FORM 10-QSB
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 December 31, 2007
OR
[ ] 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 Aspen 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 [ X ] No [ ]
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act).
Yes [ ] No [ X ]
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 February 11, 2008
----- --------------------------------
Common stock, $.005 par value 7,259,622
Transitional small business disclosure format: Yes XX No
----- -----
Part One. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
December 31, June 30,
2007 2007
------------- ------------
(unaudited)
ASSETS
Current assets:
Cash and cash equivalents $ 2,741,531 $ 4,057,279
Marketable securities, available for sale 1,258,810 1,120,485
Accounts and trade receivables 2,363,518 2,136,609
Other current assets 43,539 33,609
------------ ------------
Total current assets 6,407,398 7,347,982
------------ ------------
Property and equipment
Oil and gas property (full cost method) 22,330,219 19,802,843
Support equipment 172,700 184,514
------------ ------------
22,502,919 19,987,357
Accumulated depletion and impairment - full cost pool (9,417,475) (8,083,383)
Accumulated depreciation - support equipment (59,932) (49,304)
------------ ------------
Net property and equipment 13,025,512 11,854,670
------------ ------------
Other assets:
Deposits 263,650 263,650
Deferred income taxes 2,174,000 1,673,000
------------ ------------
Total other assets 2,437,650 1,936,650
------------ ------------
Total assets $ 21,870,560 $ 21,139,302
============ ============
(Statement Continues)
The accompanying notes are an integral part of these condensed consolidated financial statements.
2
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)
December 31, June 30,
2007 2007
------------ ------------
(unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 3,498,893 $ 2,961,100
Other current liabilities and accrued expenses 1,142,502 1,690,709
Notes payable - current portion 275,000 275,000
Asset retirement obligation, current portion 43,000 39,400
Deferred income taxes, current 252,000 342,000
------------ ------------
Total current liabilities 5,211,395 5,308,209
------------ ------------
Long-term liabilities
Notes payable, net of current portion 454,167 591,667
Asset retirement obligation, net of current portion 557,998 447,253
Deferred income taxes 4,377,500 3,786,000
------------ ------------
Total long-term liabilities 5,389,665 4,824,920
------------ ------------
Stockholders' equity:
Common stock, $.005 par value:
Authorized: 50,000,000 shares
Issued and outstanding: At December 31, 2007,
and June 30, 2007, 7,259,622 shares 36,298 36,298
Capital in excess of par value 7,549,087 7,501,789
Accumulated other comprehensive loss (95,799) --
Retained earnings 3,779,914 3,468,086
------------ ------------
Total stockholders' equity 11,269,500 11,006,173
------------ ------------
Total liabilities and stockholders' equity $ 21,870,560 $ 21,139,302
============ ============
The accompanying notes are an integral part of these condensed consolidated financial statements.
3
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended Six Months Ended
December 31, December 31,
---------------------------- ----------------------------
2007 2006 2007 2006
----------- ----------- ----------- -----------
Revenues:
Oil and gas sales $ 1,364,775 $ 1,053,839 $ 2,585,597 $ 2,016,772
----------- ----------- ----------- -----------
Operating expenses:
Oil and gas production 410,885 138,062 675,801 329,242
Accretion, and depreciation,
depletion and amortization 700,443 499,877 1,363,091 980,154
Selling, general and administrative 63,429 150,930 228,011 548,395
----------- ----------- ----------- -----------
Total operating expenses 1,174,757 788,869 2,266,903 1,857,791
----------- ----------- ----------- -----------
Income from operations 190,018 264,970 318,694 158,981
Other income (expenses)
Interest and other income 21,382 14,469 96,418 35,886
Interest and other expenses (18,524) (23) (36,859) (4,768)
Gain (loss) on investments -- 228,160 -- 490,696
Gain on sale of equipment -- -- -- 12,000
----------- ----------- ----------- -----------
Total other income (expenses) 2,858 242,606 59,559 533,814
----------- ----------- ----------- -----------
Income before income taxes 192,876 507,576 378,253 692,795
Provision for income taxes (30,654) (161,000) (66,425) (75,000)
----------- ----------- ----------- -----------
Net income $ 162,222 $ 346,576 $ 311,828 $ 617,795
=========== =========== =========== ===========
Basic net income per share $ 0.02 $ 0.05 $ 0.04 $ 0.09
=========== =========== =========== ===========
Diluted net income per share $ 0.02 $ 0.05 $ 0.04 $ 0.08
=========== =========== =========== ===========
Weighted average number of common shares outstanding
used to calculate basic net income per share : 7,259,622 7,144,898 7,259,622 7,144,898
Effect of dilutive securities:
Equity based compensation 51,329 223,028 51,329 223,028
----------- ----------- ----------- -----------
Weighted average number of common shares outstanding
used to calculate diluted net income per share : 7,310,951 7,367,926 7,310,951 7,367,926
=========== =========== =========== ===========
Unaudited Condensed Statements of Comprehensive Income
Three and Six Month Periods Ended December 31, 2007 and 2006
Three Months Ended Six Months Ended
December 31, December 31,
------------------------- --------------------------
2007 2006 2007 2006
--------- --------- --------- ---------
Net income $ 162,222 $ 346,576 $ 311,828 $ 617,795
Unrealized losses on available-for-sale securities,
net of income tax of $48,872, and ($65,876), respectively 71,071 -- (95,799) --
--------- --------- --------- ---------
Comprehensive income (loss) $ 233,293 $ 346,576 $ 216,029 $ 617,795
========= ========= ========= =========
The accompanying notes are an integral part of these condensed consolidated financial statements.
