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| ASPN.OB > SEC Filings for ASPN.OB > Form 10KSB on 29-Sep-2008 | All Recent SEC Filings |
29-Sep-2008
Annual Report
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:
(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.
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 and non-operating working interest in approximately 37 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 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 fiscal year ended June 30, 2008, these administrative charges to the properties help cover approximately 49% of our selling, general and administrative expenses.
On September 4, 2008, subsequent to our fiscal year end, we announced that we have decided to investigate strategic alternatives, including the possibility of selling Aspen's assets or considering another appropriate merger or acquisition transaction. We have opened a data room where interested persons may review certain information about our properties. As of the date of this Annual Report we have not received any offer from any person for an asset acquisition, merger, or other business combination. We cannot offer any assurance that we will receive an acceptable offer from any person for an asset acquisition, merger, or other business combination. Further, we may later determine that it is in the best interest of its shareholders to investigate other forms of business alternatives or to continue and expand existing business operations with existing or new management. In the meantime, Aspen is carrying on its business operations in the normal course.
Critical Accounting Policies and Estimates:
We believe the following critical accounting policies affect our most significant judgments and estimates used in the preparation of our Consolidated Financial Statements.
Reserve Estimates:
Our estimates of oil and natural gas reserves, by necessity, are projections based on 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
Many factors will affect actual future net cash flows, including:
º the amount and timing of actual production;
º supply and demand for oil and natural gas;
º curtailments or increases in consumption by purchasers; and
º changes in governmental regulations or taxation.
Gas Delivery Commitments:
We have entered into contracts for the sale and purchase of natural gas with Enserco Energy Inc., and Calpine Producer Services, L.P. The original, master contract with Enserco is dated November 1, 2005. The master contract with Calpine is dated June 1, 2007 Aspen has continuously renewed these contracts with Enserco and Calpine since then. Aspen's sales of natural gas under the Enserco and Calpine contracts qualify for the "Normal Purchases and Normal Sales" exception in paragraph 10(b) of FAS 133. The contracts are normal industry sales contracts that provides for the sale of gas over a reasonable period of time in the normal course of business. The contracts contain net settlement provisions should Aspen fail to deliver natural gas when required. 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.
Property, Equipment and Depreciation:
We follow the full-cost method of accounting for oil and gas properties. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, including salaries, benefits and other internal salary related costs directly attributable to these activities. 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:
(1 ) the standardized measure of discounted future net cash flows from proved reserves, and (2 ) the lower of cost or fair market value of properties in process of development and unexplored acreage
The excess is charged to expense as additional depletion. Normal dispositions of oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized.
We apply 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. 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.
Income Taxes
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.
Equity-Based Compensation
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 the fiscal years ended June 30, 2008 and 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.
Investments in Debt and Equity Securities
Prior to the beginning of the current fiscal year, the Company classified all investments as Trading Securities in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities. These securities were marked to market each period with the realized and unrealized gain or loss recorded in the statement of operations. During the first quarter of fiscal year 2008, management reassessed the appropriateness of the classification of the securities held, and determined that due to the sufficiency of cash flows to finance current operations and budgeted expenditures, the Company will hold investments until such time it determines there may be a need to sell those securities. As of July 1, 2007, Management determined the securities are more appropriately classified as available for sale, and changes in the fair value of the securities are reported as a separate component of shareholders' equity until realized. The securities were transferred from the trading category, and as such, the unrealized holding gain or loss at the date of the transfer has already been recognized in earnings and shall not be reversed. Aspen uses the specific identification method to determine the cost of securities sold.
• gas sales decreased approximately 8% from 631,557 MMbtu to 581,787 MMbtu;
• oil sales increased to 10,166 barrels due to full year results of the acquisition of operating interests in the Poplar fields in Montana; and
• reserves have decreased approximately 5% to 3,298,744 net equivalent Mcf (MCFEQ) from 3,480,271 MCFEQ. Natural gas reserves reduced by approximately 20% from 2,701,201 Mcf (at June 30, 2007) to 2,150,734 Mcf (at June 30, 2008). The significant reduction of natural gas reserves resulted primarily from discoveries during our 2008 fiscal year (382,828 Mcf) being less than one-half of the discoveries achieved during our 2007 fiscal year (874,010 Mcf). If we are not successful in replacing our production with discoveries, our reserves will continue to decrease.
During the last fiscal year, the average price received for our gas production increased approximately 8% from $7.00 per MMbtu to $7.58 per MMbtu. The average price received for oil increased almost 66% from $58.30 per barrel to $96.65 per barrel. Costs of production and accretion, depletion, depreciation, and amortization, increased 37%.
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 although (as noted above) we were not able to do so during our 2008 fiscal year due to significantly less discoveries than our natural gas discoveries during 2007. These 2008 additions resulted primarily from 7 newly drilled gas wells and the reactivation and improvement efforts on properties in which Aspen holds oil interests in Montana. Our oil reserves increased significantly during 2008 because of successful recompilations resulting in revisions of prior estimates, not as a result of any new discoveries. Overall, Aspen's interest in net producing reserves of new wells replaced 64.3% of calculated total net gas sales in 2008. 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.
At June 30, 2008, our standardized measure of discounted future net cash flows from our oil and gas operations was determined to be $10,269,000 as compared to $8,034,000 as at June 30, 2007. Our standardized measure increased during 2008 notwithstanding the reduction of our reserves of oil (Bbl) and natural gas (Mcf) primarily because of the increased prices that we are receiving for our production, offset in part by an increase in operating costs.
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