Edgar Filing: ASPEN EXPLORATION CORP

================================================================================

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

----------------------

FORM 10-KSB
(Mark One)

[X] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934.
For the fiscal year ended June 30, 2005

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

For the transition period from _______ to ______

Commission file number: 001-12531

ASPEN EXPLORATION CORPORATION
-----------------------------
(Name of small business issuer in its charter)

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

2050 S. Oneida St., Suite 208
Denver, Colorado 80224-2426
---------------- ----------
(Address of principal executive offices) (Zip Code)

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

Securities registered pursuant to Section 12(b) of the Exchange Act: None

Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $0.005 par value
------------------------------

Check whether the issuer (1) filed all reports required to be filed by
Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such
shorter period that the registrant was required to file such reports), and (2)
has been subject to such filing requirements for the past 90 days. Yes X No __

Check if there is no disclosure of delinquent filers in response to Item
405 of Regulation S-B contained in this form, and no disclosure will be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-KSB
or any amendment to this Form 10-KSB. Yes X No __

Indicate by checkmark whether the issuer is a shell company (as defined in
Rule 12b-2 of the Exchange Act) (check one): Yes __ No XX

Aspen's revenues for the fiscal year ended June 30, 2005 were $4,127,444.

At September 23, 2005, the aggregate market value of the shares held by
non-affiliates was approximately $33,786,719. The aggregate market value was
calculated by multiplying the mean of the closing bid and asked prices ($8.835)
of the common stock of Aspen on the Over-the-Counter Bulletin Board listing for
that date, by the number of shares of stock held by non-affiliates of Aspen
(3,824,190).

At September 23, 2005, there were 6,733,308 shares of common stock (Aspen's
only class of voting stock) outstanding.

Transitional Small Business Disclosure Format (check one): Yes __ No X

================================================================================

PART I

ITEM 1. BUSINESS
----------------

Because we want to provide you with more meaningful and useful information,
this Annual Report on Form 10-KSB contains certain "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, regulation of the
Securities and Exchange Commission, and common law.

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 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-KSB.

Summary of Our Business

Aspen was incorporated under the laws of the State of Delaware on February
28, 1980 for the primary purpose of acquiring, exploring and developing oil and
gas and other mineral properties. Our principal executive offices are located at
2050 S. Oneida St., Suite 208, Denver, Colorado 80224-2426. Our telephone number
is (303) 639-9860, and our facsimile number is 303-639-9863. Our websites are
www.aspenexploration.com and www.aspnx.com and our email address is
aecorp2@qwest.net. We are currently engaged primarily in the exploration and
development of oil and gas properties in California. We have an interest in two
inactive subsidiaries: a 25% interest in Aspen Power Systems, LLC (a company
that has not been engaged in business since 2002), and Aspen Gold Mining Co., a
company that has not been engaged in business since 1995.

Oil and Gas Exploration and Development. Our major emphasis has been
participation in the oil and gas segment, acquiring interests in producing oil
or gas properties and participating in drilling operations. We engage in a broad
range of activities associated with the oil and gas business in an effort to
develop oil and gas reserves. With the assistance of our management, independent
contractors retained from time to time by us, and, to a lesser extent,
unsolicited submissions, we have identified and will continue to identify
prospects that we believe are suitable for drilling and acquisition.

Currently, our primary area of interest is in the state of California. We
have acquired a number of interests in oil and gas properties in California, as
described below in more detail. In addition, we also act as operator for most of
our producing wells and receive management fees for these services.

Company Strategy:

At the present time, we cannot finance our oil and gas acquisitions and
drilling activities solely through our own resources. Consequently, we identify
prospects or production to acquire and drill prospects, and seek other industry
investors who are willing to participate in these activities with us. We
frequently retain a promotional interest in these prospects, but generally we
finance a portion (and sometimes a significant portion) of the acquisition and
drilling costs.

Where we acquire an interest in acreage on which exploration or development
drilling is planned, we will seldom assume the entire risk of acquisition or
drilling. Rather, we prefer to assess the relative potential and risks of each
prospect and determine the degree to which we will participate in the
exploration or development drilling. Generally, we have determined that it is
more beneficial to invite industry participants to share the risk and the reward
of the prospect by financing some or all of the costs of drilling contemplated
wells. In such cases, we may retain a carried working interest, a reversionary
interest, or may be required to finance all or a portion of our proportional
interest in the prospect. Although this approach reduces our potential return
should the drilling operations prove successful, it also reduces our risk and
financial commitment to a particular prospect.

Conversely, we may from time to time participate in drilling prospects
offered by other persons if we believe that the potential benefit from the
drilling operations outweighs the risk and the cost of the proposed operations.
This approach allows us to diversify into a larger number of prospects at a
lower cost per prospect, but these operations (commonly known as "farm-ins") are
generally more expensive than operations where we offer the participation to
others (known as "farm-outs"). As of this writing, we have participated in the
drilling of two farm-in wells.

Principal Products Produced and Services Rendered. Our principal products
during fiscal 2005 were crude oil and natural gas. Crude oil and natural gas are
generally sold to various entities, including pipeline companies, which usually
service the area in which our producing wells are located. In the fiscal year
ended June 30, 2005, crude oil and natural gas sales and revenues from operating
oil and gas properties accounted for $4,119,304, or 99.8% of our total revenues;
while $8,140, or .2%, was from interest and other income.

Distribution Methods of the Products or Services. We are not involved in
the distribution aspect of the oil and gas industry.

Status of any Publicly Announced New Products or Services. We do not have a
new product or service that would require the investment of a material amount of
our assets or which we believe is material to our business. Therefore, we have
not made a public announcement of nor have we made information otherwise public
about any such product or service.

Competitive Business Conditions: The exploration for, and development,
production and acquisition of, oil, gas, precious metals and other minerals are
subject to intense competition. The principal methods of compensation for the
acquisition of oil and gas and other mineral properties are the payment of:

(i) cash bonuses at the time of the acquisition of leases;
(ii) delay rentals and the amount of annual rental payments;
(iii) advance royalties and the use of differential royalty rates; and
(iv) the stipulations requiring exploration and production commitments by
the lessee.

Some of our current competitors, and many of our potential competitors in
the oil and gas industry have vast experience, are larger and have significantly
greater financial resources, existing staff and labor forces, equipment, and
other resources than we do. Consequently, these competitors may be in a better
position to compete for oil and gas projects.

In addition, the availability of a ready market for oil and gas will depend
upon numerous factors beyond our control, including the extent of domestic
production and imports of oil and gas, proximity and capacity of pipelines, and
the effect of federal and state regulation of oil and gas sales, as well as
environmental restrictions on exploration and usage of oil and gas. Further, we
expect that competition for leasing of oil and gas prospects will become even
more intense in the future. We have a minimal competitive position in the oil
and gas industry.

Sources and Availability of Raw Materials: To conduct business, we depend
on such items as drilling rigs and other equipment, casing pipe, drilling mud
and other supplies and equipment necessary for our operations. Such items have
been commonly available from a number of sources. Although we foresee no short
supply or difficulty in acquiring any equipment relevant to the conduct of
business, we cannot offer any assurances that these items will be available or
that we will be able to acquire the items on economically feasible terms.

Dependence Upon One or a Few Major Customers: We generally sell our oil and
gas production to a limited number of companies. In fiscal 2005 we obtained more
than 10% of our revenues from sales to Calpine Corporation and Enserco Energy,
Inc. In fiscal 2004 we obtained more than 10% of our revenues from sales to
Calpine Corporation and Enserco Energy, Inc. and ConocoPhillips. We do not
believe the loss of these customers would adversely impact our revenues because
we believe that oil and gas sales are primarily market driven and are not
dependent on particular purchasers. Consequently, we believe that substitute
purchasers would be available based on the widespread uses of and the need for
oil and gas.

Patents, Trademarks, Licenses, Franchises, Concessions, Royalty Agreements
or Labor Contracts (Including Duration). We do not own any patents, licenses,
franchises, or concessions except oil, gas and other mineral interests granted
by governmental authorities and private landowners. We received a trademark
registration (serial no. 74-396,919 registered on March 1, 1994) for our
corporate logo. The registration is for a term of ten years. To maintain the
registration for its entire term we filed an affidavit of commercial use on
February 21, 2000. We are currently in the process of renewing the trademark
registration.

Need for Governmental Approval of Principal Products or Services. We do not
need to seek government approval of our principal products.

Effect of Existing or Probable Governmental Regulation. Oil and gas
exploration and production are open to significant governmental regulation
including worker health and safety laws, employment regulations and
environmental regulations. Operations that occur on public lands may be subject
to further regulation by the Bureau of Land Management, the U.S. Army Corps of
Engineers, or the U.S. Forest Service as well as other federal and state
agencies.

Estimate of Amounts Spent on Research and Development Activities. We have
not engaged in any material research and development activities since our
inception.

Costs and Effects of Compliance with Environmental Laws (federal, state and
local). Because we are engaged in extracting natural resources, our business is
subject to various federal, state and local provisions regarding environmental
and ecological matters. Therefore, compliance with environmental laws may
necessitate significant capital outlays, affect our earnings potential, and
cause material changes in our current and proposed business activities.

At the present time, however, the environmental laws do not materially
hinder nor adversely affect our business. Capital expenditures relating to
environmental control facilities have not been material to our operations since
our inception.

Employees.

At June 30, 2005, we employed two full-time and one part-time person. We
also employ independent contractors and other consultants, as needed.

ITEM 2. PROPERTIES
------------------

General Information:

We have a significant amount of information regarding the proven developed
and undeveloped oil and gas reserves which can be found in below in this Item 2
as well as in the notes to our financial statements.

Drilling and Acquisition Activity:

During the fiscal year ended June 30, 2005, we participated in the drilling
of 7 gross (1.56 net) operated wells, 7 of which were completed as gas wells,
for a 100% success ratio. Of the 7 wells drilled, 4 gas wells were drilled in
the West Grimes Field, 1 gas well was drilled in the Rice Creek Field, 1 gas
well was drilled in the Winters Field, and 1 gas well was drilled in the Kirk
Buckeye Field.

West Grimes Field, Colusa County, California
--------------------------------------------

The first 4 wells drilled in the West Grimes Gas Field were successful and
are currently producing. One of these wells tested at a prolific stabilized rate
of 4,845 MCFPD of gas with a flowing tubing pressure of 3,350 psig. This well
was put on line at 3,000 MCFPD with a flowing tubing pressure of 3,400 psig.
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. Ten
additional excellent 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 excellent 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. Aspen believes that
several of these wells may have additional gas potential in behind-pipe zones,
which have not yet been perforated. Aspen has a 21% operated working interest in
this field.

Subsequent to the fiscal year ended June 30, 2005, Aspen has drilled 3
additional wells and will drill a fourth well in this field.

The Morris #12-3 well was drilled to a depth of 8,000 feet and encountered
approximately 60 feet of potential net gas pay in various intervals in the
Forbes formation. A Forbes interval was perforated and tested gas at a rate of
2,181 MCFPD. Gas sales commenced on September 8, 2005 and the well is currently
producing at the rate of 825 MCFPD.

The Strain #10-2 well was drilled to a depth of 8,012 feet and encountered
approximately 75 feet of potential gross gas pay in two intervals in the Forbes
formation. One of these Forbes intervals was perforated and tested gas on a
3/16" choke at a stabilized rate of 3,163 MCFPD with a flowing tubing pressure
of 3,900 psig and a flowing casing pressure of 4,000 psig. The shut in tubing
pressure was 4,200 psig. The well only experienced a 7% pressure drawdown while
flowing at the prolific rate of 3,163 MCFPD, which is indicative that this zone
is capable of flowing at a higher gas rate. Gas sales commenced on September 7,
2005 and the well is currently producing at the rate of 500 MCFPD.

The Farnsworth #3-35 well located in the Grimes Gas Field, Colusa County,
California, was drilled to a depth of 7,500 feet and encountered approximately
80 feet of potential gross gas pay in several intervals in the Forbes formation.
Production casing was run based on favorable mud log and electric log responses.
Aspen has a 21.00% operated working interest in this well.

Malton Black Butte
------------------

Aspen has drilled 7 gas wells out of 9 attempts in this field during the
last 4 fiscal years. These wells produce from multiple horizons in the Kione and
Forbes formation from depths ranging from 1,700 feet to 5,000 feet. Aspen has
operated working interests in these wells ranging from approximately 21% to 31%.

Subsequent to the fiscal year ended June 30, 2005, Aspen has drilled the
following 2 wells in this field:

The Johnson Unit #11 well was drilled to a depth of 4,800 feet and
encountered approximately 80 feet of potential gas pay in various intervals in
the Forbes formation. One of the Forbes intervals was perforated and tested gas
at a stabilized rate of approximately 700 MCFPD. The well is currently producing
400 MCFPD. Aspen has a 31% operated working interest in this well.

The Merrill #31-1 well was drilled to a depth of 4,875 feet and encountered
approximately 200 feet of potential net gas pay in various intervals in the
Forbes and Kione formations. One of the Forbes intervals was perforated and
tested gas at a stabilized rate of approximately 700 MCFPD. The well is
currently producing 825 MCFPD. We believe numerous potential gas zones remain
behind-pipe in this well. Aspen has a 31% operated working interest in this
well.