4
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended December 31,
--------------------------------
2007 2006
----------- -----------
Cash Flows from Operating Activities:
-------------------------------------
Net income $ 311,828 $ 617,795
Adjustments to reconcile net income to net cash provided
by operating activities:
Accretion and depreciation, depletion, and amortization 1,363,092 980,154
Deferred income taxes 66,376 75,000
Amortization of deferred compensation -- 119,233
Compensation expense related to stock options granted 47,298 81,508
Realized (gain) on marketable securities -- (147,969)
Unrealized (gain) on marketable securities -- (342,728)
Proceeds from sale of marketable securities -- 291,495
(Gain) on sale of vehicle -- (12,000)
Changes in assets and liabilities:
Increase in current assets other than cash, cash equivalents,
and short-term marketable securities (236,839) (1,188,281)
Increase (decrease) in current liabilities other than notes payable
and asset retirement obligation (10,414) (1,405,612)
----------- -----------
Net Cash Provided (Used) by Operating Activities 1,541,341 (931,405)
----------- -----------
Cash Flows from Investing Activities:
-------------------------------------
Additions to oil and gas properties (2,419,589) (2,170,214)
Purchase of securities (300,000) --
Producing oil and gas properties purchased -- (89,061)
Sale of property and equipment -- 12,000
----------- -----------
Net Cash (Used) in Investing Activities (2,719,589) (2,247,275)
----------- -----------
Cash Flows from Financing Activities:
-------------------------------------
Proceeds from exercise of stock options -- 28,500
Payment of long-term debt (137,500) --
Payment of cash dividends -- (357,981)
----------- -----------
Net Cash (Used) by Financing Activities (137,500) (329,481)
----------- -----------
Net (Decrease) in Cash and Cash Equivalents (1,315,748) (3,508,161)
Cash and Cash Equivalents, beginning of year 4,057,279 6,466,010
----------- -----------
Cash and Cash Equivalents, end of year $ 2,741,531 $ 2,957,849
=========== ===========
Supplemental disclosures of cash flow information:
--------------------------------------------------
Interest paid $ 36,859 $ 4,768
=========== ===========
Supplemental non-cash activity
------------------------------
Decrease in fair value of marketable securities (net of
income taxes of $65,876) $ 95,799 $ --
Increase in asset retirement obligation $ 95,973 $ --
The accompanying notes are an integral part of these condensed consolidated financial statements.
5
ASPEN EXPLORATION CORPORATION
Notes to Condensed Consolidated Financial Statements
(Unaudited)
December 31, 2007
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.
The 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, 2007 and in the Form 10-KSB itself.
This Form 10-QSB 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-QSB, 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-QSB 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 estimated life of long-lived assets, use of reserves in the
estimation of depletion of oil and gas properties, impairment of oil and gas
properties, asset retirement obligation liabilities, and income taxes.
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. The unrealized holding gain or loss at
the date of the transfer (July 1, 2007), to the classification as available for
sale, as described below, has already been recognized in earnings and shall not
be reversed.
6
NOTE 2 - SIGNIFICANT ACCOUNTING POLICIES (Continued)
-------------------------------
During the first quarter, management reassessed the appropriateness of the
classification of the securities held, and determined that due to the
sufficiency of the Company's 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, or the company
determines a sale to be in its best interest. Consequently, 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. Gains and losses
are no longer a component of the Company's Statement of Operations.
At December 31, 2007, the fair value of securities available for sale was
$1,258,810. The gross unrealized holding gain (loss) during the three and six
months ended December 31, 2007, on securities still held as of December 31,
2007, was $119,943 and $(161,675), respectively.
Recent Accounting Pronouncements
--------------------------------
In June 2006, the Financial Accounting Standards Board (FASB) issued
Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes--an
interpretation of FASB Statement No. 109. FIN 48 prescribes a recognition
threshold and measurement attribute for the financial statement recognition and
measurement of a tax position taken or expected to be taken in a tax return, and
provides guidance on derecognition, classification, interest and penalties,
accounting in interim periods, disclosure, and transition. This Interpretation
is effective for fiscal years beginning after December 15, 2006. The Company has
evaluated the effects of adopting this interpretation and determined there are
no material uncertain tax positions.
In September 2006, Statement of Financial Accounting Standards (SFAS) No. 157,
Fair Value Measurements was issued by the FASB. This statement defines fair
value, establishes a framework for measuring fair value and expands disclosures
about fair value measurements. SFAS No. 157 will become effective for the
Company's fiscal year beginning after November 15, 2007, and the Company is
currently assessing the potential impact of this Statement on its financial
statements.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for
Financial Assets and Financial Liabilities, which permits an entity to measure
certain financial assets and financial liabilities at fair value. The objective
of SFAS No. 159 is to improve financial reporting by allowing entities to
mitigate volatility in reported earnings caused by the measurement of related
assets and liabilities using different attributes, without having to apply
complex hedge accounting provisions. Under SFAS No. 159, entities that elect the
fair value option (by instrument) will report unrealized gains and losses in
earnings at each subsequent reporting date. The fair value option election is
irrevocable, unless a new election date occurs. SFAS No. 159 establishes
presentation and disclosure requirements to help financial statement users
understand the effect of the entity's election on its earnings, but does not
eliminate disclosure requirements of other accounting standards. Assets and
liabilities that are measured at fair value must be displayed on the face of the
balance sheet. This statement is effective for fiscal years beginning January 1,
2008 and the Company is evaluating the effects this pronouncement will have on
the Company's financial statements.
In December 2007, FASB issued SFAS No. 160, which amends Accounting Research
Bulletin (ARB) No. 51 and (1) establishes standards of accounting and reporting
on noncontrolling interests in consolidated statements, (2) provides guidance on
accounting for changes in the parent's ownership interest in a subsidiary, and
(3) establishes standards of accounting of the deconsolidation of a subsidiary
due to the loss of control. The amendments to ARB No. 51 made by SFAS No. 160
are effective for fiscal years (and interim period within those years) beginning
on or after December 15, 2008. The Company is currently assessing the potential
impact this statement on its financial statements.
7
NOTE 2 - SIGNIFICANT ACCOUNTING POLICIES (Continued)
-------------------------------
Recent Accounting Pronouncements (Continued)
In January 2008, the SEC issued Staff Accounting Bulletin (SAB) No. 110, which
amends SAB No. 107. In March 2005, the SEC issued Staff Accounting Bulletin
(SAB) No. 107 in which, among other matters, the Staff expressed its views
regarding the valuation of share-based payment arrangements. Specifically, SAB
No. 107 provided a simplified approach for estimating the expected term of a
"plain vanilla" option, which is required for application of the
Black-Scholes-Merton model (and other models) for valuing share options. At the
time, the Staff acknowledged that, for companies choosing not to rely on their
own historical option exercise data, information about exercise patterns with
respect to plain vanilla options granted by other companies might not be
available in the near term; accordingly, in SAB No. 107, the Staff permitted use
of a simplified approach for estimating the term of plain vanilla options
granted on or before December 31, 2007. The information concerning exercise
behavior that the Staff contemplated would be available by such date has not
materialized for many companies. Thus, in SAB No. 110, the Staff continues to
allow use of the simplified rule for estimating the expected term of plain
vanilla options until such time as the relevant data do become widely available.
The Company does not expect the effects of this bulletin to have any affect on
its financial statements at this time.
NOTE 3 - EQUITY COMPENSATION PLANS
-------------------------
Stock Options
-------------
Effective July 1, 2006, the Company adopted the fair value recognition
provisions of Statement of Financial Accounting Standard 123(R) "Share-Based
Payment" ("SFAS 123(R)") using the modified prospective transition method. In
addition, the Securities and Exchange Commission issued Staff Accounting
Bulletin No. 107 "Share-Based Payment" ("SAB 107") in March, 2005, which
provides supplemental SFAS 123(R) application guidance based on the views of the
SEC. Under the modified prospective transition method, compensation cost
recognized in the quarterly and year-to-date periods ended March 31, 2007
include: (a) compensation cost for all share-based payments granted prior to,
but not yet vested as of July 1, 2006, based on the grant date fair value
estimated in accordance with the original provisions of SFAS No. 123, and (b)
compensation cost for all share-based payments granted beginning July 1, 2006,
based on the grant date fair value estimated in accordance with the provisions
of SFAS 123(R). In accordance with the modified prospective transition method,
results for prior periods have not been restated.
The Company currently has two 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, 2007.
The adoption of SFAS 123(R) resulted in stock compensation expense for the three
and six months ended December 31, 2007 and 2006 of $23,649 and $47,298 and
$27,000 and $81,508, respectively, to income from continuing operations and
income before income taxes. This expense did not have a significant effect on
diluted earnings per share for the quarter, or year-to-date periods ended
December 31, 2007 and 2006.
NOTE 4 - INCOME TAXES
------------
The Company uses the asset and liability method of accounting for deferred
income taxes. Deferred tax assets and liabilities are determined based on the
temporary differences between the financial statement and tax basis of assets
and liabilities. Deferred tax assets or liabilities at the end of each period
are determined using the tax rate in effect at that time.
The total future deferred income tax liability is extremely complicated for any
energy company to estimate due in part to the long-lived nature of depleting oil
and gas reserves and variables such as product prices. Accordingly, the
liability is subject to continual recalculation, revision of the numerous
estimates is required, and may change significantly in the event of such things
as major acquisitions, divestitures, product price changes, changes in reserve
estimates, changes in reserve lives, and changes in tax rates or tax laws.
8
NOTE 5 - CONTINGENCIES AND DRILLING COMMITMENTS
--------------------------------------
In January 2007 Aspen entered into a venture to explore for gold in Alaska with
Hemis Corporation, with offices in Las Vegas, Nevada, whereby Hemis will provide
all funding and be the operator of a venture to carry out permit acquisition and
exploration for commercial quantities of gold. If such deposits are found, Hemis
intends to produce and sell the gold as well as any other commercially valuable
minerals that may occur with the gold. Hemis has commenced work to obtain
permits for the project.
Aspen is paid $50,000 on each anniversary of the agreement so long as Hemis
continues work in the area. The payment ceases when and if production begins.
Aspen retained a 5% production royalty, which may be taken in kind or in cash as
Aspen prefers. Aspen provided to Hemis exploration data assembled and gathered
by Aspen over a period of several years in the 1980's. Permits will be required
before Hemis may commence work and there is no assurance such needed permits
will be issued by the State of Alaska or by the Federal government.
The Company and Enserco Energy, Inc. entered into a "Contract for Sale and
Purchase of Natural Gas" dated November 1, 2005. Aspen and Enserco have
continuously renewed this contract since then. On January 30, 2007 Aspen agreed
to sell and Enserco agreed to purchase 2,000 MMBTU (million BTUs or British
Thermal Units) of gas per day at a fixed price of $7.65 per MMBTU less
transportation and other expenses during the period April 1, 2007 through
October 31, 2007. On April 12, 2007, the Company entered into a subsequent
renewal of the gas sales contract to sell Enserco 2,000 MMBTU of gas per day at
a fixed price of $9.02 per MMBTU less transportation and other expenses during
the period from November 1, 2007 through March 31, 2008.
Aspen's sales of natural gas under the Enserco Contract qualify for the "Normal
Purchases and Normal Sales" exception in paragraph 10(b) of FAS 133. The Enserco
Contract contains net settlement provisions should the Company fail to deliver
natural gas when required under the Enserco Contract. Those provisions are
mutual and establish the sole and exclusive remedy of the parties in the event
of a breach of a firm obligation to deliver or receive natural gas. The
provisions are summarized as follows:
(i) In the event of a breach by Aspen on any day, Aspen would be required
to pay Enserco an amount equal to the positive difference, if any,
between the purchase price and transportation costs paid by Enserco
purchasing replacement natural gas and the amount of Aspen's default;
or
(ii) In the event of a breach by Enserco on any day, Enserco must pay to
Aspen any losses incurred by Aspen after attempting the resale of the
natural gas; or
(iii) In the event that Enserco has used commercially reasonable efforts to
replace the natural gas not delivered by Aspen, or Aspen has used
commercially reasonable efforts to sell the undelivered natural gas to
a third party and no such replacement or sale is available, the sole
and exclusive remedy of the performing party shall be any unfavorable
difference between the contract price and the spot price, adjusted for
transportation.
The natures of the penalties are based on the current market prices and
therefore are variable. Aspen has met its obligations under the contract since
the inception of the contract, and expects to continue to have sufficient gas
available for delivery to fulfill current contractual delivery quantity
obligations from anticipated production from the Company's California fields.
In March or April, 2008, Aspen is scheduled to acquire a 12-square mile
3D-seismic survey directly south of Aspen's successful West Grimes project in
Colusa County, California. The new Strain Ventures project encompasses parts of
the West Grimes and Buckeye Gas Fields, and includes a sparsely drilled area
west of these fields. Aspen anticipates several prospects will be identified on
the new 3D-survey, some of which may be scheduled for drilling in the fall of
2008. Aspen has a 32% working interest in the Strain Ventures project.
Aspen has agreed to participate in a new exploration program operated by a third
party in the Malton area in Glenn and Tehama Counties, California. This area is
east of Aspen's Malton project. Several prospects have been identified by the
Operator in this area, and drilling is scheduled to begin in Spring, 2008. Aspen
has agreed to acquire a non-operated, 7% Working Interest in the project.
9
NOTE 5 - CONTINGENCIES AND DRILLING COMMITMENTS (Continued)
--------------------------------------
Aspen plans to drill one additional well in its Johnson Unit of the Malton
Field. The Johnson 13 well targets a prolific Forbes Formation objective that
appears to be fault separated from other wells in the unit. Aspen has a 31%
working interest in the unit. To the extent that Aspen has available capital and
has identified other appropriate drilling or exploration opportunities, Aspen
may participate in the drilling of additional wells.
For the period January 1 through June 30, 2008, Aspen estimates that Aspen's
share of seismic acquisition, drilling, and completion costs will be as follows.
This does not include the share that Aspen may bill to other working interest
participants where Aspen operates the wells. We also may incur expenses in
connection with our Poplar Field prospect in Montana, but these have not yet
been quantified.
3D-Seismic Completion &
Area Acquisition Wells Drilling Costs Equipping Costs Total
---------------------------------- -------------- -------------- -------------- ----------------- --------------
West Grimes Gas Field
Colusa County, CA $200,000 0 $ -- $ -- $ 200,000
Malton Gas Field
Glenn and Tehama Counties, CA 150,000 6 375,000 200,000 725,000
Cache Creek Gas Field
Yolo County, CA - 1 125,000 50,000 175,000
-------------- -------------- -------------- ----------------- --------------
Total Expenditure $350,000 7 $500,000 $250,000 $1,100,000
============== ============== ============== ================= ==============
NOTE 6 - LONG-TERM DEBT
--------------
In January 2007, the Company 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 in northern Montana. Interest on the
note is charged at LIBOR plus 2.25%. We subsequently entered into an interest
rate swap agreement with Wells Fargo Bank, which fixes the interest rate on the
note at 5.85%. Principal of $16,667 plus interest payments are due monthly
through January 15, 2010. As collateral for this indebtedness, we granted the
bank a security interest on our Accounts Receivables. At December 31, 2007 the
outstanding balance on the note was $416,667, of which $200,000 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 that $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.
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 is
$375,000 plus interest at a rate of 9.0%, and Aspen is 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's share of principal payments of $6,250 plus interest is due monthly
through February 25, 2009. At December 31, 2007, the outstanding balance was
$312,500, of which $75,000 is classified as current.
10
PAGE>
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 December 31, 2007 and 2006 and our financial condition,
liquidity and capital resources as of December 31, 2007 and June 30, 2007. 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 oil and gas sold, the type and volume
of oil and 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, 2007. The
realized prices for natural gas will fluctuate from one period to another due to
regional market conditions and other factors, while oil prices will be
predominantly influenced by world supply and demand. The aggregate amount of oil
and gas produced may fluctuate based on the success of development and
exploitation of oil and gas reserves pursuant to current reservoir management.
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.
We are currently the operator of 64 gas wells in the Sacramento Valley of
northern California. Additionally, we have a non-operated interest in 22 gas
wells in the Sacramento Valley of northern California and non-operating working
interest in approximately 27 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 three and six months ended December 31, 2007, these administrative
charges to the properties helped cover approximately 72% and 58% of our selling,
general and administrative expenses as compared to 47% and 30% for the same
periods of the 2006 fiscal year due primarily to decreases in the issuance of
equity instruments as compensation for services, while management fees increased
24% and 36%, respectively. Management fees as a percentage of our selling,
general and administrative expenses ("SG&A") increased 25% for the period ending
December 31, 2007 compared to 2006 because the company operated 9 more wells
than in the prior period.
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, 2007. Over the past five
years, through our exploration and development activities and property
acquisitions, the Company has been able to increase our oil and gas reserves
11
notwithstanding our production. Since our 2003 fiscal year, only at June 30,
2005, were our reserves at year-end less than our reserves at the previous
year-end. Management uses the measurement of our produced reserves to help
measure the success of our exploration and development activity. Where reserves
are replaced in an amount greater than production, it is a sign that we are
continuing our exploration and development activity successfully. A one-year
decline or increase may not be important to investors, but seeing a decline or
increase over a several year period is a trend worthy of noting, both internally
by management and externally by investors.
We have entered into contracts with Enserco Energy, Inc. to sell about 30% of
our production from April 1, 2007 through March 31, 2008. We expect to have
sufficient gas available for delivery to Enserco from anticipated production
from our California fields.
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 6 years has been 84%. With the use of 3-D seismic
and well control data, interpreted by our geological and geophysical
consultants, we feel we can manage our dry hole risk adequately.
The prices that we receive for the oil and natural gas (including natural gas
liquids) produced are impacted by many factors that are outside of our control.
Historically, these commodity prices have been volatile and we 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.
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.
To manage commercial risk, we may use financial tools to hedge the price we will
receive for our product. The primary purpose of hedging is to provide adequate
return on our investments, grow our reserves while leaving as much commodity
price upside as possible. We have done so through a contract with Enserco
Energy, Inc., since November 1, 2005. Under the current renewal of that
contract, we were contractually obligated to deliver 2,000 MMBTU per day at
$7.65 per MMBTU through October 31, 2007, and then $9.02 per MMBTU through March
31, 2008. These contracts were designated as normal sales contracts.
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 and became obligated for an additional
$375,000 indebtedness as part of that purchase.
Our principal uses of cash are for operating expenses, the acquisition,
drilling, completion and production of prospects, the acquisition of producing
properties, working capital and servicing debt.
During the first six months of our 2008 fiscal year, we used approximately $1.3
million of cash in our operations, investing activities and financing activities
as compared to $3.5 million during the same period of our 2007 fiscal year. The
most significant change resulting in the lower amount of cash used was a change
in cash flows from operations as described in the next paragraph. We used about
$475,000 more cash in investing activities during the six months ended December
31, 2007 than during the prior year, but we used significantly less cash in
financing activities during the six months ended December 31, 2007 as compared
to the same period of our prior fiscal year.
We generated cash of $1.5 million from operations for the six months ended
December 31, 2007, as compared to $931,405 cash used in operating activities for
the six months ended December 31, 2006. This positive change of approximately
$2.5 million was primarily due to an increase in income from operations of
approximately $160,000 (as discussed below in results of operations), and a use
of cash to retire current liabilities ($1.4 million used during the period
12
ending December 31, 2006 compared to $10,000 in the same period in our current
fiscal year). The increase in cash used to pay current liabilities during the
period impacts cash flows immediately in that less cash was used in the period
to satisfy those liabilities; however, the increase is due to the timing of
payments, and cash will be used to satisfy those liabilities in the near term.
In addition, there was less of an increase in accounts receivable ($237,000 in
2007 compared to $1.2 million in 2006).
Investing activities used cash to increase capitalized oil and gas costs of $2.4
million for the six months ending December 31, 2007 as compared to $2.1 million
in the six months ended December 31, 2006. These expenditures are net of the
sale of interests in wells to be drilled charged to third party investors. In
addition, we invested $300,000 in municipal bonds in the current period.
Our working capital surplus (current assets less current liabilities) at
December 31, 2007, was $1.2 million, which reflects a $894,000 decrease from our
working capital at June 30, 2007. As detailed above, this decrease was due
primarily to our negative cash flow of more than $1.3 million during the period
as described in our statements of cash flows. Aspen has just finished a large
drilling program (which is typical for the period for April - November), which
required large expenditures classified as investing activities. This program
resulted in increased production, which together with Aspen's existing
production is generating about $400,000 per month net to Aspen. As Aspen will
not be engaging in significant drilling operations during the January - March
period and Aspen expects that it will continue to receive production revenues at
rates at least similar to prior quarters, Aspen expects that its cash position
and working capital will increase during the winter months of 2008 because of
less drilling activity. This has historically been the pattern of Aspen's
available cash resources.
Planned Oil and Gas Operations
------------------------------
We are in the planning stage for our oil and gas operations that are anticipated
to occur during the last half of our fiscal 2008 (ending June 30, 2008). We
intend to participate in a 3-Dimensional seismic survey in the Strain Ventures
prospect in our West Grimes gas field. We are also planning to participate in
the drilling of several gas wells. Our planning is still at an early stage, and
the estimates set forth below are merely estimates based on the best information
we currently have. As is typically the case with oil and gas operations,
drilling a well may provide us better information about the location for and
costs of subsequent wells in the same area. In addition, better opportunities
may present themselves to us, causing us to defer anticipated drilling for these
other opportunities. The following table sets forth our share of the estimated
costs to complete this program:
3D-Seismic Completion &
Area Acquisition Wells Drilling Costs Equipping Costs Total
---------------------------------- ------------- ------------- ------------- ----------------- -------------
West Grimes Gas Field
Colusa County, CA $200,000 0 $ -- $ -- $ 200,000
Malton Gas Field
Glenn and Tehama Counties, CA 150,000 6 375,000 200,000 725,000
Cache Creek Gas Field
Yolo County, CA - 1 125,000 50,000 175,000
------------- ------------- ------------- ----------------- -------------
Total Expenditure $350,000 7 $500,000 $250,000 $1,100,000
============= ============= ============= ================= =============
We also may incur expenses in connection with our Poplar Field prospect in
Montana, but these have not yet been quantified. We anticipate that our existing
working capital and anticipated cash flow from operations and future successful
drilling activities will be sufficient to finance our drilling and operating
expenses estimated in the foregoing table and as we may otherwise plan for the
next twelve months. Based on national and international concerns, we anticipate
that our gas production will continue to provide us with sufficient cash flow
through our current fiscal year and beyond. As discussed herein, this is
dependent, in part, on maintaining or increasing our level of production and the
national and world market maintaining its current prices for our gas production.
13
If our drilling efforts are successful, the anticipated increased cash flow from
the new gas discoveries, in addition to our existing cash flow, should be
sufficient to fund our share of planned future completion and pipeline costs.
Results of Operations
---------------------
December 31, 2007 Compared to December 31, 2006
-----------------------------------------------
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 six months of fiscal 2007 and 2006:
For the Six Months Ended
-------------------------------------------
December 31, 2007 December 31, 2006
------------------- -------------------
Total Revenues 100.0% 100.0%
Oil and Gas Production Costs 26.1% 16.3%
----------------- -------------------
Gross Profit 73.9% 83.7%
----------------- -------------------
Cost and Expenses
Depreciation and depletion 52.7% 48.6%
Selling, general and administrative 8.8% 27.2%
----------------- -------------------
Total Cost and Expenses 61.5% 75.8%
----------------- -------------------
Income from Operations 12.4% 7.9%
----------------- -------------------
Other Income and Expenses 2.4% 26.6%
Income Before Income Taxes 14.6% 34.3%
Provision for Income Taxes -2.6% -3.7%
----------------- -------------------
Net Income 12.0% 30.6%
================= ===================
14
To facilitate discussion of our operating results for the six months ended
December 31, 2007 and 2006, we have included the following selected data from
our Condensed Consolidated Statements of Operations:
Comparison of the Fiscal Six
Months Ended December, Increase (Decrease)
----------------------------- ------------------------------
2007 2006 Amount Percentage
---------- ---------- ---------- ----------
Revenues:
Oil and gas sales $2,585,597 $2,016,772 $ 568,825 28%
---------- ---------- ---------- ----------
Cost and Expenses:
Oil and gas production 675,801 329,242 346,559 105%
Depreciation and depletion 1,363,091 980,154 382,937 39%
Selling, general and administrative 228,011 548,395 (320,384) -58%
---------- ---------- ---------- ----------
Total Costs and Expenses 2,266,903 1,857,791 409,112 22%
---------- ---------- ---------- ----------
Net Operating Income $ 318,694 $ 158,981 $ 159,713 100%
========== ========== ========== ==========
In general, our operations have been adversely affected by increasing costs of
production and accretion, depletion, depreciation, and amortization; however,
the recent increase in oil and gas prices and production have produced positive
results for the six months ended December 31, 2007. As noted, oil and gas prices
are subject to national and international pressures, and Aspen has no control
over those prices.
For the six months ended December 31, 2007, our operations continued to be
focused on the production of oil and gas, in California and Montana. Our gas
production increased from 314,394 MMBTU sold during the six months ending
December 31, 2006, to 332,339 MMBTU sold in the current period (an increase of
approximately 6%). Prices received also increased approximately 3% over the same
period last fiscal year. As a result of our increased production and prices
during the first six months of our 2008 fiscal year, and the acquisition of oil
properties in Montana, our revenues from oil and gas sales increased during the
2008 period by approximately $600,000 from approximately $2 million to
approximately $2.6 million.
Oil and gas production costs increased by more than double in the six months
ended December 31, 2007, as compared to the same period in 2006, from
approximately $329,000 to almost $676,000. The increase can be attributed to the
addition of gas wells, and our percentage working interests in these wells were
somewhat higher than the average of wells owned at December 31, 2006.
Additionally, all of the costs for the service companies who perform work on
Aspen's wells have increased dramatically. Aspen is attempting to address these
costs, but these costs are driven by market conditions and Aspen's ability to
control these costs is minimal. Generally the costs increase as prices received
for oil and natural gas increase, but costs may increase more quickly than the
prices received.
Depletion, depreciation and amortization expense increased 39%, from
approximately $980,000 for the six months ended December 31, 2006 as compared to
more than $1.36 million during the 2007 period. This increase was the result of
increased investments in oil and gas activities, which resulted in the higher
total depletion taken. Depletion expense per equivalent unit of production
(MCFe) was $3.70 and $3.05 for the six months ending December 31, 2007 and 2006,
respectively.
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 quarter of 2007 and 2006, costs decreased by $236,000, or
30%, due primarily to decreases in the issuance of equity instruments as
compensation for services, while management fees increased 36%. Management fees
as a percentage of SG&A increased 96% for the period ending December 31, 2007
compared to 2006.
A significant ratio presented is the percentage of management fees charged to
operated wells versus our general and administrative costs. This ratio coverage
of general and administrative costs increased from approximately 30% during the
six months ended December 31, 2006 to approximately 58% at December 31, 2007.
15
December 31, December 31,
2007 2006
---------- -----------
Management fees $316,565 $231,942
Selling, general and administrative (SG&A) 544,576 780,337
Management fees as a percentage of SG&A 58.1% 29.7%
Central to an understanding of our financial statements for the six months
operations ended December 31, 2007 is the discussion of changes in oil and gas
sales, volumes of natural gas sold and the price received for those sales. We
present them here in tabular form:
Gas MMBTU Price/ Oil & NGL Bbls Price/
Sales Sold MMBTU Sales Sold Bbl
---------- ---------- -------- ---------- ---------- ---------
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 81.44
---------- ---------- -------- ---------- ---------- ---------
Year to date 2,190,044 332,339 6.59 395,553 5,112 77.37
---------- ---------- -------- ---------- ---------- ---------
June 30, 2007
lst Quarter 958,171 158,391 6.05 4,762 67 $ 71.07
2nd Quarter 1,051,640 156,003 6.74 2,198 31 70.90
3rd Quarter 1,239,895 173,623 7.14 104,896 1,831 57.29
4th Quarter 936,122 143,540 6.52 120,547 2,057 58.60
---------- ---------- -------- ---------- ---------- ---------
June 30, 2007 $4,185,828 631,557 $ 7.00 $ 232,403 3,986 $ 58.30
---------- ---------- -------- ---------- ---------- ---------
Six-Month Change
----------------
Amount $ 180,233 $ 17,945 $ 0.20 $ 388,593 $ 5,014 $ 6.35
Percentage 9.0% 5.7% 3.1% 5583.2% 5116.8% 8.9%
Oil and gas revenue and volumes sold of our product have shown an increase over
the six months of fiscal 2008. As the table above notes, gas revenue has
increased approximately 9% when comparing the six-month periods ended December
31, 2007 and 2006. Volumes sold increased approximately 5.7%, while the price
received for our gas product increased 3%. The significant increase in oil
revenue is due to the acquisition of working interests in approximately 27 wells
in Montana in the third quarter of fiscal 2007.
Contractual Obligations
-----------------------
The Company and Enserco Energy, Inc. entered into a "Contract for Sale and
Purchase of Natural Gas" dated November 1, 2005. Aspen and Enserco have
continuously renewed this contract since then. On January 30, 2007 Aspen agreed
to sell and Enserco agreed to purchase 2,000 MMBTU (million BTUs or British
Thermal Units) of gas per day at a fixed price of $7.65 per MMBTU less
transportation and other expenses during the period April 1, 2007 through
October 31, 2007. On April 12, 2007, the Company entered into a subsequent
renewal of the gas sales contract to sell Enserco 2,000 MMBTU of gas per day at
a fixed price of $9.02 per MMBTU less transportation and other expenses during
the period from November 1, 2007 through March 31, 2008.
We expect to have sufficient gas available for delivery to Enserco from
anticipated production from our California fields. Aspen's sales of natural gas
under the contracts qualify for the "Normal Purchases and Normal Sales"
exception in paragraph 10(b) of FAS 133. The contract is a normal industry sales
contract that provides for the sale of gas over a reasonable period of time in
the normal course of business.
16
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 not
recognized any write-downs of the full cost pool during the first six months of
2008 or the comparable period in 2007.
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.
17
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 collectibility 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 December
31, 2007, as all receivables are expected to be collected in full.
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 current quarter, 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.
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. The liability is discounted using a credit-adjusted
risk-free rate of 8%. Revisions to the liability could occur due to changes in
well lives, or if federal and state regulators enact new requirements on the
plugging and abandonment of gas wells.
Deferred Taxes
--------------
Deferred income taxes have been determined in accordance with Statement of
Financial Accounting Standards No. 109, "Accounting for Income Taxes." For the
period ended December 31, 2007 the Company recorded income tax provision of
$66,425. 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 oil and
gas reserves, and the depletion of these long-lived reserves.
Off Balance Sheet Arrangements
------------------------------
We have no off balance sheet arrangements and thus no disclosure is required.
Other Developments
------------------
During early November 2007, the Delta Farms #10 well, located in the Butte Sink
Gas Field, Colusa County, California, was directionally drilled to a depth of
5,600 feet and encountered over 100 feet of potential gross gas pay in several
intervals in the Forbes and Kione formations. Production casing was run based on
favorable mud log and electric log responses. Gas sales commenced on November
28, 2007 and is currently producing at a rate of about 250 MCF per day. Aspen
has additional potential locations based on 3-D seismic data and well control on
its 1,000 acre leasehold in this field. Aspen owns a 38% operated working
interest before payout and a 44.3% working interest after payout in this well.
18
As noted in the Company's Form 8-K, filed on January 16, 2008, the Board of
Directors of Aspen Exploration Corporation appointed R.V. Bailey, currently vice
president and chairman of Aspen's Board of Directors, as Aspen's interim chief
executive officer, and Kevan B. Hensman, currently a director of Aspen, as
Aspen's interim chief financial officer. The Board also changed Mr. Bailey's
title to vice president of exploration and administration, and appointed Mr.
Hensman as vice president of operations and finance. These changes were made
because Robert A. Cohan, President of Aspen who formerly held those positions,
has been stricken by a stroke. Mr. Cohan is still participating in Aspen as a
member of the board of directors and will work with Messrs. Bailey and Hensman
and Aspen's consultants, as he is able, to ensure that Aspen's oil and gas
operations continue. The board of directors has determined that these
appointments are temporary until such time as Mr. Cohan is able to resume his
duties.
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." No material changes are have been noted as of the filing of
this 10-QSB.
Item 3. CONTROLS AND PROCEDURES
As of December 31, 2007, we have carried out an evaluation under the supervision
of, and with the participation of our interim Chief Executive Officer and our
interim Chief Financial Officer, of the effectiveness of the design and
operation of our disclosure controls and procedures pursuant to Rule 13a-15
under the Securities and Exchange Act of 1934, as amended.
Based on the evaluation as of December 31, 2007, our interim Chief Executive
Officer and our interim Chief Financial Officer have concluded that our
disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e))
under the Securities Exchange Act of 1934) are effective to ensure that the
information required to be disclosed in the reports that we file or submit under
the Securities Exchange Act of 1934 is recorded, processed, summarized and
reported within the time periods specified in SEC rules and forms.
There was no change in our internal control over financial reporting during the
most recently completed fiscal quarter that has materially affected, or is
reasonably likely to materially affect, our internal control over financial
reporting.
19
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 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 first 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
None.
20
Item 6. EXHIBITS
Exhibit No. Document
-------------------------------------------------------------------------------
31 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
32 Certification Pursuant to 18 U.S.C. ss.1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
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: February 11, 2008 /s/ R.V. Bailey
-------------------------------
R.V. Bailey, interim Chief
Executive Officer
(principal executive
officer)
21