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 September 30, 2004
------------------
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 off 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 the number of shares outstanding of each of the Issuer's classes of
common stock as of the latest practicable date.
Class Outstanding at November 10, 2004
Common stock, $.005 par value 6,235,824
Transitional small business disclosure format: [ ] Yes [ X ] No
Part One. FINANCIAL INFORMATION
Item 1. Financial Statements
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, June 30,
2004 2004
---- ----
Current Assets:
Cash and cash equivalents, including $847,333
and $1,127,874 of invested
cash at September 30, 2004 and June 30, 2004 respectively ....... $ 1,108,204 $ 1,329,376
Precious metals ................................................. 18,823 18,823
Accounts receivables ............................................ 605,166 556,558
Receivable, related party ....................................... 29,401 12,742
Prepaid expenses ................................................ 10,032 16,737
----------- -----------
Total current assets 1,771,626 1,934,236
----------- -----------
Investment in oil and gas properties, at cost (full cost
method of accounting) ........................................... 8,752,284 8,216,136
Less accumulated depletion and valuation allowance .............. (3,386,671) (3,235,171)
----------- -----------
5,365,613 4,980,965
----------- -----------
Property and equipment, at cost:
Furniture, fixtures and vehicles ................................ 112,562 112,562
Less accumulated depreciation ................................... (86,458) (81,958)
----------- -----------
26,104 30,604
----------- -----------
TOTAL ASSETS ............................................... $ 7,163,343 $ 6,945,805
=========== ===========
(Statement Continues)
See notes to Consolidated Financial Statements
2
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
September 30, June 30,
2004 2004
---- ----
Current liabilities:
Accounts payable and accrued expenses ........................... $ 654,890 $ 932,814
Accounts payable - related party (Note 6) ....................... 83,860 70,774
Advances from joint interest owners ............................. 742,611 621,015
Notes payable - current (Note 6), net of discount ............... 112,500 410,719
----------- -----------
Total current liabilities ....................................... 1,593,861 2,035,322
----------- -----------
Asset retirement obligation (Note 3) ............................ 87,582 79,582
Deferred income taxes (Note 9) .................................. 464,483 296,320
----------- -----------
Total long term liabilities ..................................... 552,065 375,902
----------- -----------
Total liabilities ............................................... 2,145,926 2,411,224
----------- -----------
Stockholders' equity:
(Notes 1 and 5):
Common stock, $.005 par value:
Authorized: 50,000,000 shares
Issued and outstanding: At September 30, 2004,
6,235,824 shares and June 30, 2004, 5,958,979 ............... 31,298 29,796
Capital in excess of par value .................................. 6,324,318 6,064,602
Accumulated deficit ............................................. (1,334,607) (1,556,225)
Deferred compensation ........................................... (3,592) (3,592)
----------- -----------
Total stockholders' equity ...................................... 5,017,417 4,534,581
----------- -----------
Total liabilities and stockholders' equity ...................... $ 7,163,343 $ 6,945,805
=========== ===========
See Notes to Consolidated Financial Statements
3
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended
September 30,
2004 2003
---- ----
Revenues:
Oil and gas .............................................. $ 697,553 $ 341,926
Management fees .......................................... 82,057 45,915
Interest and other, net .................................. 4,689 496
---------- ----------
Total Revenues ............................................. 784,299 388,337
---------- ----------
Costs and expenses:
Oil and gas production ................................... 64,361 39,102
Depreciation, depletion and amortization ................. 156,000 127,600
Interest expense ......................................... 3,053 -0-
Selling, general and administrative ...................... 171,104 171,438
---------- ----------
Total Costs and Expenses ................................... 394,518 338,140
---------- ----------
Income before taxes ........................................ 389,781 50,197
---------- ----------
Provision for income taxes ................................. 168,163 -0-
---------- ----------
Net income ................................................. $ 221,618 $ 50,197
========== ==========
Basic income per common share .............................. $ .04 $ .01
========== ==========
Diluted income per common share ............................ $ .04 $ .01
========== ==========
Basic weighted average number of common shares
outstanding ................................................ 6,235,824 5,863,828
========== ==========
Diluted weighted average number of common shares
outstanding ................................................ 6,421,889 5,917,538
========== ==========
The accompanying notes are an integral
part of these statements.
4
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three months ended September 30,
2004 2003
----------------------------------
Cash flows from operating activities:
-------------------------------------
Net income ...................................................... $ 221,618 $ 50,197
Adjustments to reconcile net income to net cash
provided used by operating activities:
Depreciation, depletion and amortization ...................... 156,000 127,600
Stock issued for interest expense ............................. 500 -0-
Deferred income tax provision ................................. 168,163 -0-
Changes in assets and liabilities:
Increase in receivable ........................................ (65,267) (71,446)
Decrease in prepaid expense ................................... 6,705 9,475
Increase (decrease) in accounts payable and
expense ..................................................... (143,242) 213,907
----------- -----------
Net cash provided by operating ................................ 344,477 329,733
----------- -----------
Cash flows from investing activities:
-------------------------------------
Additions to oil and gas properties ........................... (467,629) (139,900)
Purchase of producing properties .............................. (60,520) -0-
----------- -----------
Net cash (used) by investing activities ....................... (528,149) (139,900)
----------- -----------
Cash flow from financing activities:
------------------------------------
Payment of notes payable ...................................... (37,500) -0-
----------- -----------
(37,500) -0-
----------- -----------
Net increase (decrease) in cash and cash equivalents .......... (221,172) 189,833
Cash and cash equivalents, beginning of year .................. 1,329,376 776,566
----------- -----------
Cash and cash equivalents, end of year ........................ $ 1,108,204 $ 966,399
=========== ===========
Other information:
Interest paid................................................. $ 3,053 $ -0-
=========== ===========
The accompanying notes are an integral
part of these statements.
5
ASPEN EXPLORATION CORPORATION
Notes to Condensed Consolidated Financial Statements
(Unaudited)
September 30, 2004
Note 1 BASIS OF PRESENTATION
The accompanying financial statements are unaudited. However, in our
opinion, the accompanying financial statements reflect all adjustments,
consisting of only normal recurring adjustments, necessary for fair
presentation. Interim results of operations are not necessarily indicative
of results for subsequent interim periods or the remainder of the year.
These financial statements should be read in conjunction with our Annual
Report on Form 10-KSB for the year ended June 30, 2004.
Except for the historical information contained in this Form 10-QSB, this
Form contains forward-looking statements that involve risks and
uncertainties. Our actual results could differ materially from those
discussed in this Report. Factors that could cause or contribute to such
differences include, but are not limited to, those discussed in this Report
and any documents incorporated herein by reference, as well as the Annual
Report on Form 10-KSB for the year ended June 30, 2004.
Note 2 RECEIVABLE - RELATED PARTIES
The receivable from related parties constitutes amounts due from officers
and consultants for joint operating costs of wells operated by us. The
transactions are in the normal course of business with the same terms as
other joint owners and are repaid in a normal business cycle.
Note 3 ASSET RETIREMENT OBLIGATION
We have adopted the provisions of Statement of Financial Accounting
Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations."
SFAS No. 143 generally applies to legal obligations associated with the
retirement of long-lived assets that result from the acquisition,
construction, development and/or the normal operation of a long-lived
asset. SFAS No. 143 requires us to recognize an estimated liability for the
plugging and abandonment of our gas wells. We have recognized the future
cost to plug and abandon the gas wells over the estimated useful lives of
the wells in accordance with SFAS No. 143. A liability for the fair value
of an asset retirement obligation with a corresponding increase in the
carrying value of the related long-lived asset is recorded at the time a
producing well is purchased or a drilled well is completed and ready for
production. We will amortize the amount added to the oil and gas properties
and recognize accretion expense in connection with the discounted liability
over the remaining life of the respective well. The estimated liability is
based on historical experience in plugging and abandoning wells, estimated
useful lives based on engineering studies, external estimates as to the
cost to plug and abandon wells in the future and federal and state
6
Note 3 ASSET RETIREMENT OBLIGATION (CONTINUED)
regulatory requirements. The liability is a discounted liability using a
credit adjusted risk-free rate of 6%. Revisions to the liability could
occur due to changes in plugging and abandonment costs, useful well lives
or if federal or state regulators enact new regulations on the plugging and
abandonment of wells.
A reconciliation of our liability for the year ended September 30, 2004 is
as follows:
Asset retirement obligations as of
June 30, 2004 $79,582
ARO additions 8,000
Liabilities settled -0-
Accretion expense -0-
Revision of estimate -0-
-------
Asset retirement obligation as of
September 30, 2004 $87,582
=======
Note 4 EARNINGS PER SHARE
We follow Statement of Financial Accounting Standards ("SFAS") No. 128,
addressing earnings per share. SFAS No. 128 established the methodology of
calculating basic earnings per share and diluted earnings per share. The
calculations differ by adding any instruments convertible to common stock
(such as stock options, warrants, and convertible preferred stock) to
weighted average shares outstanding when computing diluted earnings per
share.
The following is a reconciliation of the numerators and denominators used
in the calculations of basic and diluted earnings per share. We had a net
income of $221,618 for the three months ended September 30, 2004 and
$50,197 for the three months ended September 30, 2003.
Three Months Ended
September 30, 2004 September 30, 2003
-------------------------------------- --------------------------------------------
Per Per
Net Share Net Share
Income Shares Amount Income Shares Amount
---------- --------- ------- ---------- --------- -----------
Basic earnings per share:
Net income and share amounts $ 221,618 6,235,824 $ .04 $ 50,197 5,863,828 $ .01
Dilutive securities:
stock options -- 392,000 -- -- 776,000 --
Repurchased shares -- (205,935) -- -- (722,290) --
---------- ---------- ------- ---------- --------- -----------
Diluted earnings per share:
Net income and assumed share
conversion $ 221,618 6,421,889 $ .04 $ 50,197 5,917,538 $ .01
========== ========== ======= ========== ========== ===========
7
Note 5 STOCKHOLDERS' EQUITY
Common Stock
------------
During 2004, we issued a convertible debenture and detachable warrants to
one accredited investor in exchange for the investor's payment to us of
$300,000. On July 15, 2004, the debt and accrued interest were converted.
On July 15, 2004 the debenture was automatically converted into shares of
our restricted common stock after our shares traded at prices greater than
$1.00 per share for ten trading days. We issued 300,500 shares of our
restricted common stock in satisfaction of the principal and interest due
the investor. The debt and unamortized discount related to warrants were
recorded to equity upon conversion. See Note 6.
The convertible debenture included warrants for up to 600,000 shares of
common stock exercisable as follows:
There are potentially two warrants, each for 300,000 shares of common
stock. If the holder exercises the initial warrant before June 30, 2005, we
will receive an additional $330,000 ($1.10 per share) and issue 300,000
shares of stock; if the holder exercises the same warrant before June 30,
2006 but after June 30, 2005, we receive an additional $360,000 ($1.20 per
share) instead of $330,000 and no new warrants will be issued.
If the holder exercises the initial warrant before March 31, 2005, the
holder will receive an additional warrant exercisable to purchase another
300,000 shares at $1.25 per share.
In any case, the warrant (and any additional warrant) will expire unless
exercised by June 30, 2006.
The warrants were valued using the Black-Scholes valuation method at
$39,281 and have been recorded as a discount to the debt.
Stock Options
-------------
During fiscal 2004, two officers, one director, a consultant and an
employee exercised their options for 192,000 shares of our common stock
granted March 14, 2002 at an average price of $0.57 per share. As
consideration for the option shares purchased, the individuals surrendered
common stock with a fair value equal to the exercise price of the option
shares and held longer than six months. The fair value of the shares
surrendered was based on a ten-day average bid price immediately prior to
the exercise date. Total shares surrendered were 96,849. The effect of the
transaction is a net increase to the common stock par value of $476 and a
corresponding decrease to additional paid in capital of $476.
On August 15, 2004, one officer, a consultant and an employee exercised
options for 92,000 shares of our common stock granted March 14, 2002 at an
average price of $0.57 per share. As consideration for the options
purchased, the individuals surrendered common stock with a fair value equal
to the exercise price of the option shares and held longer than six months.
The fair value of the shares surrendered was based on a ten-day average bid
price immediately prior to the exercise date. Total shares surrendered were
42,359. The effect of the transaction is a net increase to the common stock
par value of $248 and a corresponding decrease to additional paid in
capital of $248.
8
Note 5 STOCKHOLDERS' EQUITY (CONTINUED)
As of September 30, 2004, we had an aggregate of 392,000 common shares
reserved for issuance under our stock option plans. These plans provide
for the issuance of common shares pursuant to stock option exercises,
restricted stock awards and other equity based awards.
The following information summarizes information with respect to options
granted under our equity plans:
Number of Weighted Average Exercise
Shares Price of Shares Under Plans
------ ---------------------------
Outstanding balance June 30, 2004 484,000 $ .57
=====
Granted -0- -
=====
Exercised (92,000) .57
======
Forfeited or expensed -0- -
======
------
Outstanding balance September 30, 2004 392,000 $ .57
======= ======
The following table summarizes information concerning outstanding and
exercisable options as of September 30, 2004:
Outstanding Exercisable
------------------------------ -------------------------
Weighted
Average Weighted Weighted
Remaining Average Average
Exercise Number Contractual Exercisable Number Exercise
Price Outstanding Life In Years Price Exercisable Price
----- ----------- ------------- ----- ----------- -----
$.57 242,000 08/15/2005(1) $.57 -0- $.57
.57 150,000 08/15/2007(1) .57 -0- .57
-------
392,000
=======
(1) The term of the option will be the earlier of the contractual life of the
options or 90 days after the date the optionee is no longer an employee,
consultant or director of the Company.
We account for the two stock option plans using APB No. 25 for directors and
employees and SFAS No. 123 for consultants. There were 676,000 options granted
in 2002. Directors and employees were granted 601,000 and consultants were
granted 75,000. The consultant options were valued using the fair value method
of SFAS No. 123 as calculated by the Black-Scholes option-pricing model. The
fair value of each option grant, as opposed to its exercisable price, is
estimated on the date of grant using the Black-Scholes option-pricing model with
the following weighted average assumptions: no dividend yield, expected
volatility of 14.9%, credit adjusted risk free interest rates of 8.5% and
expected lives of 3.4 to 4.4 years. The resulting compensation expense relating
to the consultant option grant will be included as an operating expense as the
options vest.
9
Note 6 NOTES PAYABLE
The Company incurred the following debt:
September 30, June 30,
2004 2004
--------------------------
Note payable to a bank $ 112,500 $ 150,000
Convertible debenture issued to a
privately held corporation -0- 300,000
--------- ---------
112,500 450,000
--------- ---------
Less discount -0- (39,281)
--------- ---------
$ 112,500 $ 410,719
========= =========
Proceeds from the note payable to a bank were used for the acquisition of
producing gas properties located in several counties in the Sacramento
Valley, California. The note matures in June 2005, principal payments are
$12,500 per month plus interest at the bank's prime rate plus 2%. The rate
was 6.75% at September 30, 2004. The loan is collateralized by accounts
receivable, other rights to payments and all inventory.
On June 28, 2004, we issued the convertible debenture to the accredited
investor in exchange for the investor's payment to us of $300,000. The
convertible debenture with a principal amount of $300,000, bears interest
at 4% per annum and 300,000 common stock warrants. The debenture was
converted to common stock on July 15, 2004. See Note 5. Another 300,000
shares are potentially issuable under certain circumstances.
On July 15, 2004 the debenture was automatically converted into shares of
our restricted common stock after our shares traded at prices greater than
$1.00 per share for ten trading days. We issued 300,500 shares of our
restricted common stock in satisfaction of the principal and interest due
the investor.
Note 7 SEGMENT INFORMATION
We operate in one industry segment within the United States, oil and gas
exploration.
Identified assets by industry are those assets that are used in our
operations in that industry. Corporate assets are principally cash,
furniture, fixtures and vehicles.
10
Note 7 SEGMENT INFORMATION (CONTINUED)
We have adopted SFAS No. 131, "Disclosures about Segments of an Enterprise
and Related Information." SFAS No. 131 requires the presentation of
descriptive information about reportable segments which is consistent with
that made available to the management of the Company to assess performance.
Our oil and gas segment derives its revenues from the sale of oil and gas
and prospect generation and administrative overhead fees charged to
participants in our oil and gas ventures. Corporate income is primarily
derived from interest income on funds held in money market accounts.
During the three months ended September 30, 2004 and 2003, there were no
intersegment revenues. The accounting policies applied by each segment are
the same as those used by us in general.
There have been no differences from the last annual report in the basis of
measuring segment profit or loss. There have been no material changes in
the amount of assets for any operating segment since the last annual report
except for the oil and gas segment which capitalized approximately $528,149
for the development and acquisition of oil and gas properties.
Segment information consists of the following for the three months ended
September 30:
Oil and Gas Corporate Consolidated
----------- --------- ------------
Revenues:
2004 $ 779,610 $ 4,689 $ 784,299
2003 387,841 496 388,337
Income (loss) from operations:
2004 $ 560,696 $ (170,915) $ 389,781
2003 225,739 (175,542) 50,197
Identifiable assets:
2004 $ 5,589,338 $ 1,574,005 $ 7,163,343
2003 4,225,438 1,269,291 5,494,729
Depreciation, depletion and valuation charged to identifiable assets:
2004 $ (3,386,671) $ (86,458) $ (3,473,129)
2003 (2,797,469) (68,778) (2,866,247)
Capital expenditures:
2004 $ 528,149 $ -0- $ 528,149
2003 139,900 -0- 139,900
11
Note 8 MAJOR CUSTOMERS
We derived in excess of 10% of our revenue from various sources (oil and
gas sales) as follows:
The Company
-----------
A B C
- - -
Quarter ended:
September 30, 2004 26% 55% 11%
September 30, 2003 29% 53% -
Note 9 INCOME TAXES
We have recorded deferred income taxes of $464,483 and $131,350 as of
September 30, 2004 and 2003, respectively. During the first quarter of
2004, we used approximately $345,000 in net operating loss carryforwards
leaving approximately $1,339,000 in available federal net operating loss
carryforwards as of September 30, 2004. During the first quarter of 2003,
we used approximately $50,000 in net operating loss carryforwards leaving a
total of approximately $1,746,000.
The deferred tax consequences of temporary differences in reporting items
for financial statement and income tax purposes are recognized, if
appropriate. Realization of future tax benefits related to the deferred tax
assets is dependent on many factors, including our ability to generate
taxable income within the net operating loss carryforward period. We have
considered these factors in reaching our conclusion as to the valuation
allowance for financial reporting purposes. Primarily, our proved oil and
gas reserves substantially exceed our expected future costs and hence, we
believe it more likely than not that the benefit will be realized.
At September 30, the income tax effect of temporary differences comprising
the deferred tax assets and deferred tax liabilities on the accompanying
balance sheet is the result of the following:
2004 2003
---------- ----------
Deferred tax assets:
Federal tax loss
carryforwards $ 519,760 $ 699,646
Asset retirement obligation 4,727 -
--------- ---------
524,487 699,646
--------- ---------
Deferred tax (liabilities):
Property, plant and
equipment (2,569) (3,324)
Oil and gas properties (986,401) (827,672)
--------- ---------
(988,970) (830,996)
--------- ---------
$(464,483) $(131,350)
========= =========
12
Note 9 INCOME TAXES (CONTINUED)
A reconciliation between the statutory federal income tax rate (34%) and
the effective rate of income tax expense for the two years ended September
30 is as follows:
2004 2003
---------- --------
Statutory federal income
tax rate 34% 34%
Statutory state income tax
rate, net of federal benefit 9% 9%
-------- --------
Effective rate 43% 43%
======== ========
The provision for income taxes consists of the following components:
2004 2003
---------- ---------
Current tax expense,
state $ -0- $ -0-
Deferred tax expense 168,163 -0-
---------- ---------
Total income tax provision $ 168,163 $ -0-
========== =========
We have available federal net operating loss carryforwards of approximately
$1,339,000 (net operating losses expire beginning June 30, 2011 through the
year ending June 30, 2023).
Note 10 DRILLING COMMITMENTS AND CONTINGENCIES
We have a proposed drilling budget for the period October through December
2004. The budget includes drilling one well in the Sacramento gas province
of northern California and the completion of the Verona Pipeline. Our share
of the estimated costs to complete this program is set forth in the
following table:
Completion &
Area Wells Drilling Costs Equipping Costs Total
-------------------------- ----------- ----------------------- ------------------------- -------------
West Grimes Field 1 $105,000 $71,000 $176,000
Colusa County, CA
Verona Pipeline - 120,000 120,000
----------- ----------------------- ------------------------- --------------
Total Expenditure 1 $105,000 $191,000 $296,000
=========== ======================= ========================= ==============
13
Note 11 SUBSEQUENT EVENTS
The Meckfessel #1-24, located in the Buckeye Gas Field, Colusa County,
California, was drilled to a depth of 8,624 feet, and encountered 40 feet
of gas pay in the Forbes formation. The upper portion of this zone was
perforated and tested at a stabilized rate of 2,181 MCFPD on a 1/4 inch
choke. This was the fourth consecutive successful well drilled on a
recently acquired farmout package consisting of six quality drilling
prospects which are leased and defined by 3-D seismic data and well
control. Aspen has a 28.75% operated working interest in these wells.
The Swanson #22-1, located in the Rice Creek Gas Field, Tehama County,
California, was drilled to a depth of 5,485 feet and encountered gas pay in
the Forbes Formation. This zone was perforated and tested at a stabilized
rate of 370 MCFPD of gas with a flowing tubing pressure of 1,165 psig and a
flowing casing pressure of 1,165 psig. The shut in tubing pressure was
1,860 psig. Gas sales commenced on October 22, 2004. Aspen has a 34.48%
operated working interest in this well. Aspen has drilled 5 producing gas
wells out of 6 attempts in this field.
The Morris #12-2, located in the West Grimes Field, Colusa County,
California, was drilled to a depth of 8,400 feet and encountered
approximately 73 feet of net gas pay (100 feet gross) in the Forbes
Formation. This zone was perforated and tested at a stabilized rate of
4,845 MCFPD of gas with a flowing tubing pressure of 3,350 psig and a
flowing casing pressure of 3,400 psig. The shut in tubing pressure was
3,475 psig. This well was put on line in October 2004 at a flow rate of
3,000 MCFPD with a flowing tubing pressure of 3,400 psig. The first 3 wells
drilled in this field were successful and are currently producing. The
fourth well in this project, the WGU #15-9, commenced drilling on October
23, 2004. These wells were drilled based on a recently acquired 10.5 square
mile 3-D seismic program located over Aspen's 5,000 plus leased acres in
this field. Approximately 10 additional drilling prospects have been
identified. The wells in this field produce from multiple Forbes intervals
ranging in depth from 6,000 feet to 8,500 feet and have produced over 80
BCF of gas to date. Numerous wells in this immediate area have produced at
very prolific flow rates (4,000 MCFPD), have yielded per well reserves (3
to 4 BCF per well), and have long productive well lives. Several of the 10
producing wells that Aspen acquired in this field last year have been
producing for 40 years.
The Griffin #1-1, located in the Winters Gas Field, Yolo County,
California, was drilled to a depth of 5,000 feet, and encountered 15 net
feet of extremely permeable and porous gas pay in the McCune Sand. This
zone was perforated and tested at a stabilized rate of 1,385 MCFPD on a
12/64 inch choke. There was very little pressure drawdown during the flow
test. The shut in pressure is approximately 2,000 psig.
During the last 4 years, Aspen participated in the drilling of 23 operated
wells, 20 of which were completed as gas wells and 3 dry holes which were
plugged and abandoned, a success rate of 87%. Aspen currently operates 48
gas wells and has non-operated interests in 15 additional wells in the
Sacramento Valley of northern California. Aspen has entered into fixed
contracts for a portion of its gas, at prices as high as $8.75 per MMBtu
for the five month period from November 2004 through March 2005.
14
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
This segment should be read in conjunction with the management's discussion
and analysis of financial condition and results of operations contained in our
Annual Report on Form 10-KSB for the year ended June 30, 2004, which has been
filed with the Securities and Exchange Commission. 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. These risks,
uncertainties and contingencies include, without limitation, the factors set
forth in our Form 10-KSB under "Item 6. Management's Discussion and Analysis of
Financial Conditions or Plan of Operation - Factors that may affect future
operating results." We have no obligation to update or revise any such
forward-looking statements that may be made to reflect events or circumstances
after the date of this Form 10-QSB.
Overview
--------
Aspen Exploration Corporation was organized in 1980 for the purpose of
acquiring, exploring and developing oil and gas and other mineral 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. We are currently the operator of 48 gas wells and have a
non-operated interest in 15 additional gas wells.
We currently have offices in Bakersfield, California and Denver, Colorado
and have 2 full time employees as well as the Chairman of the Board who
allocates a portion of his time to the Company. We also make extensive use of
consultants for the conduct of our business, ranging from financial,
engineering, land, legal, and geological and geophysical specialists.
We will typically review 20 to 25 prospects for every well we participate
in, using 3-D seismic and well control geology to evaluate each prospect. Our
goal is to identify low to moderate risk wells with good gas reserve potential.
Where possible, we attempt to be the operator of each property we invest
in. Our knowledge of drilling and operating wells in the Sacramento Valley
allows us to maximize the potential return of each property. Administrative
charges to the properties help cover approximately 33% of our selling, general
and administrative expenses.
Outlook and Trends
------------------
We expect our natural gas production to increase substantially during
fiscal 2005 due to recent drilling successes. Total production for the year will
15
depend on the number of wells successfully completed, the date they are put on
line, their initial rate of production, and their production decline rates. We
also anticipate that the average price for our product will be in the range of
$5.00 to $7.25 per MMBTU for the fiscal year ended June 30, 2005.
Over the past five years we have been able to replace our produced reserves
and increase our yearly natural gas production. We have also benefited from a
general increase in natural gas prices over the past two years, from a low of
$2.78 per MMBTU average during the first quarter of fiscal 2003 to $5.31 per
MMBTU for the quarter ended September 30, 2004.
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 ratio over the past four years has been 87%. 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 as well as
anyone in the industry.
Commodity prices are impacted by many factors that are outside of our
control. Historically, commodity prices have been volatile and we expect them to
remain volatile. Commodity prices are affected by changes in market demands,
overall economic activity, weather, pipeline capacity constraints, inventory
storage levels, 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. During the period November 1, 2004 through
March 31, 2005, we are contractually obligated to deliver 4,000 MMBTU per day to
two of our natural gas purchasers as follows:
2,000 MMBTU/Day @ $7.97 per MMBTU
1,000 MMBTU/Day @ $6.90 per MMBTU
500 MMBTU/Day @ $7.52 per MMBTU
500 MMBTU/Day @ $8.75 per MMBTU
The average price received during the first quarter of fiscal 2005 for our
natural gas was approximately $5.31 per MMBTU.
During December 2003, we borrowed $225,000 from a bank for a modest
acquisition. We currently pay 2% over the bank's prime rate for that facility.
At September 30, 2004, the effective interest rate was 6.75% and the outstanding
loan balance was $112,500. In June 2004, we borrowed $300,000 from an Oklahoma
corporation to facilitate the drilling and completion of several wells in
northern California. This debt was converted to our common stock on July 15,
2004.
16
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. Our principal uses of cash are for
operating expenses, the acquisition, drilling and production of prospects, the
acquisition of producing properties, working capital, servicing debt and the
payment of income taxes.
Cash of $344,477 and $329,733 was provided by our operations for the three
months ended September 30, 2004 and 2003. Even though the 2003 period generated
a modest net income of $50,197, we were able to generate a comparable positive
cash flow from operations during the first three months of fiscal 2003 as
compared to the 2004 period (when we generated net income of $221,618) because
of:
Lower depreciation, depletion and amortization expenses ($127,600 in 2003
as compared to $156,000 in 2004); and
A $213,907 increase in accounts payable and accrued expenses in 2003 (which
conserved cash during the 2003 period) compared to an $143,242 reduction in
accounts payable and accrued expenses in 2004 (which required cash
payments).
Investing activities used cash to increase capitalized oil and gas costs of
$528,149 and $139,900 in the three months ended September 30, 2004 and 2003.
Cash in the current three month period ended September 30, 2004 was used for
lease acquisition, seismic work, intangible drilling and well workovers
($353,279), and the purchase of oil and gas well equipment ($174,870). These
expenditures are net of the sale of interests in wells to be drilled charged to
third party investors.
We have a proposed drilling, completion and construction budget for the
period October through December 2004. The budget includes drilling one well in
the Sacramento gas province of northern California and the completion of the
Verona Pipeline. Our share of the estimated costs to complete this program over
the next three months is set forth in the following table:
Completion &
Area Wells Drilling Costs Equipping Costs Total
-------------------------- ------------- ----------------------- ------------------------- --------------
West Grimes Field 1 $105,000 $71,000 $176,000
Colusa County, CA
Verona Pipeline - 120,000 120,000
------------- ----------------------- ------------------------- -- --------------
Total Expenditure 1 $105,000 $191,000 $296,000
============= ======================= ========================= ==============
Our working capital (current assets less current liabilities) at September
30, 2004, was $177,765, which reflects an approximate $279,000 increase from our
working capital deficit at June 30, 2004. Our working capital situation improved
during the first quarter of our 2005 fiscal year because of our positive cash
17
flow from operations and our ability to pay down our current liabilities, both
made possible by our increase in net revenues and in net income recognized
during the quarter. We anticipate that our working capital and anticipated cash
flow from operations and future successful drilling will be sufficient to pay
our current liabilities as long as our gas production continues to provide us
with sufficient cash flow. As discussed below, 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.
Our capital requirements can fluctuate over a twelve month period because
our drilling program is usually carried out in California's dry season, from
late April until November, after which wet weather either precludes further
activity or makes it cost prohibitive.
We believe that internally generated funds will be sufficient to finance
our drilling and operating expenses for the next twelve months. In June 2004, we
borrowed $300,000 from an Oklahoma corporation to facilitate the drilling and
completion of several wells in northern California. This debt and accrued
interest were converted into 300,500 shares of our common stock at $1.00 per
share on July 15, 2004. 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.
18
Results of Operations
---------------------
September 30, 2004 Compared to September 30, 2003
-------------------------------------------------
For the three months ended September 30, 2004, our operations continued to be
focused on the production of oil and gas, and the investigation for possible
acquisition of producing oil and gas properties in California. During the 2004
period our revenues increased by more than $395,000 as compared to the
comparable period of our 2003 fiscal year because of:
Increased production (130,000 MMBTU sold as compared to 72,600 MMBTU sold
during the first three months of our 2003 fiscal year);
Increased price received for our production (an average of $5.31 per MMBTU
during the first three months of our 2005 fiscal year as compared to $4.75
per MMBTU received during that period in 2004); and
Increased management fees received ($82,100 during fiscal 2005 as compared
to $45,900 during fiscal 2004) because we were operators of more wells
during 2005 (48 wells compared to 33 wells in 2004).
19
The following table sets forth certain items from our Condensed Consolidated
Statements of Operations as expressed as a percentage of total revenues, shown
by quarter for the three months of fiscal 2004, 2003 and 2002:
For the Three Months Ended
---------------------------------------
9/30/2004 9/30/2003 9/30/2002
--------- ---------- -----------
Total revenues 100.0% 100.0% 100.0%
Oil & gas production costs 8.2 10.1 14.3
--------- ------------- ------------
Income from operations 91.8 89.9 85.7
--------- ------------- ------------
Costs and expenses
Depreciation and depletion 19.9 32.9 32.2
Selling, general and administrative 21.8 44.1 70.1
Interest expense .3 .0 .0
--------- ------------- ------------
Total costs and expenses 42.0 77.0 102.3
--------- ------------- ------------
Income before income taxes 49.8 12.9 (16.6)
Provision for income taxes 21.4 .0 .0
--------- ------------- ------------
Net income (loss) 28.4 12.9 (16.6)
========= ============= ============
To facilitate discussion of our operating results for the three months ended
September 30, 2004 and 2003, we have included the following selected data from
our Condensed Consolidated Statements of Operations:
Comparison of the Fiscal
Three Months Ended September 30, Increase (Decrease)
---------------------------------------- ---------------------------
2004 2003 Amount Percentage
--------------------------------------------------------------------
Revenues:
Oil and gas sales $ 697,553 $ 341,926 $ 355,627 104%
Management fees 82,057 45,915 36,142 79
Interest and other 4,689 496 4,193 845
--------- --------- --------- ---------
Total revenues 784,299 388,337 395,962 102%
--------- --------- --------- ---------
Cost and expenses:
Oil and gas production 64,361 39,102 25,259 65
Depreciation and depletion 156,000 127,600 28,400 22
Selling, general and administrative 171,104 171,438 (334) --
Interest expense 3,053 -0- 3,053 --
--------- --------- --------- ---------
Total costs and expenses 394,518 338,140 56,378 17%
--------- --------- --------- ---------
Income before taxes 389,781 50,197
Provision for income taxes 168,163 -0-
--------- ---------
Net income $ 221,618 $ 50,197
============================
21
Central to the issue of success of the three months operations ended September
30, 2004 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 (1)
Sales Sold Price/MMBTU
---------- -------- -----------
2005
-----
lst Quarter $ 697,553 130,000 $ 5.31
--------- -------- --------
2004
----
lst Quarter 341,926 72,600 4.75
2nd Quarter 362,942 79,900 4.64
3rd Quarter 401,941 71,900 5.28
--------- -------- --------
Year to date 1,106,809 224,400 4.88
--------- -------- --------
2003
----
lst Quarter 198,431 65,800 2.78
2nd Quarter 241,700 63,700 3.76
3rd Quarter 314,222 57,900 5.47
--------- -------- --------
Year to date 754,353 187,400 3.23
--------- -------- --------
First Quarter change
--------------------
2005
----
Amount $355,627 57,400 $ .56
Percentage 104% 79% 12%
2004
----
Amount $143,495 6,800 $ 1.97
Percentage 72% 10% 71%
(1) Price per MMBTU may not agree with oil and gas sales because of the
inclusion of oil and NGL sales.
Oil and gas revenue, volumes sold and price received for our product have shown
a steady improvement over the first three months of fiscal 2005 and the twelve
months of fiscal 2004. As the table above notes, revenue has increased
approximately 104% when comparing the two three month periods ended September
30, 2004 and 2003. Volumes sold increased approximately 79%, while the price
received for our product increased 12%.
Total revenue increased $396,000, or 104% when comparing the two periods, while
operating and production costs increased $25,300, or 65%.
A significant ratio presented is the percentage of management fees charged to
operated wells versus our general and administrative costs. This coverage of
general and administrative costs improved from approximately 27% for the three
months ended September 30, 2003 to approximately 48% at September 30, 2004.
When comparing general and administrative expense for 2005 and 2004, costs
declined slightly by $334, or 0.2%.
21
Results of operations and net income are presented in the following table:
Quarterly Financial Information (unaudited)
(1) (2) Net Income (loss)
Total Operating Net Income Per Share
Revenues Income (loss) Basic Diluted
---------- ---------- ---------- --------- ---------
2005
------------------- ---------- ---------- ---------- --------- ---------
1st Quarter $ 784,299 $ 715,249 $ 389,781 $ .063 $ .061
---------- ---------- ---------- --------- ---------
2004
-------------------
lst Quarter 388,337 348,739 50,197 .010 .010
2nd Quarter 433,317 365,761 93,022 .010 .010
3rd Quarter 440,127 354,642 76,762 .010 .010
------------------- ---------- ---------- ---------- --------- ---------
Total 1,261,781 1,069,142 219,981 0.04 0.04
---------- ---------- ---------- --------- ---------
2003
-------------------
lst Quarter 264,896 223,246 (41,650) (.01) (.01)
2nd Quarter 279,080 237,155 (15,660) -- --
3rd Quarter 337,476 271,845 28,748 -- --
------------------- ---------- ---------- ---------- --------- ---------
Total $ 881,452 $ 732,246 $ (28,562) -- --
---------- ---------- ---------- --------- ---------
(1) Operating income is oil and gas sales plus management fees less direct
operating costs. (2) Before provision for deferred income taxes.
As can be seen in the table, revenues and operating income have improved in
every quarter when comparing the three month periods ended September 30, 2004
and 2003. We believe this is due to the steady increase in production volumes
sold in each subsequent quarter and the fact that we have enjoyed an
appreciating price received for our product. Operating income has increased
because production costs have increased at a lesser rate than production and
prices.
Contractual Obligations:
------------------------
We had five contractual obligations as of September 30, 2004. The following
table lists our significant liabilities at September 30, 2004:
Payments Due By Period
-----------------------------------------------------------------------------------
Less than After
Contractual Obligations 1 year 2-3 years 4-5 years 5 years Total
----------------------- --------- --------- --------- -------- ---------
Employment Obligations $210,400 $208,300 $127,300 $ -0- $ 546,000
Bank Loans 112,500 -0- -0- -0- 112,500
Operating Leases 12,960 3,850 -0- -0- 16,810
-------- -------- -------- -------- ---------
Total contractual
cash obligations $335,860 $212,150 $127,300 $ -0- $ 675,310
======== ======== ======== ======== =========
We maintain office space in Denver, Colorado, our principal office, and
Bakersfield, California. The Denver office consists of approximately 1,108
square feet with an additional 750 square feet of basement storage. We entered
into a one-year lease agreement on the Denver office through December 31, 2004
22
at a lease rate of $1,261 per month. The Bakersfield, California office has 546
square feet and a monthly rental fee of $730 to $770 over the term of the lease.
The three year lease expires February 8, 2006. Rent expense for the three months
ended September 30, 2004 and 2003 was $6,033 and $5,973, respectively.
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 Condensed
Consolidated Financial Statements.
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 uncollectable 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 additional 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.
23
Property, Equipment, Depreciation and Depletion:
------------------------------------------------
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. Costs associated with production and general
corporate activities are expensed in the period incurred. 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 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.
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 6%. 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.
24
Item 3. CONTROLS AND PROCEDURES
As required by Rule 13a-15 under the Securities Exchange Act of 1934, as of
the filing date of this report, 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 principal executive officer (who is also our principal
financial officer), who concluded that our disclosure controls and procedures
are effective. There have been no significant changes in our internal controls
or in other factors, which could significantly affect internal controls
subsequent to the date we carried out our evaluation.
Disclosure controls and procedures are controls and other procedures that
are designed to ensure that information required to be disclosed in our reports
filed or submitted under the Securities Exchange Act is recorded, processed,
summarized and reported, within the time periods specified in the Securities and
Exchange Commission's rules and forms. Disclosure controls and procedures
include, without limitation, controls and procedures designed to ensure that
information required to be disclosed in our reports filed under the Exchange Act
is accumulated and communicated to management, including our principal executive
officer and our principal financial officer, as appropriate, to allow timely
decisions regarding required disclosure.
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.
------------------------------------------------------------
During 2004, we issued a convertible debenture and detachable warrants to
one accredited investor in exchange for the investor's loan to us of $300,000.
On July 15, 204, the debt was converted to 300,500 share of common stock as
consideration for payment of principal and interest.
The convertible debenture included a potential 600,000 common stock
warrants exercisable as follows:
If the holder exercises the first warrant before June 30, 2005, we will
receive an additional $330,000 ($1.10 per share) and issue 300,000 shares
of stock; if the holder exercises the warrant before June 30, 2006 but
after June 30, 2005, we receive an additional $360,000 ($1.20 per share)
instead of $330,000.
If the holder exercises the warrant before March 31, 2005, the holder will
receive an additional warrant exercisable to purchase another 300,000
shares at $1.25 per share.
In any case, the warrant (and any additional warrant) will expire unless
exercised by June 30, 2006.
25
On July 15, 2004 the debenture was automatically converted into shares of
our restricted common stock after our shares traded at prices greater than $1.00
per share for ten trading days. We issued 300,500 shares of our restricted
common stock in satisfaction of the principal and interest due the investor.
The following sets forth the information required by Item 701 in connection
with that transaction:
(a) The conversion was completed effective July 15, 2004.
(b) There was no placement agent or underwriter for the transaction or the
original transaction that took place in fiscal year 2004.
(c) The shares were not sold for cash. The shares of common stock were issued in
exchange for (and in conversion of) outstanding convertible debt.
(d) We relied on the exemption from registration provided by Sections 3(a)(9)
under the Securities Act of 1933 for the conversion transaction, and upon the
exemptions from registration provided by Sections 4(2), 4(6), and Regulation D
for the issuance of the initial debt. In addition, we did not engage in any
public advertising or general solicitation in connection with this transaction;
and we provided the accredited investor with disclosure of all aspects of our
business, including providing the accredited investor with our reports filed
with the Securities and Exchange Commission, our press releases, access to our
auditors, and other financial, business, and corporate information. Based on our
investigation, we believe that the accredited investor obtained all information
regarding Aspen Exploration it requested, received answers to all questions it
posed, and otherwise understood the risks of accepting our securities for
investment purposes.
(e) The common stock issued in this transaction are not convertible or
exchangeable. Warrants were issued in this transaction as described above. There
are no registration rights associated with the issuance of the common stock or
the warrants.
(f) We received no cash proceeds from the issuance of the shares of common
stock. The original loan made by the accredited investor was used for working
capital and drilling operations.
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.
Item 6. Exhibits.
---------
31. Rule 13a-14(a) Certification
32. Section 1350 Certification
26
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
/s/ Robert A. Cohan
-------------------------------
By: Robert A. Cohan,
November 10, 2004 Chief Executive Officer,
Principal Financial Officer
27