Momentum Farmout, Colusa, Yolo, Sutter and Solano Counties, California
----------------------------------------------------------------------

Aspen acquired a farmout package consisting of 6 quality drilling
prospects, which are leased and defined by 3-D seismic data and well control.
These prospects were drilled (and will be drilled) during the 2004 - 2005
drilling seasons (4 wells in 2004 and 2 wells in 2005). The first well drilled
in this package, the Ettl #1-10, located in the Grimes Gas Field, Sutter County,
California, was drilled to a depth of 7,600 feet to test three potential Forbes
targets. The Grimes Gas Field has produced approximately 650 BCF (billion cubic
feet) of gas and is currently producing 11,000 MCFPD. The well was successfully
completed and commenced gas sales in July 2004 at the rate of 500 MCFPD. The
well is currently flowing 300 MCFPD after over a year of production.

The second well drilled, the Chickohominy #1-12, located in the Winters Gas
Field, Yolo County, California, was drilled to a depth of 5,050 feet, and
encountered 25 feet of extremely permeable and porous potential gas pay in the
Winters Formation. The well was perforated in June 2004, and tested at a stable
gas rate of 2,540 MCFPD with a flowing tubing pressure of 1,725 psig. Gas sales
commenced in August 2004 at a rate of 1,000 MCFPD with a flowing tubing pressure
of 1,900 psig. More than one year later, the well is still flowing 950 MCFPD.

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 gas rate of 1,385 MCFPD on a 12/64 inch choke. Gas
sales commenced in September 2004 at 800 MCFPD and the well is currently flowing
400 MCFPD.

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 prolific
formation has produced nearly 7 billion cubic feet (7 BCF) of gas from a well
located approximately two miles away. Gas sales commenced in November 2004 at
800 MCFPD and the well is currently flowing 375 MCFPD.

This was the fourth consecutive successful well drilled in this farmout
package. The remaining two wells will be drilled in the summer-fall of 2005.

Aspen has a 28.75% operated working interest before payout and a 24.4375%
working interest after payout in these wells.

Kirk-Buckeye Field, Colusa County, California
---------------------------------------------

Aspen has drilled 4 gas wells out of 6 attempts in this field during the
last 3 fiscal years. These wells produce from multiple horizons in the Forbes
formation from depths ranging from 7,500 feet to 9,500 feet. Aspen has operated
working interests in these wells ranging from approximately 15% to 38.67%.

Subsequent to the fiscal year ended June 30, 2005, the Heidrick #11-1 well
was drilled to a depth of 8,532 feet and encountered approximately 80 feet of
potential gross gas pay in several intervals in the Forbes formation. One of
these Forbes intervals was perforated and tested gas on a 3/16 inch choke at a
stabilized rate of 2,283 MCFPD with a flowing tubing pressure of 2,810 psig and
a flowing casing pressure of 2,900 psig. The shut in tubing pressure was 3,360
psig. Aspen has a 38.67% operated working interest in this well.

Sour Grass Prospect, Tehama County, California
----------------------------------------------

The Sour Grass prospect area is a 2,000 acre play located in southern
Tehama County. In this project, for which a 7.5 square mile area 3-D seismic
survey has been acquired, Aspen has a 23.33% operated working interest. There is
also abundant well data for the area in addition to 2-D seismic survey
information. Several prospective locations have been identified through an
analysis of the data, with numerous pay zones from 2,000 to 6,000 feet in depth.

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 at a rate of 200 MCFPD and the well is
currently flowing 225 MCFPD. Aspen has a 23.33% operated working interest in
this well. Aspen has drilled 5 producing gas wells out of 6 attempts in this
field.

Drilling Activity:
------------------

The following table sets forth the results of our drilling activities
during the fiscal years ended June 30, 2003, 2004 and 2005:

Drilling Activity
-----------------

Gross Wells Net Wells
----------- ---------
Year Total Producing Dry Total Producing Dry
---- ----- --------- --- ----- --------- ---

2003 Exploratory 8 7 1 1.45 1.22 .23
2004 Exploratory 7 5 2 1.38 1.05 .33
2005 Exploratory 7 7 0 1.56 1.56 0

Production Information:

Net Production, Average Sales Price and Average Production Costs (Lifting).
--------------------------------------------------------------------------

The table below sets forth the net quantities of oil and gas production (net of
all royalties, overriding royalties and production due to others) attributable
to Aspen for the fiscal years ended June 30, 2005, 2004, and 2003, and the
average sales prices, average production costs and direct lifting costs per unit
of production.

Years Ended June 30,
---------------------------------------
2005 2004 2003
---- ---- ----
Net Production
--------------
Oil (Bbls) 219 357 768
Gas (MMcf) 617 305 248

Average Sales Prices
--------------------
Oil (per Bbl) $ 43.79 $ 31.65 $ 26.13
Gas (per Mcf) $ 6.23 $ 5.17 $ 4.23

Average Production Cost(1)
--------------------------
Per equivalent
Bbl of oil $ 16.50 $ 15.73 $ 12.83

Average Lifting Costs(2)
------------------------
Per equivalent
Bbl of oil $ 3.36 $ 4.73 $ 3.61

(1) Production costs include all operating expenses, depreciation, depletion and
amortization, lease operating expenses and all associated taxes.

(2) Direct lifting costs do not include impairment expense, ceiling write-down,
or depreciation, depletion and amortization.

Productive Wells and Acreage:

Gross and Net Productive Gas Wells, Developed Acres, and Overriding Royalty
Interests.
---------------------------------------------------------------------------

Leasehold Interests - Productive Wells and Developed Acres: The tables
below sets forth Aspen's leasehold interests in productive and shut-in gas
wells, and in developed acres, at June 30, 2005:

Producing and Shut-In Wells

Gross Net(1)
----- ------
Prospect Gas Gas
-------- --- ---
California:
Anderson Farms 1 0.30000
Anderson Unit 1-2 1 0.90000
Armstrong 17-4 1 0.36000
Balsdon 3-21 1 0.05983
Balsdon 6 1 0.04134
Chickohominy 1-12 1 0.24438
Cygnus 2 1 0.05125
Deane 1 1 0.12938
Dragon 1 1 0.05565
Eastby 36-2 1 0.07770
Elektra 1 1 0.07560
Emigh 34-1 1 0.32550
Emigh 35-2 1 0.32800
Emigh 35-3 1 0.11900
Emigh 35-6 1 0.05514
Ettl 1-10 1 0.28750
Firestone 1-10 1 0.03850
Gay Unit 1 0.21000
Grey Wolf 1 1 0.18000
Griffin 1-1 1 0.24438
Houghton 25-1 1 0.07770
Johnson Unit 4 0.84000
Kuppenbender 20-2 1 0.27075
Kuppenbender 20-3 1 0.15200
Leal 22-1 1 0.23334
McCullough 36-1 1 0.17725
Malton Arbuckle 1 1 0.51667
Mapco-Kylling 1 1 0.37800
Meckfessel 1-24 1 0.24437
Morris 12-2 1 0.21000
NL&F 26-1 1 0.23334
Noseco 1 1 0.67900
Pinheiro 1-10 1 0.01890
Pinheiro 2-10 1 0.01890
Pope Bypass 1-5 1 0.25400
Porter 26-2 1 0.23334
Sanborn 3-3 1 0.12762
Sanborn 4-10 1 0.02979
Sciortino 1-7 1 0.03000
South Sycamore 7 1 0.21000
South Sycamore 20 1 0.21000
Swanson 22-1 1 0.23334
Tiahrt 1-4 1 0.13617
Verona Farms 1 1 0.30000
West Grimes Unit 14 2 0.42000
West Grimes Unit 15 5 1.05000
West Grimes Unit 16 3 0.63000
Strain Ranches 16-3 1 0.21000
Strain Ranches 17-1 1 0.21000
Walter Trust 1 1 0.07291
Zimmerman 1-24 1 0.23334
TOTAL 61 12.72388

(1) A net well is deemed to exist when the sum of fractional ownership working
interests in gross wells equals one. The number of net wells is the sum of the
fractional working interests owned in gross wells expressed as whole numbers and
fractions thereof.

Developed Acreage Table
-----------------------

Aspen's Developed Acres(1)
Prospect Gross(2) Net(3)
-------- ----- ---
California:

Denverton Creek 1,431 216
Feather River 160 48
Firestone 1-10 160 6
Grey Wolf 1 120 22
Kirk Buckeye/Orion 972 307
Malton Black
Butte Field 1,355 296
McCullough 36-1 583 103
Momentum 616 150
Phillips Acquisition 1,120 79
Pope Bypass 1-5 120 30
Sac Valley Acquisition 1,324 555
Sour Grass 704 164
West Grimes 3,073 645
------- ------

TOTAL 11,738 2,621
======= ======

(1) Consists of acres spaced or assignable to productive wells.

(2) A gross acre is an acre in which a working interest is owned. The number of
gross acres is the total number of acres in which a working interest is owned.

(3) A net acre is deemed to exist when the sum of fractional ownership working
interests in gross acres equals one. The number of net acres is the sum of the
fractional working interests owned in gross acres expressed as whole numbers and
fractions thereof.

Royalty Interests in Productive Wells and Developed Acreage: The following
tables set forth Aspen's royalty interest in productive gas wells and developed
acres at June 30, 2005:

Overriding Royalty Interests
----------------------------

Productive
Wells Gross
Prospect Interest(%) Gas Acreage(1)
-------- ----------- --- --------

California:
Denverton Creek 1.142816 1 80
Malton Black Butte 7.500000 1 645
Grimes Gas 0.101590 1 615
--- -----

TOTAL 3 1,340
=== =====

(1) Consists of acres spaced or assignable to productive wells.

Undeveloped Acreage:

Leasehold Interests Undeveloped Acreage: The following table sets forth Aspen's
leasehold interest in undeveloped acreage at June 30, 2005:

Undeveloped Acreage
-------------------
Gross Net
----- ---
California:
Andromeda 342 342
Denverton Creek 514 69
Dunkirk 3-D 741 741
Momentum 428 71
Orion 590 288
Sour Grass 293 68
West Grimes 2,511 510
------- ------

TOTAL 5,419 2,029
======= ======

Gas Delivery Commitments:

Effective April 1, 2005, we entered a contract to sell Enserco 2,000 MMBTU
of gas per day at a fixed price of $6.49 less transportation and other expenses;
and a contract to sell Calpine 1,500 MMBTU of gas per day at a fixed price of
$6.90 less transportation and other expenses. The contracts are for the term
April 1, 2005 - September 30, 2005, required Enserco and Calpine to purchase the
stated quantities at the stated prices, and contained monetary penalties for
non-delivery of the gas.

Effective November 1, 2005, we entered a contract to sell Enserco 1,000
MMBTU of gas per day at a fixed price of $8.40 less transportation and other
expenses; and a contract to sell Calpine 1,000 MMBTU of gas per day at a fixed
price of $8.43 less transportation and other expenses. The contracts are for the
term November 1, 2005 - March 31, 2006, required Enserco and Calpine to purchase
the stated quantities at the stated prices, and contained monetary penalties for
non-delivery of the gas.

Effective November 1, 2005, we entered a contract to sell Enserco 500 MMBTU
of gas per day at a fixed price of $9.49 less transportation and other expenses;
and a contract to sell Calpine 500 MMBTU of gas per day at a fixed price of
$9.48 less transportation and other expenses. The contracts are for the term
November 1, 2005 - March 31, 2006, required Enserco and Calpine to purchase the
stated quantities at the stated prices, and contained monetary penalties for
non-delivery of the gas.

Effective November 1, 2005, we entered a contract to sell Enserco 500 MMBTU
of gas per day at a fixed price of $11.02 less transportation and other
expenses; and a contract to sell Calpine 250 MMBTU of gas per day at a fixed
price of $11.02 less transportation and other expenses. The contracts are for
the term November 1, 2005 - March 31, 2006, required Enserco and Calpine to
purchase the stated quantities at the stated prices, and contained monetary
penalties for non-delivery of the gas.

Drilling Commitments:

We have a proposed drilling budget for the period August through December
2005. The budget includes drilling nine wells in the Sacramento gas
province of northern California. Our share of the estimated costs to
complete this program is set forth in the following table:

Drilling Completion &
Area Wells Costs Equipping Costs Total
------------------ ------ ---------- --------------- ----------
Kirk-Buckeye Field 2 $323,000 $248,000 $571,000
Colusa County, CA

West Grimes Field 4 470,000 330,000 800,000
Colusa County, CA

Malton Black Butte 2 181,000 180,000 361,000
Tehama County, CA

Winters Gas Field 1 38,000 53,000 91,000
Yolo County, CA
------ ----------- ------------ -----------

Total Expenditure 9 $1,012,000 $811,000 $1,823,000
====== =========== ============ ===========

Reserve Information - Oil and Gas Reserves:

Cecil Engineering, Inc. evaluated our oil and gas reserves attributable to
our properties at June 30, 2005. Reserve calculations by independent
petroleum engineers involve the estimation of future net recoverable
reserves of oil and gas and the timing and amount of future net revenues to
be received therefrom. Those estimates are based in numerous factors, many
of which are variable and uncertain. Reserve estimators are required to
make numerous judgments based upon professional training, experience and
educational background. The extent and significance of the judgments in
them are sufficient to render reserve estimates of future events, actual
production determinations involve estimates inherently imprecise, since
reserve revenues and operating expenses may not occur as estimated.
Accordingly, it is common for the actual production and revenues later
received to vary from earlier estimates. Estimates made in the first few
years of production from a property are generally not as reliable as later
estimates based on a longer production history. Reserve estimates based
upon volumetric analysis are inherently less reliable than those based on
lengthy production history. Also, potentially productive gas wells may not
generate revenue immediately due to lack of pipeline connections and
potential development wells may have to be abandoned due to unsuccessful
completion techniques. Hence, reserve estimates may vary from year to year.

Estimated Proved Reserves/ Developed and Undeveloped Reserves: The
following tables set forth the estimated proved developed and proved undeveloped
oil and gas reserves of Aspen for the years ended June 30, 2005 and 2004. See
Note 10 to the Consolidated Financial Statements and the above discussion.

Estimated Proved Reserves
-------------------------

Proved Reserves Oil (Bbls) Gas (Mcf)
--------------- ---------- ---------

Estimated quantity, June 30, 2003 3,000 2,480,000
---------- ----------

Revisions of previous estimates (1,000) (411,000)
Discoveries 0 527,000
Production 0 (305,000)
Purchased reserves 0 243,000
---------- ----------

Estimated quantity, June 30, 2004 2,000 2,534,000

Revisions of previous estimates 0 (306,000)
Discoveries 0 667,000
Production 0 (617,000)
---------- ----------

Estimated quantity, June 30, 2005 2,000 2,278,000
========== ==========

Developed and Undeveloped Reserves
----------------------------------

Developed Undeveloped Total
--------- ----------- -----
Oil (Bbls)
June 30, 2005 -- 2,000 2,000
June 30, 2004 -- 2,000 2,000

Gas (Mcf)
June 30, 2005 1,327,000 951,000 2,278,000
June 30, 2004 1,236,000 1,298,000 2,534,000

For information concerning the standardized measure of discounted future
net cash flows, estimated future net cash flows and present values of such cash
flows attributable to our proved oil and gas reserves as well as other reserve
information, see Note 10 to the Consolidated Financial Statements.

Oil and Gas Reserves Reported to Other Agencies: We did not file any
estimates of total proved net oil or gas reserves with, or include such
information in reports to, any federal authority or agency since the beginning
of the fiscal year ended June 30, 2005.

Title Examinations: Oil and Gas: As is customary in the oil and gas
industry, we perform only a perfunctory title examination at the time of
acquisition of undeveloped properties. Prior to the commencement of drilling, in
most cases, and in any event where we are the Operator, a thorough title
examination is conducted and significant defects remedied before proceeding with
operations. We believe that the title to our properties is generally acceptable
to a reasonably prudent operator in the oil and gas industry. The properties we
own are subject to royalty, overriding royalty and other interests customary in
the industry, liens incidental to operating agreements, current taxes and other
burdens, minor encumbrances, easements and restrictions. We do not believe that
any of these burdens materially detract from the value of the properties or will
materially interfere with our business.

We have purchased producing properties on which no updated title opinion
was prepared. In such cases, we have retained third party certified petroleum
landmen to review title.

Office Facilities:

Our principal office is located in Denver, Colorado. We also have an office
located in 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 month to month lease agreement on January 1, 2005 for a lease
rate of $1,261 per month.

We entered a lease agreement for our Bakersfield, California office, which
consists of approximately 546 square feet. The Bakersfield, California lease
requires lease payments of $793 over the term of the lease which expires
February 8, 2006.

ITEM 3. LEGAL PROCEEDINGS
-------------------------

We are not subject to any pending or, to our knowledge, threatened, legal
proceedings.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
-----------------------------------------------------------

No matters were presented to security holders for a vote during the year
ended June 30, 2005, or any subsequent period.

PART II

ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
----------------------------------------------------------------

Market Information:

Our common stock is quoted on the Over-the-Counter Bulletin Board ("OTCBB")
under the symbol "ASPN". The quotations reflect inter-dealer prices without
retail mark-up, mark-down or commission and may not reflect actual transactions.

The OTCBB rules provide that companies not current in their reporting
requirements under the Securities Exchange Act of 1934 will be removed from the
quotation service. At June 30, 2004 and 2005, we believe that we were in full
compliance with these rules.

Quarter Ended
Sept., 2004 Dec., 2004 March, 2005 June 30, 2005
----------- ---------- ----------- -------------
Common Stock ("ASPN")
High $1.37 $2.42 $3.34 $3.40
Low $0.95 $1.09 $1.95 $2.39

Quarter Ended
Sept., 2003 Dec., 2003 March, 2004 June 30, 2004
----------- ---------- ----------- -------------
Common Stock ("ASPN")
High $.85 $.97 $.95 $1.23
Low $.56 $.55 $.58 $0.65

Holders:

As of June 30, 2004 and 2005, there were approximately 1,158 and 1,127
holders of record of our Common Stock, respectively. This does not include an
indeterminate number of persons who hold our Common Stock in brokerage accounts
and otherwise in 'street name.'

Dividends:

We have never declared or paid a cash dividend on our Common Stock. We
presently intend to retain our earnings to fund development and growth of our
business. Decisions concerning dividend payments in the future will depend on
income and cash requirements.

Holders of common stock are entitled to receive such dividends as may be
declared by Aspen's Board of Directors. There were no dividends declared by the
Board of Directors during the fiscal year ended June 30, 2005, or subsequently,
and we have paid no cash dividends on its common stock since inception. There
are no contractual restrictions on our ability to pay dividends to our
shareholders.

Securities authorized for issuance under equity compensation plans.

The following is provided with respect to compensation plans (including
individual compensation arrangements) under which equity securities are
authorized for issuance as of the fiscal year ending June 30, 2005.

-----------------------------------------------------------------------------------------
Equity Compensation Plan Information (1)
-----------------------------------------------------------------------------------------

Plan Category and Number of Weighted-average Number of securities remaining
Description Securities to be exercise price of available for future issuance
issued upon outstanding under equity compensation
exercise of options, warrants, plans (excluding securities
outstanding and rights reflected in column (a))
options,
warrants, and
rights
(a) (b) (c)
--------------------- ---------------- ------------------- ------------------------------
Equity compensation
plans approved by
security holders -0- $-0- -0-
--------------------- ---------------- ------------------- ------------------------------
Equity compensation
plans not approved
by security holders 552,000 $1.56 NA
--------------------- ---------------- ------------------- ------------------------------
--------------------- ---------------- ------------------- ------------------------------
Total 552,000 $1.56 NA
--------------------- ---------------- ------------------- ------------------------------
--------------------- ---------------- ------------------- ------------------------------

(1) This does not include options held by management and directors that were
not granted as compensation. In each case, the disclosure refers to options
or warrants unless otherwise specifically stated.

Recent Sales of Unregistered Securities -- Item 701 Disclosure.

The following sets forth information regarding sales of unregistered securities
during the June 30, 2005 fiscal year and subsequently as required by Item 701 of
Regulation S-B.

Tri-Power Resources, Inc.

On June 28, 2004, Tri-Power Resources, Inc., a privately-held Oklahoma
corporation, purchased a $300,000 convertible debenture from Aspen Exploration
Corporation. Aspen also issued to Tri-Power warrants to purchase 300,000 shares
of its common stock which, if exercised before March 31, 2005, will result in
the purchaser acquiring warrants to purchase an additional 300,000 shares.
Shares potentially issuable to Tri-Power total 900,000.

(a) The transaction was completed effective June 28, 2004. We issued the
following securities to one accredited investor in exchange for the investor's
payment to Aspen of $300,000:

a convertible debenture with a principal amount of $300,000, bearing
interest at 4% per annum and

300,000 common stock warrants exercisable as described in paragraph (c)
below.

(b) There was no placement agent or underwriter for the transaction and Aspen
did not publicly offer any securities.

If the holder exercises the warrant before June 30, 2005, Aspen will
receive an additional $330,000 ($1.10 per share); if the holder exercises the
warrant before June 30, 2006 but after June 30, 2005, Aspen will receive an
additional $360,000 ($1.20 per share).

If the holder exercises the warrant before March 31, 2005, the holder will
receive an additional warrant exercisable to purchase 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.

(d) We relied on the exemption from registration provided by Sections 4(2) and
4(6) under the Securities Act of 1933 for this transaction and Regulation D. We
did not engage in any public advertising or general solicitation in connection
with this transaction which was in negotiation for more than several weeks. 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 it requested, received answers to all questions it (and its
advisors) posed, and otherwise understood the risks of accepting our securities
for investment purposes.

(e) The convertible debenture convertible into common stock at the effective
price of $1.00 per share (subject to dilution adjustment in the event of stock
splits, stock dividends, and similar transactions, the "Conversion Price"). The
convertible debenture will automatically convert into common stock at the
Conversion Price if the market price for Aspen's common stock as reported by the
OTC Bulletin Board remains above $1.00 per share for ten consecutive trading
days.

Each common stock warrant is exercisable to purchase one share of common
stock through June 30, 2006. The warrants may only be exercised to the extent
that there is an exemption available for the exercise at the time of exercise.

If exercised before March 31, 2005, the exercise price is $1.10 per share,
and the holder will receive one share of common stock and one additional warrant
(exercisable through June 30, 2006 at $1.25 per share) for each warrant
exercised.

If exercised before June 30, 2005, the exercise price is $1.10 per share,
and the holder will receive one share of common stock for each warrant
exercised.

If exercised after June 30, 2005 but before the expiration date (June 30,
2006), the exercise price is $1.20 per share, and the holder will receive one
share of common stock for each warrant exercised.

Aspen has the right to redeem the common stock purchase warrants issued at
any time for the payment of $0.10 per warrant provided there is an effective
registration statement for the resale of the shares underlying the warrant at
the time of the redemption, and provided further that the market price of
Aspen's common stock has exceeded $2.50 per share for twenty of the thirty
trading days preceding the date Aspen gives notice of its intention to redeem
the warrants. There are no other registration rights associated with the
securities issued to the accredited investor.

(f) We will use the proceeds for expenses of drilling and (if warranted)
completing oil and gas wells.

Conversion of Convertible Debenture

On July 15, 2004, Aspen gave the holder notice that the conditions for the
automatic conversion of the convertible debenture had been met, and issued
300,500 shares of common stock upon such conversion.

(a) The conversion was completed effective July 15, 2004. We issued the 300,500
shares of our restricted common stock to one accredited investor in conversion
of and outstanding convertible debenture and accrued interest.

(b) There was no placement agent or underwriter for the transaction and Aspen
did not publicly offer any securities.

(d) We relied on the exemption from registration provided by Sections 3(a)(9),
4(2) and 4(6) under the Securities Act of 1933 for this transaction and
Regulation D. We did not engage in any public advertising or general
solicitation in connection with this conversion. 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 it requested,
received answers to all questions it (and its advisors) posed, and otherwise
understood the risks of accepting our securities for investment purposes.

(e) We issued common stock to the holder upon conversion of the convertible
debenture.

(f) We received no proceeds from the conversion of the debenture.

Stock Warrants Exercised

On March 11, 2005, the warrant holder exercised warrants to purchase
300,000 shares of our common stock at $1.10 per share.

(a) The warrants were exercised on March 11, 2005. We issued 300,000 shares of
our common stock of our restricted common stock on March 17, 2005 to one
accredited investor.

(b) There was no placement agent or underwriter for the transaction and Aspen
did not publicly offer any securities.

Stock Issuances pursuant to exercise of options

On August 16, 2004, one director and one executive officer of Aspen, one
staff member and a consultant, exercised common stock purchase options they held
and acquired shares of our common stock as described below. On March 9, 2005,
two directors exercised common stock purchase options they held and acquired
shares of our common stock as described below. In each case, the persons
exercising the options paid the exercise price by returning common stock to
Aspen.

----------------------- ------------- ------------- ------------ -----------
Name and Principal Date Number of Exercise Option
Position Common Price paid Exercise
Shares Sold ($) Price Per
(#) Share ($)
----------------------- ------------- ------------- ------------ -----------
R. A. Cohan, 8/16/2004 50,000 28,500 .57
director and
president, options
exercised
----------------------- ------------- ------------- ------------ -----------
R. V. Bailey, 3/19/2005 50,000 28,500 .57
director and vice
president, options
exercised
----------------------- ------------- ------------- ------------ -----------
R. F. Sheldon, 3/19/2005 50,000 28,500 .57
director, options
exercised
----------------------- ------------- ------------- ------------ -----------
J. L. Shelton, 8/16/2004 17,000 9,690 .57
office manager,
options exercised
----------------------- ------------- ------------- ------------ -----------
R. K. Davis, 8/16/2004 25,000 14,250 .57
consultant, options
exercised
----------------------- ------------- ------------- ------------ -----------
----------------------- ------------- ------------- ------------ -----------
Total 192,000 109,440 .57
----------------------- ------------- ------------- ------------ -----------
----------------------- ------------- ------------- ------------ -----------

(a) In the aggregate, Aspen issued 192,000 shares of its common stock upon the
exercise of options at a price of $0.57 per share. The option holders
surrendered a total of 60,171 shares of Aspen's common stock in payment of the
exercise price.

(b) There was no underwriter involved in this transaction, and Aspen did not
publicly offer any securities. Each of the persons who acquired shares has had
prior relationships with Aspen extending over a period of many years.

(c) No securities were sold for cash. Aspen accepted shares of its common stock
at its market price as payment of the exercise price for the options.

(d) We relied on the exemption from registration provided by Sections 3(a)(9)
and 4(2) under the Securities Act of 1933 for this transaction and Regulation D.
Each of the persons receiving our common stock was and remains a shareholder of
Aspen, and no person paid any consideration other than the exchange of
securities with Aspen. Furthermore, we did not engage in any public advertising
or general solicitation in connection with this transaction which was in
negotiation for more than several weeks. We provided the investors 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 investors
obtained all information regarding Aspen it requested, received answers to all
questions it (and its advisors) posed, and otherwise understood the risks of
accepting our securities for investment purposes.

(e) Not applicable, since the securities issued are neither convertible nor
exchangeable.

(f) Not applicable, inasmuch as Aspen did not receive any cash from the
issuance of the securities.

ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION OR PLAN OF
OPERATION
------------------------------------------------------------------------------

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."

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. We are currently the
operator of 49 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 and one part 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. We believe that 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 35% of our
selling, general and administrative expenses.

Critical Accounting Policies and Estimates:

We believe the following critical accounting policies affect our most
significant judgments and estimates used in the preparation of our Consolidated
Financial Statements.

Reserve Estimates:

Our estimates of oil and natural gas reserves, by necessity, are
projections based on an interpretation of geologic and engineering data. There
are uncertainties inherent in the interpretation of such data as well as the
projection of future rates of production and the timing of development
expenditures. Reserve engineering is a subjective process of estimating
underground accumulations of oil and natural gas that are difficult to measure.
The accuracy of any reserve estimate is a function of the quality of available
data, engineering and geological interpretation and judgment. Estimates of
economically recoverable oil and natural gas reserves and future net cash flows
necessarily depend upon a number of variable factors and assumptions, such as
historical production from the area compared with production from other

producing areas, the assumed effects of regulations by governmental 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.

Property, Equipment and Depreciation:
-------------------------------------

We follow the full-cost method of accounting for oil and gas properties.
Under this method, all productive and nonproductive costs incurred in connection
with the exploration for and development of oil and gas reserves are
capitalized. Such capitalized costs include lease acquisition, geological and
geophysical work, delay rentals, drilling, completing and equipping oil and gas
wells, including salaries, benefits and other internal salary related costs
directly attributable to these activities. 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 6.25%. 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.

Outlook and Trends
------------------

We expect our natural gas production to increase substantially during
fiscal 2006 due to recent drilling successes. Total production for the year will
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 $10.00 per MMBTU for the fiscal year ended June 30, 2006.

Over the past five years we have been able to replace our produced reserves
and increase our yearly natural gas production. During fiscal 2005, we managed
to replace 90% of our proved reserves in spite of a delayed drilling program,
which commenced in June instead of April due to adverse weather conditions. 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 $6.30 per MMBTU for the quarter ended June 30, 2005.

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 5 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 adequately.

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 and although
we have recently benefited from increasing prices for our natural gas
production, 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 are exposed to interest rate risk to the extent we have borrowed funds.
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 June 30,
2005, the effective interest rate was 8%. In June 2004, we issued a convertible
debenture for $300,000 with interest at 4% per annum. At June 30, 2005, we
repaid the bank loan in full and during July 2004 the $300,000 convertible
debenture was converted to 300,000 shares of our common stock.

Liquidity and Capital Resources
-------------------------------

We have historically financed our operations with internally generated
funds, 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 $2,861,500 and $1,536,500 was provided by our operations for the
twelve months ended June 30, 2005 and 2004. The cash flow from operations
increase of $1,325,000, or 86%, was because of:

Increased oil and gas sales ($3,853,000 in 2005 as compared to $1,588,000
in 2004) due to increasing prices and production volume;

A decrease in accounts receivable during 2004 which provided cash $288,300
compared to a further decrease in accounts receivable during 2005 which
provided cash of $44,100; and

An increase in accounts payable and accrued expenses in 2004 which
conserved cash of $874,200 compared to a decrease in accounts payable and
accrued expenses in 2005 which used cash of $57,100.

Investing activities used cash to increase capitalized oil and gas costs of
$1,465,500 and $1,448,100 in the twelve months ended June 30, 2005 and 2004.
Cash in the current twelve month period ended June 30, 2005 was used for lease
acquisition and seismic work ($96,700), intangible drilling and well workovers
($1,029,500), and the purchase of oil and gas well equipment ($339,300). These
expenditures were offset by the sale of interests in wells to be drilled charged
to third party investors.

Contractual Obligations
-----------------------

We had four contractual obligations as of June 30, 2005. The following
table lists our significant liabilities at June 30, 2005:

Payments Due By Period
--------------------------------------------------------
Less than After
Contractual Obligations 1 year 2-3 years 4-5 years 5 years Total
----------------------- ------ --------- --------- ------- -----

Employment Obligations $218,500 $504,400 $ 67,400 -0- $790,300

Contract Service Obligations 20,000 -0- -0- -0- 20,000

Operating Leases 9,500 4,000 -0- -0- 13,500
-------- -------- -------- -------- --------

Total contractual
cash obligations $248,000 $508,400 $ 67,400 $ -0- $823,800
======== ======== ======== ======== ========

Future Commitments
------------------

We have a proposed drilling, completion and construction budget for the
period July through December 2005. The budget includes drilling nine wells in
the Sacramento gas province of northern California. Our share of the estimated
costs to complete this program over the next six months is set forth in the
following table:

Drilling Completion &
Area Wells Costs Equipping Costs Total
-------------------- ----------- -------------- ------------------- -------------
Kirk-Buckeye Field 2 $323,000 $248,000 $571,000
Colusa County, CA

West Grimes Field 4 470,000 330,000 800,000
Colusa County, CA

Malton Black Butte 2 181,000 180,000 361,000
Tehama County, CA

Winters Gas Field 1 38,000 53,000 91,000
Yolo County, CA
----------- -------------- ------------------- -------------

Total Expenditure 9 $1,012,000 $811,000 $1,823,000
=========== ============== =================== =============

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 month to month lease agreement beginning January 1, 2005 for a lease rate
of $1,261 per month. The Bakersfield, California office has 546 square feet and
a monthly rental fee of $793 over the term of the lease. The three year lease
expires February 8, 2006. Rent expense for both of the years ended June 30, 2005
and 2004 were $24,370.

In addition to office leases, we are responsible for various compressor
rentals located on our California producing properties. These leases are on a
month to month basis and total approximately $72,400 per year.

Our working capital surplus (current assets less current liabilities) at
June 30, 2005, was $2,609,400. 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.

To the extent that we continue recognizing net income, tax expense in
future years will result in a negative impact on our cash flow. To date we have
avoided paying federal income taxes because of significant tax loss
carryforwards. We have used substantially all of our tax loss carryforwards as
of June 30, 2005, and in future years we anticipate that we will actually have
to pay significant amounts in federal and state taxes. See Note 5 to our
financial statements, "Income Taxes."

We believe that internally generated funds and third-party farmouts will be
sufficient to finance our drilling and operating expenses for the next twelve
months. However, during December 2003, we borrowed $225,000 from a bank in
California and used the proceeds to acquire various working interests in
producing gas wells located in several counties in the Sacramento Valley,
California. We also issued a convertible debenture for $300,000 in June 2004
(which converted to common stock in July 2004 and was reclassified from a
current liability to equity) to finance our share of additional wells drilled in
July and August of 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 any future completion and
pipeline costs.

Results of Operations
---------------------

June 30, 2005 Compared to June 30, 2004
---------------------------------------

For the twelve months ended June 30, 2005, 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 2005
period, our revenues increased by more than $2.3 million as compared to the
comparable period of our 2004 fiscal year because of:

Increased production (622,000 MMBTU sold as compared to 305,000 MMBTU sold
during our 2004 fiscal year, a 104% increase); and

Increased price received for our production (an average of $6.20 per MMBTU
during our 2005 fiscal year as compared to $5.17 per MMBTU received during
that period in 2004).

The foregoing increases were reinforced in part by an increase in
management fees received ($266,127 during 2005 as compared to $232,430 during
2004). We were operators of more wells during 2005 (49 wells compared to 46
wells in 2004), and our management fees were positively impacted by the
increased number of wells we operate.

The following table sets forth certain items from our Consolidated Statements of
Operations as expressed as a percentage of total revenues, shown by year for
fiscal 2005, 2004 and 2003:

For the Year Ended
---------------------------------
6/30/2005 6/30/2004 6/30/2003
--------- --------- ---------

Total revenues 100.0% 100.0% 100.0%

Oil & gas production costs 8.4 13.3 12.1

--------- --------- ---------
Income from operations 91.6 86.7 87.9
--------- --------- ---------

Costs and expenses
Depreciation and depletion 33.2 31.9 32.4
Selling, general and administrative 18.5 34.4 47.4
Interest expense .1 .3 .0

--------- --------- ---------
Total costs and expenses 51.8 66.6 80.1
--------- --------- ---------

Gain on sale of investment 13.7 - -

Income before income taxes 53.5 20.0 7.8

Provision for income taxes (18.9) (9.0) (3.2)

Cumulative effect of accounting charge - - (.2)

--------- --------- ---------
Net income 34.6 11.0 4.4
========= ========= =========

To facilitate discussion of our operating results for the years ended June 30,
2005 and 2004, we have included the following selected data from our
Consolidated Statements of Operations:

Comparison of the Fiscal
Twelve Months Ended June 30, Increase (Decrease)
----------------------- ----------------------
2005 2004 Amount Percentage
---------- ---------- ---------- ----------

Revenues:
---------
Oil and gas sales $3,853,177 $1,588,250 $2,264,927 142.6%
Management fees 266,127 232,430 33,697 14.5
Interest and other 8,140 3,256 4,884 150.0
---------- ---------- ---------- ---------
Total revenues 4,127,444 1,823,936 2,303,508 126.3
---------- ---------- ---------- ---------

Cost and expenses:
------------------
Oil and gas production 346,451 242,472 103,979 42.9
Depreciation and depletion 1,372,265 581,402 790,863 113.3
Selling, general and administrative 763,236 628,265 134,971 21.5
Interest expense 6,180 6,152 28 .4
---------- ---------- ---------- ---------
Total costs and expenses 2,488,132 1,458,291 1,029,841 70.7
---------- ---------- ---------- ---------

Net operating income $1,639,312 $ 365,645 $1,273,667 348.4%
-------------------- ========== ========== ========== =========

Central to the issue of success of the twelve months operations ended June 30,
2005 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
2nd Quarter 1,132,359 177,350 6.37
3rd Quarter 1,103,687 169,150 6.52
4th Quarter 919,578 145,500 6.30
----------- ---------- ------------
Year to date 3,853,177 622,000 6.20
----------- ---------- ------------

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
4th Quarter 481,441 80,600 5.97
----------- ---------- ------------
Year to date 1,588,250 305,000 5.17
----------- ---------- ------------

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
4th Quarter 314,445 60,600 5.19
----------- ---------- ------------
Year to date 1,068,798 248,000 4.23
----------- ---------- ------------

12 month change
---------------
2005
----
Amount $2,264,927 317,000 $1.03
Percentage 142.6% 103.9% 19.9%

2004
----
Amount $519,452 57,000 $.94
Percentage 48.6% 23% 22.2%

(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 past twelve months of fiscal 2005 and the twelve
months of fiscal 2004. As the table above notes, revenue has increased
approximately 143% when comparing the two twelve month periods ended June 30,
2005 and 2004. Volumes sold increased approximately 104%, while the price
received for our product increased approximately 20%.

Total revenue increased $2,265,000, or 143% when comparing the two periods,
while operating and production costs increased $104,000, or 43%. As set out in
the previous paragraph, revenue from gas sales increased because the volumes
sold from new and existing wells increased and natural gas prices increased
substantially. Production costs increased due to the addition of newly
productive wells.

Depletion and depreciation increased $728,900, or 113% due largely to adverse
weather conditions which delayed the start of our fiscal 2005 drilling season
from April until late June. Because of the delay, reserves discovered in July
and August of 2005 were not included in our 2005 reserve report causing the
percentage depletion to increase substantially resulting in the increased
depletion expense.

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 remained fairly constant at approximately 35%
for the twelve months ended June 30, 2004 to approximately 36% at June 30, 2005.

When comparing general and administrative expense for 2005 and 2004, costs
increased by $135,000, or 21%, due primarily to increases in accounting and
audit fees, promotional expense and corporate reporting expense and the issuance
of common stock as compensation for services.

Results of operations and income (loss) before income taxes are presented in the
following table:

Quarterly Financial Information (unaudited)

Income (loss)
(1) Income Before Income Taxes
Total Operating (Loss) Before Per Share
Revenues Income Income Taxes Basic Diluted
----------- ----------- ----------- --------- ---------
2005
----
lst Quarter $ 784,299 $ 715,249 $ 389,781 $ .063 $ .061
2nd Quarter 1,190,333 1,092,632 729,748 .074 .070
3rd Quarter 1,163,746 1,056,268 703,738 .109 .109
4th Quarter 980,926 908,704 382,957 .094 .090
----------- ----------- ----------- --------- ---------
Total 4,119,304 3,772,853 2,206,224 .34 .33
----------- ----------- ----------- --------- ---------

2004
----
lst Quarter 388,337 348,739 50,197 .01 .01
2nd Quarter 433,317 365,761 93,022 .01 .01
3rd Quarter 440,127 354,642 76,762 .01 .01
4th Quarter 558,899 509,066 145,664 .02 .01
----------- ----------- ----------- --------- ---------
Total 1,820,680 1,578,208 365,645 .05 .05
----------- ----------- ----------- --------- ---------

2003
----
lst Quarter 264,896 232,246 (44,238) (.008) (.007)
2nd Quarter 279,080 237,155 (15,660) (.003) (.003)
3rd Quarter 337,476 271,845 28,748 .005 .005
4th Quarter 432,369 272,421 133,876 .023 .022
----------- ----------- ----------- --------- ---------
Total $ 1,313,821 $ 1,013,667 $ 102,726 $ .02 $ .02
----------- ----------- ----------- --------- ---------

(1) Operating income is oil and gas sales plus management fees less direct
operating costs.

As can be seen in the table, revenues and operating income have improved
significantly when comparing the twelve month periods ended June 30, 2005 and
2004. 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.

Our future success in the oil and gas industry will depend on the cost of
finding oil or gas reserves to replace our production, the volume of our
production and the prices we receive for sale of our production. These factors
are subject to all of the risks associated with operations in the oil and gas
industry, many of which are beyond our control.

Factors that may Affect Future Operating Results
------------------------------------------------

In evaluating our business, readers of this report should carefully
consider the following factors in addition to the other information presented in
this report and in our other reports filed with the SEC that attempt to advise
interested parties of the risks and factors that may affect our business. As
noted elsewhere herein, the future conduct of Aspen's business, non-oil and gas
exploration activities, and discussions of possible future activities is
dependent upon a number of factors, and there can be no assurance that Aspen
will be able to conduct its operations as contemplated herein. These risks
include, but are not limited to:

(1) The possibility that the described operations, reserves, or
exploration or production activities will not be completed or
continued on economic terms, if at all.

(2) The exploration and development of oil and gas, and mineral properties
are enterprises attendant with high risk, including the risk of
fluctuating prices for oil, natural gas and other minerals being
sought.

(3) Imports of petroleum products from other countries and the resulting
volatility of prices received for the sale of our natural gas
production.

(4) Not encountering adequate resources despite expending large sums of
money.

(5) Test results and reserve estimates may not be accurate,
notwithstanding best effort precautions.

(6) The possibility that the estimates on which we are relying are
inaccurate and that unknown or unexpected future events may occur that
will tend to reduce or increase our ability to operate successfully,
if at all.

(7) Our ability to participate in these projects may be dependent on the
availability of adequate financing from third parties which may not be
available on commercially-reasonable terms, if at all.

(8) Our ability to compete with other companies (many of whom may be
better financed than are we) for the purchase of properties, hiring of
drilling rigs for exploration and development work, and completing
wells for production. Many of these considerations are
price-sensitive, and the cost will depend on many factors associated
with the oil and gas industry regionally, nationally, and
internationally, and over which we have no control.

(9) Our stock price may be hurt by future sales of our shares or the
perception that such sales may occur. As of the date of this Form
10-KSB, approximately 2,955,972 shares of Common Stock held by
existing stockholders constitute "restricted shares" as defined in
Rule 144 under the Securities Act. These shares may only be sold if
they are registered under the Securities Act or sold under Rule 144 or
another exemption from registration under the Securities Act. Sales
under Rule 144 are subject to the satisfaction of certain holding
periods, volume limitations, manner of sale requirements, and the
availability of current public information about us.

Off Balance Sheet Arrangements
------------------------------

We do not have any off balance sheet accounting arrangements except in
connection with joint ventures and operating agreements for the ownership and
drilling of wells. Aspen's balance sheet only reflects its own interest in these
arrangements, however, and has no interest in any ownership by third parties
(some of whom are related parties).

ITEM 7. FINANCIAL STATEMENTS
----------------------------

The information required by this item begins on page 41 of Part III of this
Report on Form 10-KSB and is incorporated into this part by reference.

ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
-----------------------------------------------------------------------

Not applicable.

ITEM 8A. CONTROLS AND PROCEDURES
--------------------------------

(a) Evaluation of Disclosure Controls and Procedures.

As required by Rule 13a-15 under the Securities Exchange Act of 1934,
within the 90 days prior to the filing date of this report, we carried out an
evaluation of the effectiveness of the design and operation of its disclosure
controls and procedures. This evaluation was carried out under the supervision
and with the participation of our principal executive officer as well as our
principal financial officer, who concluded that the Company's disclosure
controls and procedures are effective.

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 the our principal
executive officer and our principal financial officer, as appropriate, to allow
timely decisions regarding required disclosure.

(b) Changes in Internal Controls.

There were no changes in our internal controls or in other factors that
could significantly affect these internal controls subsequent to the date of
their evaluation.

ITEM 8B. OTHER INFORMATION
--------------------------

Not applicable. All required information has been reported herein.

PART III

ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS, COMPLIANCE
WITH SECTION 16(A) OF THE EXCHANGE ACT
--------------------------------------------------------------------------------

Identification of Directors and Executive Officers:

The following table sets forth the names and ages of all the Directors and
Executive Officers of Aspen, and the positions held by each such person. As
described below, the Board of Directors is divided into three classes which,
under Delaware law, must be as nearly equal in number as possible. The members
of each class are elected for three-year terms at each successive meeting of
stockholders serve until their successors are duly elected and qualified;
officers are appointed by, and serve at the pleasure of, the Board of Directors.
We have held no annual meetings since February 25, 1994. Therefore the terms of
each class of director expires at the next annual meeting of stockholders.

Director
Name Age Position Class Since
---- --- -------- ----- -----
Robert A. Cohan 49 President, Chief Executive Officer, I 1998
Chief Financial Officer, Treasurer
and Director

Robert F. Sheldon 82 Director II 1981

R. V. Bailey 73 Vice President, Secretary, and III 1980
Director

Each of the directors will be up for reelection at the next annual meeting
of stockholders and will continue to serve until his successor is elected and
qualified or until his or her earlier death, resignation, or removal. We do not
expect to hold an annual meeting during fiscal 2006.

Each officer is appointed annually and serves at the discretion of the
Board of Directors until his successor is duly elected and qualified. No
arrangement exists between any of the above officers and directors pursuant to
which any of those persons was elected to such office or position. None of the
directors are also directors of other companies filing reports under the
Securities Exchange Act of 1934.

Robert A. Cohan. Mr. Cohan obtained a Bachelor of Science degree in Geology
from the State University College at Oneonta, NY in 1979 and he works for Aspen
on a full-time basis. He has approximately 26 years experience in oil and gas
exploration and development, including employment in Denver, CO with Western
Geophysical, H. K. van Poollen & Assoc., Inc., as a Reservoir Engineer and
Geologist, Universal Oil & Gas, and as a principal of Rio Oil Co., Denver, CO.
Mr. Cohan served as Manager, Oil & Gas Operations, Aspen Exploration
Corporation, Denver, CO from 1989 to 1992. He was employed as Vice President,
Oil & Gas Operations, for Tri-Valley Oil & Gas Co., Bakersfield, CA. from 1992
to April 1995, at which time Mr. Cohan rejoined Aspen Exploration Corporation as
Vice President (now President), West Coast Division, opening an office in
Bakersfield, CA. He is a member of the Society of Petroleum Engineers (SPE) and
the American Association of Petroleum Geologists (AAPG).

Robert F. Sheldon. Mr. Sheldon obtained a Bachelor of Science degree in
Geological Engineering from the University of British Columbia in 1948. He
served a total of approximately 40 years at various mining companies, with his
experience covering a wide range of mineral commodities including gold, silver,
copper, uranium, lead, zinc, nickel, mercury, molybdenum and tungsten. He is a
member of the Professional Engineers of British Columbia, the Society of Mining
Engineers, the Canadian Institute of Mining and Metallurgy, and the Yukon
Chamber of Mines (where he served as an officer for four years). Mr. Sheldon
joined Aspen's Board of Directors in April 1981. Mr. Sheldon is currently
retired and only devotes a small portion of his time to Aspen's business.

R. V. Bailey. R. V. Bailey obtained a Bachelor of Science degree in Geology
from the University of Wyoming in 1956. He has approximately 43 years experience
in exploration and development of mineral deposits, primarily gold, uranium,
coal, and oil and gas. His experience includes basic conception and execution of
mineral exploration projects. Mr. Bailey is a member of several professional
societies, including the Society for Mining and Exploration, the Society of
Economic Geologists and the American Association of Petroleum Geologists, and
has written a number of papers concerning mineral deposits in the United States.
He is the co-author of a 542-page text, published in 1977, concerning applied
exploration for mineral deposits. Mr. Bailey is the founder of Aspen and has
been an officer and director since its inception, but currently devotes only a
small portion of his time to Aspen's business.

Meetings of the Board and Committees:

The Board of directors held one formal meeting during the fiscal year ended
June 30, 2005. Each director attended all of the formal meetings either in
person or by telephone, without exception. In addition, regular communications
were maintained throughout the year among all of the officers and directors of
the Company and the directors acted by unanimous consent six times during fiscal
2004 and six times subsequently through June 30, 2005.

No Audit Committee or Code of Ethics

Aspen does not have an audit committee or other committee of the board that
performs similar functions. Consequently Aspen has not designated an audit
committee financial expert.

Aspen's board of directors has not adopted a code of ethics because the
board does not believe that, given the small size of Aspen and the limited
transactions, a code of ethics is warranted.

Procedures by which security holders may recommend nominees to the board of
directors; communications with members of the Board of Directors

The board of directors has not adopted procedures by which security holders
may recommend nominees to the board of directors.

Any shareholder desiring to communicate directly with any officer or
director of Aspen may address correspondence to that person at our offices in
Denver, Colorado. Our office staff will forward such communications to the
addressee.

Identification of Significant Employees:

There are no significant employees who are not also directors or executive
officers as described above. No arrangement exists between any of the above
officers and directors pursuant to which any one of those persons was elected to
such office or position.

Family Relationships:

As of June 30, 2005, and subsequently, there were no family relationships
between any director, executive officer, or person nominated or chosen by the
Company to become a director or executive officer.

Involvement in Legal Proceedings:

We are not subject to any pending or, to our knowledge, threatened, legal
proceedings.

Section 16(a) Beneficial Ownership Reporting Compliance:

Section 16(a) of the Securities Exchange Act of 1934 (the "Exchange Act")
requires Aspen's directors and officers and any persons who own more than ten
percent of Aspen's equity securities, to file reports of ownership and changes
in ownership with the Securities and Exchange Commission (the "SEC"). All
directors, officers and greater than ten-percent shareholders are required by
SEC regulation to furnish Aspen with copies of all Section 16(a) reports files.
Based solely on our review of the copies of the reports it received from persons
required to file, we believe that during the period from July 1, 1995 through
September 23, 2005, all filing requirements applicable to its officers,
directors and greater-than-ten-percent shareholders were complied with except as
set forth in the following paragraphs.

1. Tri-Power Resources, Inc., beneficial owner of more than 10% of our
common stock, filed its Form 4 reporting the exercise of warrants into common
stock (a report required by SEC Rule 16a-3(g)(1) even though the transaction is
exempt from the application of Section 16(b)) late.

ITEM 10. EXECUTIVE COMPENSATION
-------------------------------

The following table sets forth information regarding compensation awarded,
paid to, or earned by the chief executive officer and the other principal
officers of Aspen for the three years ended June 30, 2003, 2004 and 2005. No
other person who is currently an executive officer of Aspen earned salary and
bonus compensation exceeding $100,000 during any of those years. This includes
all compensation paid to each by Aspen and any subsidiary.

Annual compensation Long-term Compensation
Awards
-------------------------------- --------------------------------------
Awards Payout
-------------------------- -----------
(a) (b) (c) (d) (e) (f) (g) (h) (i)
------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- -----------------

Securities
($) Underlying
Name and Fiscal ($) ($) ($) Restricted Options & LTIP All Other
Principal Position Year Salary Bonus Other (1) Awards SARs (#) Payout Compensation (1)
------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- -----------------
R. A. Cohan 2003 127,100 0 35,600 0 0 0 9,700
President and CEO 2004 137,100 0 54,800 0 0 0 7,300
2005 145,000 0 128,100 0 0 0 5,900
------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- -----------------
R. V. Bailey, 2003 111,700 0 33,250 0 0 0 23,487
Vice President 2004 45,000 0 59,100 0 0 0 25,250
and Chairman 2005 45,000 0 96,200 0 0 0 25,940
------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- -----------------

(1) We have an "Amended Royalty and Working Interest Plan" by which we, in our
discretion, are able to assign overriding royalty interests or working
interests in oil and gas properties or in mineral properties. This plan is
intended to provide additional compensation to Aspen's personnel involved
in the acquisition, exploration and development of Aspen's oil or gas or
mineral prospects.

We have a medical insurance plan for our employees and those of its
subsidiaries, and had a life insurance plan for our chairman and vice president,
R. V. Bailey. This life insurance plan included a split-dollar insurance plan
for the benefit of Mr. Bailey, which is described in Note 2 to the financial
statements. In June 2003 the plan was terminated.

No additional compensation has been recognized as reimbursement to the vice
president for income taxes for the years ended June 30, 2005, 2004 and 2003. Mr.
Bailey's taxable amount was $-0- for fiscal 2005, 2004 and 2003, equal to the
"economic benefit" attributed to the vice president as defined by the Internal
Revenue Code. The Company paid no premiums during fiscal 2005, 2004 and 2003.

We adopted a Profit-Sharing 401(k) Plan which took effect July 1, 1990. All
employees are eligible to participate in this Plan immediately upon being hired
to work at least 1,000 hours per year and attained age 21. Aspen's contribution
(if any) to this plan is determined by the Board of Directors each year. At June
30, 2003, we contributed $7,388 to the plan; during fiscal 2004 we contributed
$8,550 to the plan. During fiscal 2005, we contributed $-0- to the plan. When
amounts are contributed to Mr. Bailey's and Mr. Cohan's accounts (which amounts
are fully vested), these amounts are also included in column (e) of the tables,
above.

We have furnished a vehicle to Mr. Bailey, and the compensation allocable
to this vehicle, plus amounts paid for various travel and entertainment paid on
behalf of Mr. Bailey and Mr. Bailey's wife when she accompanied him for business
purposes, are also included in column (i) of the table. Aspen also purchased a
vehicle for Mr. Cohan. This vehicle is used substantially for business purposes;
therefore, no vehicle costs were charged to Mr. Cohan.

We have agreed to reimburse our officers and directors for out-of-pocket
costs and expenses incurred on behalf of Aspen.

During fiscal 2005, we assigned to employees royalties, which accumulated
during the fiscal year ended June 30, 2005, on certain wells drilled during the
year. The value assigned to these overrides is considered nominal, as the
assignments were made before the leases were proved. The overriding royalty
interests in these California properties granted to our employees were as
follows:

R. V. R. A. J. L.
Bailey Cohan Shelton
------ ----- -------

Griffin 1-1 0.8500% 1.2500% 0.4000%
Meckfessel 1-24 1.1900% 1.7500% 0.5600%

Stock Options and Stock Appreciation Rights Granted during the Last Fiscal Year:

During fiscal 2005, two directors, one officer, 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
60,171. The effect of the transaction is a net increase to the common stock par
value of $658 and a corresponding decrease to additional paid in capital of
$658.

On April 27, 2005 stock options to acquire 260,000 shares of our common
stock were granted to officers, directors, consultants and employees. The grant
price was $2.67 per share and are exercisable over a three year period ending
January, 2008.

Aggregated Option Exercises in Last Fiscal Year and Fiscal Year End Option
Values:

The following table sets forth information regarding the year-end value of
options being held by the Chief Executive Officer and the other such named
officers and persons on June 30, 2005.

Number of securities
underlying unexercised Value of unexercised
Shares options/SARs in-the-money options/SARs
acquired on Value at June 30, 2005 at June 30, 2005
Name and Principal Position exercise (#) realized Exercisable/Unexercisable Exercisable/Unexercisable
--------------------------- ------------ -------- ------------------------- -------------------------

R. V. Bailey
Vice President & Chairman... 115,000 $202,050 0 /115,000 $-0-
Robert A. Cohan
President & CEO............. 230,000 $299,100 0 /230,000 $-0-
Robert F. Sheldon
Director.................... 115,000 $202,050 0 /115,000 $-0-

Long Term Incentive Plans/Awards in Last Fiscal Year:

We do not have a long-term incentive plan nor have we made any awards
during the fiscal year ended June 30, 2005.

Employment contracts and termination of employment and change in control
arrangements:

Mr. Bailey: Effective May 1, 2003 we entered into a new employment
agreement with Chairman of the Board, R. V. Bailey. Some of the pertinent
provisions include an employment period ending May 1, 2009, the title of Vice
President subject to the general direction of the President, Robert A. Cohan,
and the Board of Directors of Aspen. Mr. Bailey's salary will be $45,000 per
year from May 1, 2003 to December 31, 2006 and $60,000 per year from January 1,
2007, ending May 1, 2009. Mr. Bailey will also participate in Aspen's stock
options and royalty interest programs. During the term of the agreement, we have
agreed to pay Mr. Bailey a monthly $1,700 allowance to cover such items as
prescriptions, medical and dental coverage for himself and his dependents and
other expenses not covered in the agreement.

We may terminate this agreement upon Mr. Bailey's death by paying his
estate all compensation that had or will accrue to the end of the year of his
death plus $75,000. Should Mr. Bailey become totally and permanently disabled,
we will pay Mr. Bailey one half of the salary and benefits set forth in our
agreement with him for the remainder of the term of the agreement.

Mr. Cohan: In April 2005 Mr. Cohan's employment agreement was renewed to
December 31, 2008 with a salary increase to $160,000 per year. Other benefits
and duties will remain the same as the previous employment contract.

See also Item 12, Certain Relationships and Related Party Transactions.

Report on Repricing of Options/SARs

We did not reprice any options or stock appreciation rights during the
fiscal year ended June 30, 2004, or subsequently.

ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
------------------------------------------------------------------------

The following table sets forth as of September 15, 2005 the number and
percentage of Aspen's shares of $.005 par value common stock owned of record and
beneficially owned by each person owning more than five percent of such common
stock, and by each Director, and by all Officers and Directors as a group.

Beneficial Ownership
Beneficial Owner Number of Shares Percent of Total
---------------- ---------------- ----------------

R. V. Bailey 1,475,276(i) 21.91%

Robert A. Cohan 822,377(ii) 12.21%

Robert F. Sheldon 315,656(iii) 4.69%

All Officers and Directors as a Group 2,613,309 38.81%
(3 persons)

The address for all of the above
directors and executive officers is:
2050 S. Oneida St., Suite 208,
Denver, CO 80224

Tri-Power Resources, Inc. 900,500(iv) 13.4%
P.O. Box 849
Ardmore, OK 73402

(i) This number includes 1,146,083 shares of stock held of record in the
name of R. V. Bailey and 16,320 shares of record in the name of Mieko Nakamura
Bailey, his wife. In addition, the number of shares owned includes 100,000
shares of common stock granted in a property exchange; stock options to purchase
65,000 shares of restricted common stock; stock options to purchase 150,000
shares of restricted common stock, which includes 50,000 shares of restricted
common stock that were exercised on May 14, 2004 and 50,000 shares of restricted
common stock that were exercised on March 9, 2005; and 200,000 shares of
restricted common stock that were exercised on June 11, 2001. Additionally,
Aspen issued 32,000 shares of common stock to the Aspen Exploration Profit
Sharing Plan for the benefit of R. V. Bailey as a corporation contribution to
Mr. Bailey's 401(k) account.

(ii) This number includes 300,000 shares of common stock granted; stock
options to purchase 80,000 shares of restricted common stock; stock options to
purchase 250,000 shares of restricted common stock, which includes 50,000 shares
of restricted common stock that were exercised on May 14, 2004 and 50,000 shares
of restricted common stock that were exercised on August 16, 2004; and stock
options to purchase 200,000 shares of restricted common stock that were
exercised on February 27, 2001. Additionally, Aspen issued 30,733 shares of
common stock to the Aspen Exploration Profit Sharing Plan for the benefit of
Robert A. Cohan as a corporation contribution to Mr. Cohan's 401(k) account.

(iii) This number includes 20,000 shares of common stock granted December
13, 1996; 20,000 shares of common stock granted November 1, 1997; stock options
to purchase 65,000 shares of restricted common stock; stock options to purchase
150,000 shares of restricted common stock, which includes 50,000 shares of
restricted common stock that were exercised on May 14, 2004 and 50,000 shares of
restricted common stock that were exercised on March 9, 2005; and stock options
granted for 80,000 shares of common stock that were exercised on December 17,
2001.

(iv) This includes warrants to purchase 300,000 shares of our common stock
with an exercise price of $1.10 per share through June 30, 2006 ($1.20 per share
if exercised after June 30, 2005). The holder exercised the warrant before March
31, 2005, and received an additional warrant exercisable to purchase 300,000
shares at $1.25 per share (also through June 30, 2006), which is also included
in the foregoing calculation.

Except with respect to the employment agreement between Aspen and R. V.
Bailey and between Aspen and Robert Cohan, we know of no arrangement, the
operation of which may, at a subsequent date, result in change in control of
Aspen.

See Item 5, above, for information regarding securities authorized for
issuance under equity compensation plans in the form required by Item 201(d) of
Regulation S-B.

ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
-------------------------------------------------------

The following sets out information regarding transactions between officers,
directors and significant shareholders of Aspen during the most recent two
fiscal years and during the subsequent fiscal year.

Working Interest Participation:

Some of the directors and officers of Aspen are engaged in various aspects
of oil and gas and mineral exploration and development for their own account.
Aspen has no policy prohibiting, nor does its Certificate of Incorporation
prohibit, transactions between Aspen and its officers and directors. We plan to
enter into cost-sharing arrangements with respect to the drilling of its oil and
gas properties. Directors and officers may participate, from time to time, in
these arrangements and such transactions may be on a non-promoted basis (actual
costs), although they have participated mainly on a promoted basis, but must be
approved by a majority of the disinterested directors of our Board of Directors.

R. V. Bailey, vice president and director of Aspen, Robert A. Cohan,
president and director of Aspen, and Ray K. Davis, consultant to Aspen, each
have working and royalty interests in certain of the California oil and gas
properties operated by Aspen. The affiliates paid for their proportionate share
of all costs to acquire, develop and operate these properties. As of June 30,
2005, working interests of the Company and its affiliates in certain producing
California properties are set forth below:

GROSS WELLS NET WELLS
GAS GAS
--- ---
Aspen Exploration 59 11.52
R. V. Bailey 39 1.15
R. A. Cohan 39 .71
R. K. Davis 47 .94
J. L. Shelton 31 .08

Amended Royalty and Working Interest Plan:

The allocations for royalty under Aspen's "Royalty and Working Interest
Plan" for employees are based on a determination of whether there is any "room"
for royalties in a particular transaction. In some specific cases an oil or gas
property or project is sufficiently burdened with existing royalties so that no
additional royalty burden can be allocated to our employees for that property or
project. In other situations a determination may be made that there are royalty
interests available for assignment to our employees. The determination of
whether royalty interests are available and how much to assign to employees
(usually less than 3%) is made on a case by case basis by Robert A. Cohan,
president, and R. V. Bailey, vice president, both of whom may benefit from
royalty interests assigned. During fiscal 2002, assignments to Mr. Cohan and Mr.
Bailey have been on an equal basis, while Ms. Judy Shelton, the corporate office
manager, was assigned a lesser amount. For fiscal 2003 Mr. Bailey and Ms.
Shelton shared a proportionately lesser amount. A discussion of specific
royalties assigned is included in Item 10 "Executive Compensation" above.

Employment Agreements

See Item 10, Executive Compensation -- Employment contracts and termination
of employment and change in control arrangements, for a discussion of the
current employment contracts between Aspen and Messrs. Cohan and Bailey.

Other Arrangements:

During the fiscal years 2005 and 2004, Aspen paid for various hospitality
functions and for travel, lodging and hospitality expenses for spouses who
occasionally accompanied directors when they were traveling on company business.
Our president has also supplied Aspen with certain promotional items. The net
effect of these items has been a cost to Aspen of less than $5,000 for the
fiscal years ended June 30, 2005 and 2004, respectively. Management believes
that the expenditures were to Aspen's benefit. During the years ended June 30,
2005 and 2004, Aspen provided one vehicle each to Aspen's president and vice
president.

Certain Business Relationships:

None.

(1)-(5) Indebtedness of Management:

None.

Transactions with Promoters:

Not applicable.

ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K.
------------------------------------------

Exhibits Pursuant to Item 601 of Regulation S-B:

Exhibit No. Title
----------- --------------------------------------------------------------

3.01 Certificate of Incorporation (1)
3.02 Registrant's Bylaws. (1)
3.03 Bylaws - Subsidiary (1)
3.20 Registrant's Amended and Restated Bylaws(10)
4.01 Specimen Common Stock Certificate. (1)
10.01 Royalty and Working Interest Plan (1)
10.02 Employment Agreement between Aspen Exploration Corporation and
Robert A. Cohan dated January 1, 2003 (10)
10.03* Employment Agreement between Aspen Exploration Corporation and
R.V. Bailey dated May 1, 2003, as amended
10.08 Stock Purchase Agreement between Aspen Exploration Corporation
and R.V. Bailey dated January, 1983 (7)
10.13 Split-Dollar Life Insurance Plan for R.V. Bailey (8)
10.15 Stock Purchase Agreement between Aspen Exploration Corporation
and R.V. Bailey dated June, 1993 (9)
22.1 Subsidiaries of Aspen Exploration Corporation
Aspen Gold Mining Company, a Colorado corporation
Aspen Power Systems, LLC, a Colorado limited liability
company
31* Certification pursuant to Rule 13a-14
32* Certification pursuant to 18 U.S.C.ss.1350

* Filed herewith.

1 Incorporated by reference from Commission File No. 2-69324.

7 Incorporated by reference from Annual Report on Form 10-K dated June 30,
1991 (filed on September 27, 1991).

8 Incorporated by reference from Annual Report on Form 10-K dated June 30,
1992 (filed on October 3, 1992).

9 Incorporated by reference from Annual Report on Form 10-KSB dated June 30,
1993 (filed on September 27, 1993).

10 Incorporated by reference from Annual Report on form 10-KSB dated June 30,
2003 (filed on September 22, 2003).

ITEM 14. PRINCIPAL ACCOUNTANT'S FEES AND SERVICES.
--------------------------------------------------

(a) Audit Fees.

Our principal accountant, Gordon Hughes & Banks LLP, billed us aggregate
fees in the amount of approximately $26,700 for the fiscal year ended June 30,
2005 and approximately $23,000 for the fiscal year ended June 30, 2004. These
amounts were billed for professional services that Gordon Hughes & Banks LLP
provided for the audit of our annual financial statements, review of the
financial statements included in our report on 10-QSB and other services
typically provided by an accountant in connection with statutory and regulatory
filings or engagements for those fiscal years.

(b) Audit-Related Fees.

Gordon Hughes & Banks LLP billed us aggregate fees in the amount of $21,300
and $18,300 for the fiscal years ended June 30, 2005 and 2004 for assurance and
related services that were reasonably related to the performance of the audit or
review of our financial statements.

Gordon Hughes & Banks LLP billed us aggregate fees in the amount of
approximately $5,400 for the fiscal year ended June 30, 2005 and approximately
$4,750 for the fiscal year ended June 30, 2004, for tax compliance, tax advice,
and tax planning.

(d) All Other Fees

Gordon Hughes & Banks LLP billed us aggregate fees in the amount of $-0-
for the fiscal years ended June 30, 2005 and 2004 for other fees.

(e) Audit Committee's Pre-Approval Practice

Inasmuch as Aspen does not have an audit committee, Aspen's board of
directors performs the functions of its audit committee. Section 10A(i) of the
Securities Exchange Act of 1934 prohibits our auditors from performing audit
services for us as well as any services not considered to be "audit services"
unless such services are pre-approved by the board of directors (in lieu of the
audit committee) or unless the services meet certain de minimis standards.

The board of directors has adopted resolutions that provide that the board
must:

Preapprove all audit services that the auditor may provide to us or any
subsidiary (including, without limitation, providing comfort letters in
connection with securities underwritings or statutory audits) as required
by ss.10A(i)(1)(A) of the Securities Exchange Act of 1934 (as amended by
the Sarbanes-Oxley Act of 2002).

Preapprove all non-audit services (other than certain de minimis services
described in ss.10A(i)(1)(B) of the Securities Exchange Act of 1934 (as
amended by the Sarbanes-Oxley Act of 2002) that the auditors propose to
provide to us or any of its subsidiaries.

The board of directors considers at each of its meetings whether to approve
any audit services or non-audit services. In some cases, management may present
the request; in other cases, the auditors may present the request. The board of
directors has approved Gordon Hughes & Banks LLP performing our audit for the
2004 and 2003 fiscal years, as well as tax services for the 2003 and 2004 fiscal
years.

The percentage of the fees for audit, audit-related, tax and other services were
as set forth in the following table:

Percentage of total fees paid to Gordon Hughes & Banks LLP
----------------------------------------------------------
Fiscal Year 2005 Fiscal Year 2004
---------------- ----------------
Audit fees 66% 67%
Audit-related fees 14% 14%
Tax fees 20% 19%
All other fees 0% 0%

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the Registrant
has duly caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized.

September 23, 2005

ASPEN EXPLORATION CORPORATION,
a Delaware Corporation

By: /s/ Robert A. Cohan
---------------------------------
Robert A. Cohan
President, Chief Executive Officer, and
Chief Financial Officer

Pursuant to the requirement of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated:

Date Name and Title Signature
---- -------------- ---------

September 23, 2005 Robert A. Cohan /s/ Robert A. Cohan
Principal Executive Officer, ----------------------
Principal Financial Officer
Director

September 23, 2005 R. V. Bailey /s/ R. V. Bailey
Chairman of the Board ----------------------
Director

September 23, 2005 Robert F. Sheldon /s/ Robert F. Sheldon
Director ----------------------

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Page
----

Report of Independent Auditors................................................40

Financial Statements as of June 30, 2005 and June 30, 2004:

Consolidated Balance Sheets................................................41-42

Consolidated Statements of Operations.........................................43

Consolidated Statement of Stockholders' Equity................................44

Consolidated Statements of Cash Flows.........................................45

Notes to Consolidated Financial Statements.................................46-65

INDEPENDENT AUDITORS' REPORT

Board of Directors
Aspen Exploration Corporation and Subsidiary
Denver, Colorado

We have audited the consolidated balance sheets of Aspen Exploration Corporation
and Subsidiary as of June 30, 2005 and 2004 and the related consolidated
statements of operations, stockholders' equity, and cash flows for the years
ended June 30, 2005 and 2004. These financial statements are the responsibility
of the Company's management. Our responsibility is to express an opinion on
these consolidated financial statements based on our audits.

We conducted our audits in accordance with standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audits to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Aspen Exploration
Corporation and Subsidiary as of June 30, 2005 and 2004, and the results of
their consolidated operations and cash flows for the years ended June 30, 2005
and 2004 in conformity with accounting principles generally accepted in the
United States of America.

/s/ GORDON, HUGHES & BANKS, LLP

Greenwood Village, Colorado
August 19, 2005

Item 7. Financial Statements and Supplementary Data
---------------------------------------------------

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS

ASSETS
June 30,
2005 2004
----------- -----------

Current Assets:
Cash and cash equivalents, including $2,812,971 and
$1,127,874 of invested cash in 2005 & 2004, respectively
(Note 1) ................................................ $ 3,430,146 $ 1,329,376

Accounts & trade receivables .............................. 614,720 556,558

Accounts receivable - related party (Notes 1 and 7) ....... 13,000 12,742

Prepaid expenses .......................................... 15,422 15,422

Precious metals (Note 1) .................................. 18,823 18,823
----------- -----------

Total current assets ...................................... 4,092,111 1,934,236
----------- -----------

Investment in oil & gas properties, at cost (full cost method
of accounting) (Note 9) ................................. 9,670,383 8,216,136

Less accumulated depletion and valuation allowance ...... (4,587,090) (3,235,171)
----------- -----------

5,083,293 4,980,965
----------- -----------

Property and equipment, at cost:

Furniture, fixtures & vehicles ............................ 154,819 112,562

Less accumulated depreciation ........................... (74,044) (81,958)
----------- -----------

80,775 30,604
----------- -----------

Total assets ................................................ $ 9,256,179 $ 6,945,805
=========== ===========

(Statement Continues)
See Summary of Accounting Policies and Notes to Consolidated Financial Statements

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS (Continued)

LIABILITIES AND STOCKHOLDERS' EQUITY

June 30,
2005 2004
----------- -----------

Current liabilities:

Accounts payable and accrued expenses ....................... $ 655,190 $ 932,814

Accounts payable - related party (Note 7) ................... 103,233 70,774

Advances from joint interest owners ......................... 710,477 621,015

Notes payable - current (Note 6), net of discount ........... -0- 410,719

Asset retirement obligation (Note 14) ....................... 13,826 32,749
----------- -----------

Total current liabilities ................................... 1,482,726 2,068,071
----------- -----------

Asset retirement obligation, net of current portion (Note 14) 82,384 46,833

Deferred income taxes (Note 5) ................................ 1,015,488 296,320
----------- -----------

Total long term liabilities ................................... 1,097,872 343,153
----------- -----------

Total liabilities ........................................... 2,580,598 2,411,224
----------- -----------

Stockholders' equity:
(Notes 1 and 4):
Common stock, $.005 par value:
Authorized: 50,000,000 shares
Issued and outstanding: At June 30, 2005, 6,733,308 shares
and June 30, 2004, 5,958,979 shares ....................... 33,666 29,796

Capital in excess of par value ................................ 6,728,321 6,064,602

Accumulated retained (deficit) ................................ (69,169) (1,556,225)

Deferred compensation ......................................... (17,237) (3,592)
----------- -----------

Total stockholders' equity .................................... 6,675,581 4,534,581
----------- -----------

Total liabilities and stockholders' equity .................... $ 9,256,179 $ 6,945,805
=========== ===========

See Summary of Accounting Policies and Notes to Consolidated Financial Statements

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS

Year ended June 30,
2005 2004
----------- -----------
Revenues:

Oil and gas (Note 9) .................................... $ 3,853,177 $ 1,588,250
Management fees (Note 9) ................................ 266,127 232,430
Interest and other income ................................ 8,140 3,256
----------- -----------

Total revenues ............................................. 4,127,444 1,823,936
----------- -----------

Costs and expenses:

Oil and gas production ................................... 346,451 242,472
Depreciation, depletion and amortization ................. 1,372,265 581,402
Interest expense ......................................... 6,180 6,152
Selling, general and administrative ...................... 763,236 628,265
----------- -----------

Total costs and expenses ................................... 2,488,132 1,458,291
----------- -----------

Operating income ........................................... 1,639,312 365,645
Gain on sale of investment and vehicle (Note 11) ........... 566,912 -0-
----------- -----------

Income before income tax provision ......................... 2,206,224 365,645

Provision for income taxes ................................. (719,168) (164,970)
----------- -----------

Net income ................................................. $ 1,487,056 $ 200,675
=========== ===========

Basic earnings per common share ............................ $ .23 $ .03
=========== ===========

Diluted earnings per common share .......................... $ .22 $ .03
=========== ===========

Basic weighted average number of common shares outstanding . 6,488,001 5,876,081
=========== ===========

Diluted weighted average number of common shares outstanding 6,786,499 6,686,932
=========== ===========

See Summary of Accounting Policies and Notes to Consolidated Financial Statements

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

Accumulated
Common Stock (par $.005) (Deficit)
------------------------ Retained Deferred Total
Shares Par Value APIC Earnings Compensation Equity
----------- ----------- ----------- ----------- ----------- -----------

Balance, June 30, 2003 5,863,828 $ 29,320 $ 6,025,797 $(1,756,900) $ (7,184) $ 4,291,033
Options exercised by directors and officers 74,337 372 (372) -- -- --
Options exercised by consultant 12,389 62 (62) -- -- --
Options exercised by employee 8,425 42 (42) -- -- --
Amortization of deferred compensation -- -- -- -- 3,592 3,592
Warrants issued and debt discounted -- -- 39,281 -- -- 39,281
Net income -- -- -- 200,675 -- 200,675
----------- ----------- ----------- ----------- ----------- -----------

Balance, June 30, 2004 5,958,979 29,796 6,064,602 (1,556,225) (3,592) 4,534,581
=========== =========== =========== =========== =========== ===========

Stock issued for debt and interest 300,500 1,503 259,717 -- -- 261,219
Options exercised by directors and officers 109,167 545 (545) -- -- --
Options exercised by employee 9,173 46 (46) -- -- --
Options exercised by consultant 13,489 67 (67) -- -- --
Stock issued for consulting services 28,000 140 34,860 -- (35,000) --
Stock warrants exercised 300,000 1,500 328,500 -- -- 330,000
Stock issued for consulting services 14,000 70 41,300 -- (41,370) --
Amortization of deferred compensation -- -- -- -- 62,725 62,725
Net Income -- -- -- 1,487,056 -- 1,487,056
----------- ----------- ----------- ----------- ----------- -----------

Balance, June 30, 2005 6,733,308 $ 33,666 $ 6,728,321 $ (69,169) $ (17,237) $ 6,675,581
=========== =========== =========== =========== =========== ===========

See Summary of Accounting Policies and Notes to Consolidated Financial Statements

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended June 30,
2005 2004
----------- -----------

Cash flows from operating activities:
-------------------------------------

Net income ....................................................... $ 1,487,056 $ 200,675

Adjustments to reconcile net income to net cash
provided by operating activities:
Amortization of deferred compensation ....................... 62,725 3,592
Depreciation, depletion, and amortization ................... 1,372,265 581,402
Deferred income tax provision ............................... 719,168 164,970
Gain on sale of investment and vehicle ...................... (566,912) -0-
Changes in assets and liabilities:
Decrease (increase) in receivable and prepaid expenses ...... (57,105) (288,295)
Increase (decrease) in accounts payable, accrued expenses and
advances from joint owners ................................ (155,703) 874,202
----------- -----------

Net cash provided by operating activities .......................... 2,861,494 1,536,546

Cash flows from investing activities:
-------------------------------------

Additions to oil and gas properties .............................. (1,446,179) (1,026,531)
Producing oil and gas properties purchased ....................... (19,248) (421,583)
Additions to property and equipment .............................. (45,613) -0-
Sale of oil and gas equipment .................................... -0- 14,378
Sale of mining stock ............................................. 560,090 -0-
Sale of vehicle .................................................. 10,226 -0-
----------- -----------

Net cash (used) by investing activities ............................ (940,724) (1,433,736)
----------- -----------

Cash flows from financing activities:
-------------------------------------

Common stock issued .............................................. 330,000 -0-
Proceeds from notes payable ...................................... -0- 525,000
Payment of notes payable ......................................... (150,000) (75,000)
----------- -----------

Net cash provided by financing activities .......................... 180,000 450,000
----------- -----------

Net increase (decrease) in cash and cash equivalents ............... 2,100,770 552,810

Cash and cash equivalents, beginning of year ....................... 1,329,376 776,566
----------- -----------

Cash and cash equivalents, end of year ............................. $ 3,430,146 $ 1,329,376
=========== ===========

Other information:
------------------

Interest paid ...................................................... $ 6,180 $ 6,152
=========== ===========

Income taxes paid .................................................. $ 800 $ 800
=========== ===========

Non-cash investing and financing activities:

Asset retirement obligation ...................................... $ 28,977 $ (66,454)
Conversion of debt for equity .................................... 261,219 --
Stock issued for deferred consulting services .................... 76,370 --

See Summary of Accounting Policies and Notes to Consolidated Financial Statements

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business
------------------

We were incorporated under the laws of the State of Delaware on February
28, 1980 for the primary purpose of acquiring, exploring and developing oil
and gas properties. Our principal executive offices are located at 2050 S.
Oneida St., Suite 208, Denver, Colorado 80224. Our telephone number is
(303) 639-9860, and our facsimile number is 303-639-9863. We are currently
engaged primarily in the exploration and development of oil and gas
properties in California.

Oil and Gas Exploration and Development. Our major emphasis has been our
participation in the oil and gas segment acquiring interests in producing
oil or gas properties and participating in drilling operations. We engage
in a broad range of activities associated with the oil and gas business in
an effort to develop oil and gas reserves. With the assistance of our
management, independent contractors retained from time to time by Aspen,
and, to a lesser extent, unsolicited submissions, we have identified and
will continue to identify prospects that we believe are suitable for
drilling and acquisition. Currently, our primary area of interest is in the
state of California. We have acquired a number of interests in oil and gas
properties in California, as described below in more detail. In addition,
we also act as operator for a number of our producing wells and receive
management fee revenues for these services.

A summary of our Company's significant accounting policies follows:

Consolidated Financial Statements
---------------------------------

The consolidated financial statements include our Company and its
wholly-owned subsidiary, Aspen Gold Mining Company. Significant
intercompany accounts and transactions, if any, have been eliminated. The
subsidiary is currently inactive.

Statement of Cash Flows
-----------------------

For statement of cash flows purposes, we consider short-term investments
with original maturities of three months or less to be cash equivalents.
Cash restricted from use in operations beyond three months is not
considered a cash equivalent.

Management's Use of Estimates
-----------------------------

Accounting principles generally accepted in the United States of America
require us to make 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. Actual results could differ from those estimates.

The mining and oil and gas industries are subject, by their nature, to
environmental hazards and cleanup costs for which we carry catastrophe
insurance. At this time, we know of no substantial costs from environmental
accidents or events for which we may be currently liable. In addition, our
oil and gas business makes it vulnerable to changes in wellhead prices of
crude oil and natural gas. Such prices have been volatile in the past and
can be expected to be volatile in the future. By definition, proved
reserves are based on current oil and gas prices and estimated reserves.
Price declines reduce the estimated quantity of proved reserves and
increase annual depletion expense (which is based on proved reserves).

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Impairment of Long-lived Assets
-------------------------------

Long-lived assets and identifiable intangibles are reviewed for impairment
whenever events or changes in circumstances indicate that the carrying
amount may not be recoverable. If the expected undiscounted future cash
flow from the use of the assets and their eventual disposition is less than
the carrying amount of the assets, an impairment loss is recognized and
measured using the asset's fair value or discounted cash flows.

Financial Instruments
---------------------

The carrying value of current assets and liabilities reasonably
approximates their fair value due to their short maturity periods. The
carrying value of our debt obligations reasonably approximates their fair
value as the stated interest rate approximates current market interest
rates of debt with similar terms.

Precious Metals and Revenues
----------------------------

Precious metals inventories are valued at the lower of cost (specific
identification method) or market. There were no sales of gold from
inventory for the years ended June 30, 2005 and 2004.

Oil and Gas Properties
----------------------

We follow the "full-cost" method of accounting for our oil and gas
properties. Under this method, all costs associated with property
acquisition, exploration and development activities, including internal
costs that can be directly identified with those activities, are
capitalized within one cost center. No gains or losses are recognized on
the receipt of prospect fees or on the sale or abandonment of oil and gas
properties, unless the disposition of significant reserves is involved.

Depletion and amortization of our full-cost pool is computed using the
units-of-production method based on proved reserves as determined annually
by us and independent engineers. An additional depletion provision in the
form of a valuation allowance is made if the costs incurred on our oil and
gas properties, or revisions in reserve estimates, cause the total
capitalized costs of our oil and gas properties in the cost center to
exceed the capitalization ceiling. The capitalization ceiling is the sum of
(1) the present value of our future net revenues from estimated production
of proved oil and gas reserves applicable to the cost center plus (2) the
lower of cost or estimated fair value of our cost center's unproved
properties less (3) applicable income tax effects. The valuation allowance
was $281,719 at June 30, 2005 and 2004 (Note 9). Depletion and amortization
expense was $1,354,055 and $563,622 for the years ended June 30, 2005 and
2004, respectively.

Property and Equipment
----------------------

Depreciation and amortization of our property and equipment are expensed in
amounts sufficient to relate the expiring costs of depreciable assets to
operations over estimated service lives, principally using the
straight-line method. Estimated service lives range from three to eight
years. When assets are sold or otherwise disposed of, the cost and
accumulated depreciation are removed from the accounts and any resulting
gain or loss is reflected in operations in the period realized.
Depreciation expense was $18,210 and $17,780 for the years ended June 30,
2005 and 2004, respectively.

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Deferred Compensation Costs
---------------------------

We record the fair value of stock bonuses to employees and consultants as
an expense and an increase to paid-in capital in the year of grant unless
the bonus vests over future years. Bonuses that vest are deferred and
expensed ratably over the vesting period. During the fiscal year ended June
30, 2005 and 2004, we expensed $62,725 and $3,592, respectively, in stock
bonuses.

Allowance for Bad Debts
-----------------------

The Company extends credit to participants of our drilling prospects and
operated wells. We bear the risks inherent in granting credit to these
customers. Management reviews accounts receivable on a regular basis to
determine if any receivables will potentially be uncollectible. We include
any accounts receivable that are determined to be uncollectible, along with
a general reserve, in the overall allowance for doubtful accounts. After
all attempts to collect the receivable have failed, the receivable is
written off against the allowance. As of June 30, 2005 and 2004, based on
information available, management considers accounts receivable to be fully
collectible as recorded, accordingly, no allowance for doubtful accounts is
required.

Revenue Recognition
-------------------

Sales of oil and gas production are recognized at the time of delivery of
the product to the purchaser.

Management fees from outside parties are recognized at the time the
services are rendered.

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.

2005
------------------------------------
Per
Net Share
Income Shares Amount
----------- ----------- -------

Basic earnings per share:

Net income and
share amounts $ 1,487,056 6,488,001 $ .23

Dilutive securities 552,000

Purchased shares (253,502)
----------- ----------- -------

Diluted earnings per share:

Net income and assumed
share conversion $ 1,487,056 6,786,499 $ .22
=========== =========== =======

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2004
--------------------------------
Per
Net Share
Income Shares Amount
--------- --------- -------

Basic earnings per share:

Net income and
share amounts $ 200,675 5,876,081 $ .03

Dilutive securities
stock options 484,000

Convertible debt and warrants 600,000

Repurchased shares (273,149)
--------- --------- -------

Diluted earnings per share:

Net income and assumed
share conversion $ 200,675 6,686,932 $ .03
========= ========= =======

Segment Reporting
-----------------

We follow SFAS No. 131, "Disclosure about Segments of an Enterprise and
Related Information", which amended the requirements for a public
enterprise to report financial and descriptive information about its
reportable operating segments. Operating segments, as defined in the
pronouncement, are components of an enterprise about which separate
financial information is available that is evaluated regularly by us in
deciding how to allocate resources and in assessing performance. The
financial information is required to be reported on the basis that is used
internally for evaluating segment performance and deciding how to allocate
resources to segments. We operate in one industry segment, exploration and
development of oil and gas properties.

Income Taxes
------------

We account for income taxes under SFAS No. 109, "Accounting for Income
Taxes". Temporary differences are differences between the tax basis of
assets and liabilities and their reported amounts in the financial
statements that will result in taxable or deductible amounts in future
years.

Stock Award and Stock Option Plans
----------------------------------

We grant common stock and stock options to employees and non-employees and
apply Accounting Principles Board (APB) Opinion No. 25 (APB 25),
"Accounting for Stock Issued to Employees", and related Interpretations in
accounting for all stock award and stock option plans for employees and
directors.

Following the guidance of APB 25, compensation cost has been recognized for
stock options issued to employees and directors as the excess of the market
price of the underlying common stock on the date of the grant over the
exercise price of the Company's stock options on the date of the grant.

SFAS No. 123, "Accounting for Stock-Based Compensation", requires us to
provide pro forma information regarding net income as if compensation cost
for the Company's stock option plans had been determined in accordance with
the fair value based method prescribed in SFAS No. 123. To provide the
required pro forma information, we estimate the fair value of each stock
option at the grant date by using the Black-Scholes option-pricing model.

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In certain circumstances, we issue common stock for invoiced services, to
pay creditors and in other similar situations. In accordance with SFAS No.
123, payments in equity instruments to non-employees for goods or services
are accounted for by the fair value method, which relies on the valuation
of the service at the date of the transaction, or public stock sales price,
whichever is more reliable as a measurement.

Options were granted but not vested to directors and employees during the
fiscal year 2002. An adjustment to net income for compensation expense to
recognize annual vesting would be recorded under SFAS No. 123, on a pro
forma basis, as reflected in the following table:

2005 2004
---------- ----------

Net Income (loss): As Reported $1,487,056 $ 200,675
Pro Forma 1,451,272 176,414
Basic Earnings
Per Share: As Reported .23 .03
Pro Forma .23 .02
Diluted Earnings
Per Share: As Reported .22 .03
Pro Forma .21 .02

Reclassification
----------------

Certain 2004 amounts have been reclassified to conform to 2005
presentation.

Recently issued pronouncements
------------------------------

Reporting Accounting Changes in Interim Financial Statements
------------------------------------------------------------

In May 2005, the FASB issued FASB Statement 154. This Statement replaces
APB Opinion No. 20, "Accounting Changes", and FASB Statement No. 3,
"Reporting Accounting Changes in Interim Financial Statements", and changes
the requirements for the accounting for and reporting of a change in
accounting principle. This Statement applies to all voluntary changes in
accounting principle. It also applies to changes required by an accounting
pronouncement in the unusual instance that the pronouncement does not
include specific transition provisions. When a pronouncement includes
specific transition provisions, those provisions should be followed.
Management does not believe the adoption of this pronouncement will have a
material impact on the financial statements.

Note 2 EMPLOYEE BENEFIT PLANS

Defined Contribution Plan
-------------------------

We have a 401(k) defined contribution plan that covers all employees. Under
the amended terms of the plan, an employee is eligible to participate in
the plan immediately upon being hired to work at least 1,000 hours per year
and having attained age 21. Participants may contribute up to a maximum of
14.95% of their pre-tax earnings (not to exceed $13,000) to the plan. Under
the plan, we may make discretionary contributions to the plan. We made
contributions for fiscal 2005 and 2004 in the amount of $-0- and $8,550,
respectively.

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Medical Benefit Plan
--------------------

For the fiscal years ended June 30, 2005 and 2004, we had a policy of
reimbursing employees for medical expenses incurred but not covered by our
paid medical insurance plan. Expenses reimbursed for fiscal 2005 and fiscal
2004 were $8,437 and $8,939, respectively. