimate expected cost of the obligation, the expected future date of the required cash expenditures, and inflation rates. The nature of these estimates requires us to make judgments based on historical experience and future expectations related to timing. We review the estimate of our future asset retirement obligations quarterly. These quarterly reviews may require revisions to these estimates based on such things as changes to cost estimates or the timing of future cash outlays. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis. Revisions for the nine months ending March 31, 2009 resulted in a decrease in asset retirement obligations and the related asset of approximately $110,000.

NOTE 2 – SIGNIFICANT ACCOUNTING POLICIES (Continued)

The sale of our oil property in the Poplar Field in Montana resulted in a further decrease in our asset retirement obligation of $131,750.

We recognize two components on our consolidated statement of operations; accretion of asset retirement obligations and asset retirement expense. Accretion of asset retirement obligation reflects the periodic accretion of the present value of future plugging and abandonment costs. Accretion expense of $36,000 was recognized for the period ended March 31, 2009.

Income Taxes

We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes”. Accordingly, deferred tax assets and liabilities are determined based on the temporary differences between the financial statements and tax bases of assets and liabilities, using enacted tax rates in effect for the year in which the differences are expected to reverse.

Projections of future income taxes and their timing require significant estimates with respect to future operating results. Accordingly, the net deferred tax liability is continually re-evaluated and numerous estimates are revised over time. As such, the net deferred tax liability may change significantly as more information and data is gathered with respect to such events as changes in commodity prices, their effect on the estimate of gas reserves, and the depletion of these long-lived reserves.

Earnings Per Share

Our earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share is calculated by dividing net income by the diluted weighted average number of common shares. The diluted weighted average number of common shares is computed using the treasury stock method for common stock that may be issued for outstanding stock options. Dilution is not permitted if there are net losses.

Equity Compensation Plans

At March 31, 2009, the Company had three share-based employee compensation plans, which are described in the Notes to Consolidated Financial Statements in the Company’s Annual Report on Form 10-KSB for the year ended June 30, 2008. No compensation expense related to our equity compensation plans was recognized in the nine months ending March 31, 2009.

Off Balance Sheet Transactions, Arrangements, or Obligations

We have no material off balance sheet transactions, arrangements or obligations.

Recent Accounting Pronouncements

In September 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Positions (FSP) No. 133-1 and FIN 45-4 to amend SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, to require disclosures by sellers of credit derivatives, including credit derivatives embedded in a hybrid instrument. This FSP also amends FASB Interpretation No.45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, to require an additional disclosure about the current status of the payment/performance risk of a guarantee. Further, this FSP clarifies the FASB’s intent about the effective date of FASB Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities. We do not expect the adoption of this FSP to have a material effect on our financial statements and related disclosures. This FSP is effective for financial statements issued for reporting periods (annual or interim) ending after November 15, 2008, with early application encouraged.

NOTE 3 – ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss for the periods ending March 31, 2009 and 2008 consists of unrealized losses on available-for-sale securities. Changes in accumulated other comprehensive loss for the quarters ended March 31, 2009 and 2008 are as follows:


		2009			2008

Accumulated other comprehensive loss, July 1	$	(281,849	)	$	-
Unrealized losses on available-for-sale securities, net		(281,296	)		(354,095	)
Less: reclassification adjustment for gains realized in net income		(2,901	)		-

Accumulated other comprehensive loss, March 31	$	(566,046	)	$	(354,095	)

NOTE 4 – FAIR VALUE MEASUREMENTS

In September 2006, the FASB issued SFAS No. 157 “Fair Value Measurements” in order to establish a single definition of fair value and a framework for measuring fair value in generally accepted accounting principles (GAAP) that is intended to result in increased consistency and comparability in fair value measurements. SFAS No. 157 also expands disclosures about fair value measurements. SFAS No. 157 applies whenever other authoritative literature requires (or permits) certain assets or liabilities to be measured at fair value, but does not expand the use of fair value. SFAS No. 157 was originally effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years with early adoption permitted.

In early 2008, the FASB issued Staff Position (FSP) FAS-157-3, “Effective Date of FASB Statement No. 157,” which delays by one year, the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The delay pertains to items including, but not limited to, non-financial assets and non-financial liabilities initially measured at fair value in a business combination, non-financial assets recorded at fair value at the time of acquisition, and long-lived assets measured at fair value for impairment assessment under SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets”.

The Company has adopted the portion of SFAS No. 157 that has not been delayed by FSP FAS-157-3 as of the beginning of its 2009 fiscal year, and plans to adopt the balance of its provisions as of the beginning of its 2010 fiscal year. Items carried at fair value on a recurring basis (to which SFAS No. 157 applies in fiscal 2009) consist of available for sale securities based on quoted prices in active or brokered markets for identical as well as similar assets and liabilities. We do not currently have items which are carried at fair value on a non-recurring basis (to which SFAS No. 157 will apply in fiscal 2010). The Company also uses fair value concepts to test various long-lived assets for impairment. The Company is continuing to evaluate the impact the standard will have on the determination of fair value related to non-financial assets and non-financial liabilities in post-2009 years.

Fair values of assets and liabilities measured on a recurring basis at March 31, 2009 are as follows:


		Fair Value Measurements at Reporting Date Using

				Quoted Prices
				In Active	Significant
				Markets for	Other	Significant
				Identical	Observable	Unobservable
				Assets/Liabilities	Inputs	Inputs
		Fair Value		(Level 1)	(Level 2)	(Level 3)

Available-for-sale securities	$	151,887	$	151,887	$-	$-

NOTE 5 – LONG-TERM DEBT

In January 2007, we borrowed $600,000 from Wells Fargo Bank, NA pursuant to a promissory note payable over thirty-six months to partially finance the acquisition of the Poplar Field discussed in Note 7 of our form 10-KSB filed for the period ending June 30, 2008. Principal of $16,667 plus interest payments are due monthly beginning February 15, 2007 and continuing to January 15, 2010. Collateral consists of a blanket filing on Accounts Receivables. At March 31, 2009 the outstanding balance on the note was $166,667, and is classified as current.

The Wells Fargo note contains restrictive covenants which, among other things, require us to maintain a certain “Net Worth” defined as total stockholder’s equity of not less than $9,000,000 at any time, net income after taxes not less than $1,000 on an annual basis and an EBITDA ratio, as defined. We are currently not in compliance with our covenants to Wells Fargo due to the net loss for the period; however, Wells Fargo has not declared an event of default under the agreement.

In February 2007, as part of the Poplar acquisition, Aspen agreed to be responsible for 12.5% of a $3,000,000 loan obtained by Nautilus in connection with the purchase of the Poplar Field assets. Nautilus Poplar, LLC obtained the loan from the Jonah Bank of Wyoming, as lender. Aspen’s share of this loan was, at the time of acquisition of the property, $375,000 plus interest at a rate of 9.0%, and Aspen was subject to the repayment schedule that Nautilus Poplar negotiated and to the other terms and conditions of the loan agreement as fully as if Aspen were a party to the loan agreement. Aspen was relieved of this obligation as part of the sale of the Poplar Field assets, effective January 1, 2009.

Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

As announced in September 2008, our board of directors decided to investigate strategic alternatives for Aspen, including the possibility of selling our assets or considering another appropriate merger or acquisition transaction for several reasons, including:

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;
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
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

write-down taken by Aspen at March 31, 2009 (which was primarily due to commodity price decreases). Management expects that the decline will continue through fiscal 2009 as management continues its work to complete the sale of its assets or completing another business combination.

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.

Investing activities generated cash of $3.44 million due to the sale of oil interests and potentially refundable deposits on the prospective sale of gas properties (which deposit is also included as a current liability) and the sale of securities during the first nine months of fiscal year 2009 as compared to $2.65 million used to increase capitalized oil and gas costs in the nine months ended March 31, 2008. Cash used to increase capitalized oil and gas costs decreased primarily due to the fact that we have not commenced drilling any oil or gas wells during our 2009 fiscal year or subsequently, whereas we had an active drilling program in the first three quarters of the 2008 fiscal year. The expenditures that were made primarily related to recompletion activities on eight wells. These expenditures are net of the sale of interests in wells to be drilled charged to third party investors. In addition, we sold municipal bonds in the amount of $322,000 in the current period compared to the purchase of $280,000 in municipal bonds in the same period of our 2008 fiscal year.

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%

To facilitate discussion of our operating results for the nine months ended March 31, 2009 and 2008, we have included the following selected data from our Condensed Consolidated Statements of Operations:


		Comparison of the Fiscal Nine
		Months Ended March 31,						Increase (Decrease)
		2009			2008			Amount		Percentage
Revenues:
Oil and gas sales	$	2,606,637		$	3,910,858		$	(1,304,221	)	-33%

Cost and Expenses:
Oil and gas production		940,452			1,047,302			(106,850	)	-10%
Depreciation and depletion		4,890,238			1,910,003			2,980,235		156%
Selling, general and administrative		516,271			363,333			152,938		42%

Total Costs and Expenses		6,346,961			3,320,638			3,026,323		91%

Operating Income		(3,740,324	)		590,220			(4,330,544	)	-734%

Other Income (Expenses)		(2,259,395	)		59,886			(2,319,281	)	-3873%

Income Tax Benefit (Provision)		2,423,861			(133,439	)		2,557,300		-1916%

Net Income (Loss)	$	(3,575,858	)	$	516,667		$	(4,092,525	)	-792%

We have experienced a decrease in oil and gas revenues over the past year and our operations have been adversely affected by increasing costs of production, as well as additional administrative, consulting, legal and accounting costs incurred due to the efforts we have made to sell our oil and gas properties and to replace the services previously provided by our president who suffered a stroke in January 2008. As noted, oil and gas prices are subject to national and international pressures, and Aspen has no control over those prices. The Company reported a net loss for the three months ended March 31, 2009 of $(2.34 million), compared to net income of $205,000 for the same period in 2008 (a net loss during the nine months ended March 31, 2009 of $(3.6 million), compared to net income of $517,000 for the same period in 2008). The Company’s net loss for the three and nine months ended March 31, 2009 was largely due to impairment expense charges of $3.55 million, a conveyance loss of $2.16 million on the sale of our oil interests, and increased operating expenses as discussed in more detail below.

For the three and nine months ended March 31, 2009, our operations continued to be focused on the production of gas in California. Our gas production decreased from 462,027 MMBTU sold during the first nine months of March 31, 2008, to 336,427 MMBTU sold this period (a decrease of approximately 27%) (a decrease during the three month period from 129,688 MMBTU (during the 2008 period) to 99,351 MMBTU (2009)). Our production volume decreased so significantly because our producing wells followed expected decline curves (reducing production volume over time), and we did not drill any additional wells to replace the reserves produced. Unless we engage in further drilling operations, we anticipate that our natural gas production volume will continue to decrease as the reserves in our existing wells are depleted.

Average gas prices received during the first nine months of fiscal year 2009 decreased approximately 7.4% compared to the same period in the last fiscal year as a result of fixed price contracts in effect during the period. As a result of our decreased gas production, decreased prices received for our production, and the sale of our oil interests, our revenues from oil and gas sales decreased during the 2009 period by approximately $1.3 million from approximately $3.9 million to approximately $2.6 million.

Oil and gas production costs decreased approximately 10% in the nine months ended March 31, 2009, as compared to the same period in 2008, from approximately $1 million to about $940,000 ($371,500 to $235,000 during the three month period). The decrease can be attributed to the sale of our oil interests.

Excluding the $3.55 million ceiling write-down, depletion, depreciation and amortization expense decreased 30%, from approximately $1.9 million for the nine months ended March 31, 2008 ($547,000 for the three month period

ending March 31, 2008) as compared to $1.3 million and $299,000 during the nine and three month periods ending March 31, 2009. This decrease was the result of decreased investments in oil and gas activities, which resulted in the lower total depletion taken. Depletion expense per equivalent unit of production (MCFe) was $3.62 and $3.75 for the nine months ending March 31, 2009 and 2008, respectively ($3.01 and $3.73 respectively for the three month periods). The decrease in depletion rate is primarily due to the sale of our oil interests.

Effective January 1, 2009, the Company sold its entire interest in oil property in the Poplar Field of Montana for approximately $1.2 million. The disposition of these assets was significant in relation to our full cost pool, and therefore, we were required to evaluate whether the transaction had significantly altered the relationship between our capitalized costs and proved reserves, which could cause us to recognize a loss under the full cost pool accounting rules. Accordingly, our evaluation resulted in our recognition of a $2.157 million loss on conveyance during the quarter ended March 31, 2009. During the 2008 fiscal year, we did not have any oil and gas property dispositions.

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 the first nine months of 2009 and 2008, costs increased by about $132,500, or 17%, due primarily to consulting, accounting, and legal fees, while management fees decreased 9%. Management fees as a percentage of SG&A decreased 11% for the nine month period ending March 31, 2009 compared to 2008. Similar increases in costs were recognized during the three month period ended March 31, 2009 as compared to the same three month period in 2008. This ratio coverage of general and administrative costs decreased from approximately 55.9% during the nine months ended March 31, 2008 to approximately 43.5% at March 31, 2009.


		March 31,			March 31,
		2009			2008

Management fees	$	398,082		$	436,727
Selling, general and administrative (SG&A)		914,353			800,060
Management fees as a percentage of SG&A		43.5	%		54.6	%

Central to the issue of success of the three and nine months operations ended March 31, 2009 is the discussion of changes in oil and gas sales, volumes of natural gas sold and the price received for those sales. We present them here in tabular form:

										Oil &
		Gas		MMBTU			Price/			NGL		Bbls			Price/
		Sales		Sold			MMBTU			Sales		Sold			Bbl

June 30, 2009
1st Quarter	$	996,710		119,724		$	8.33		$	296,407		2,903		$	102.10
2nd Quarter		743,732		117,352			6.34			117,338		2,677			43.83
3rd Quarter		452,450		99,351			4.55			-		-			-

Year to Date		2,192,892		336,427			6.52			413,745		5,580			74.15

June 30, 2008
1st Quarter		1,057,907		170,058			6.22			162,915		2,256			72.21
2nd Quarter		1,132,137		162,281			6.98			232,638		2,856			81.46
3rd Quarter		1,063,473		129,688			8.20			261,788		2,822			92.77
4th Quarter		1,154,356		119,760			9.64			325,153		2,232			145.68

June 30, 2008	$	4,407,873		581,787		$	7.58		$	982,494		10,166		$	96.65

Nine-Month
Change
2009 vs 2008
Amount	$	(1,060,625	)	(125,600	)	$	(0.5	)	$	(243,596	)	(2,354	)	$	(8.7	)
Percentage		-32.6	%	-27.2	%		-7.4	%		-37.1	%	-29.7	%		-10.5	%

Due to a 27% reduction in natural gas production volumes, decreased prices received for our production, and the sale of our oil interests, our oil and gas revenues have shown a decrease over the nine months of fiscal 2009. As the table above notes, the volume of gas sold has decreased and we have experienced a 7.4% decrease in the price received per MMBTU of gas. We anticipate that, because we have not engaged in any additional drilling operations, our production volume will likely decline during the next fiscal quarters.

Critical Accounting Policies and Estimates

The Company believes the following accounting policies and estimates are critical in the preparation of its consolidated financial statements: the carrying value of its oil and natural gas properties, the accounting for oil and gas reserves, and the estimate of its asset retirement obligations.

Oil and Gas Properties

The Company uses the full cost method of accounting for costs related to its oil and natural gas properties. Capitalized costs included in the full cost pool are depleted on an aggregate basis using the units-of-production method. Depreciation, depletion and amortization is a significant component of oil and natural gas properties, but does not impact cash flow. A change in proved reserves without a corresponding change in capitalized costs will cause the depletion rate to increase or decrease.

Both the volume of proved reserves and any estimated future expenditures used for the depletion calculation are based on estimates such as those described under “Reserve Estimates” below.

The capitalized costs in the full cost pool are subject to a quarterly ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10 percent plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and result in lower depreciation and depletion in future periods. A write-down may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the ceiling. Aspen has recognized a write-down of $3.55 million to the full cost pool during the first nine months of 2009 (including a $1.3 million write-down in the third quarter of fiscal 2009).

Changes in oil and natural gas prices have historically had the most significant impact on the Company’s ceiling test. In general, the ceiling is lower when prices are lower. Even though oil and natural gas prices can be highly volatile over weeks and even days, the ceiling calculation dictates that prices in effect as of the last day of the test period be used and held constant. The resulting valuation is a snapshot as of that day and, thus, is generally not indicative of a true fair value that would be placed on the Company’s reserves by the Company or by an independent third party. Therefore, the future net revenues associated with the estimated proved reserves are not based on the Company’s assessment of future prices or costs, but rather are based on prices and costs in effect as of the end of the test period.

Reserve Estimates

Our estimates of oil and natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and natural gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and gas properties and/or the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

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

The amount and timing of actual production;
Supply and demand for natural gas;
Curtailments or increases in consumption by natural gas purchasers; and
Changes in governmental regulations or taxation.

Accounts Receivable

Accounts receivable balances are evaluated on a continual basis and allowances are provided for potentially uncollectible accounts based on management’s estimate of the collectability of customer accounts. If the financial condition of a customer were to deteriorate, resulting in an impairment of its ability to make payments, an allowance may be required. Allowance adjustments are charged to operations in the period in which the facts that give rise to the adjustments become known; however, no allowance is recorded for the period ending March 31, 2009, as all receivables are expected to be collected in full.

Investments in Debt and Equity Securities

The Company classifies all investments as available for sale securities in accordance with SFAS No. 115,

Accounting for Certain Investments in Debt and Equity Securities. Changes in the fair value of the securities are reported as a separate component of shareholders’ equity until realized.

Asset Retirement Obligations

We recognize the future cost to plug and abandon gas wells over the estimated useful life of the wells in accordance with the provision of SFAS No. 143. SFAS No. 143 requires that we record a liability for the present value of the asset retirement obligation with a corresponding increase to the carrying value of the related long-lived asset. We amortize the amount added to the oil and gas properties and recognize accretion expense in connection with the discounted liability over the remaining lives of the respective gas wells. Our liability estimate is based on our historical experience in plugging and abandoning gas wells, estimated well lives based on engineering studies, external estimates as to the cost to plug and abandon wells in the future and federal and state regulatory requirements. 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.

Deferred Taxes

Off Balance Sheet Arrangements

We have no off balance sheet arrangements and thus no disclosure is required.

Other Developments

Aspen has been investigating strategic alternatives for its business operations. In February 2009, and retroactively effective to January 1, 2009, Aspen sold its non-operated interest in the East Poplar oil field in Roosevelt County, Montana to its fellow participants in that field. The purchase price was approximately $1.2 million, and resulted in a conveyance loss of approximately $2,157,000.

After significant due diligence and negotiations since September 2008, in February 2009, management reached an agreement with an unaffiliated party to define a transaction for the sale of its California natural gas assets. The sale of these assets will not be completed until after Aspen receives shareholder approval of the sale and other closing conditions are completed or waived by the parties. Currently, Aspen’s shareholder meeting is scheduled for May 22, 2009. Aspen cannot offer any assurance that we will be able to obtain shareholder approval or then proceed to

conclude the contemplated transaction for the sale of our California natural gas assets. If we are unable to complete the transaction 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 oil and gas operations in California and elsewhere. In the meantime, Aspen has suspended its normal drilling operations, but is carrying on its other business operations (including operation of existing oil and gas wells and recompletion of those wells where deemed necessary) in the normal course.

Forward Looking Statements

The management discussion and analysis portion 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 items are discussed at length in Aspen’s Form 10-KSB filed with the Securities and Exchange Commission, under the heading “Risk Factors” in the section titled “Management’s Discussion and Analysis of Financial Condition or Plan of Operation,” and in this Form 10-Q.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

As a crude oil and natural gas producer, our revenue, cash flow from operations, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil and natural gas. Declines in commodity prices will materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices may reduce the amount of crude oil and natural gas that we can produce economically. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control, such as global, political and economic conditions. Historically, prices received for crude oil and natural gas production have been volatile and unpredictable, and such volatility is expected to continue. Most of our production is sold at market prices. Generally, if the commodity indexes fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control.

Item 4T. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As required by Rule 13a-15 under the Securities Exchange Act of 1934 (the “1934 Act”), as of March 31, 2009, we carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures. This evaluation was carried out under the supervision and with the participation of our Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer). Based upon and as of the date of that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2009.

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 of 1934 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 Securities Exchange Act of 1934 is accumulated and communicated to our management, including our principal executive officer and our principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Internal Control Over Financial Reporting

There have not been any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated by the SEC under the Exchange Act) during the nine months ended March 31, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II

Item 1. LEGAL PROCEEDINGS

There are no material pending legal or regulatory proceedings against Aspen Exploration Corporation, and it is not aware of any that are known to be contemplated.

Item 1A. RISK FACTORS

Risk Factors are discussed at length in Aspen’s Form 10-KSB for the fiscal year ended June 30, 2008 and filed with the Securities and Exchange Commission, under the heading “Risk Factors” in the section titled “Management’s Discussion and Analysis of Financial Condition or Plan of Operation” which is incorporated herein by this reference.

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

Item 3. DEFAULTS UPON SENIOR SECURITIES

None.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matter was submitted during the third quarter of the fiscal year covered by this report to a vote of security holders, through the solicitation of proxies or otherwise.

Item 5. OTHER INFORMATION

Aspen has scheduled a special meeting of shareholders on May 22, 2009, although such meeting will not include an election of directors and therefore is not considered an “annual meeting.” If this date is delayed by more than 30 days, or if the meeting is adjourned, Aspen will inform shareholders of the change by a means reasonably calculated to inform shareholders.

Item 6. EXHIBITS

Exhibit No.		Document
10.1		Purchase and Sale Agreement among Aspen Exploration Corporation, Venoco, Inc., and certain other
		persons listed in the Annexes thereto dated February 18, 2009. (1)

10.2		Form of Voting Agreement. (1)

10.3		Form of Joinder Agreements (Indirect). (1)

10.4		Form of Joinder agreements (Direct Seller). (1)

10.5		Agreement of Purchase and Sale among Aspen Exploration Corporation, Nautilus Poplar, LLC and
		Hunter Energy LLC dated February 24, 2009. (2)

10.6		Employment Agreement between Aspen Exploration Corporation and R.V. Bailey. (3)

31.1		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (R. V. Bailey, Chief Executive Officer).

31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Kevan Hensman, Chief Financial Officer).

32		Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley
		Act of 2002. (R. V. Bailey, Chief Executive Officer, and Kevan Hensman, Chief Financial Officer).

(1) Incorporated by reference from the registrant’s current report on Form 8-K dated February 18, 2009 and filed on February 19, 2009.

(2) Incorporated by reference from the registrant’s current report on Form 8-K dated February 25, 2009 and filed on March 3, 2009.

(3) Incorporated by reference from the registrant’s current report on Form 8-K dated March 25, 2009 and filed on March 31, 2009.

Other exhibits and schedules are omitted because they are not applicable, not required or the information is included in the financial statements or notes thereto.

In accordance with the requirements of the Securities Exchange Act of 1934, we have duly caused this report to be signed on our behalf by the undersigned, thereunto duly authorized

		ASPEN EXPLORATION CORPORATION


Date: May 14, 2009		/s/ R.V. Bailey
		R.V. Bailey, Chief Executive Officer
		(principal executive officer)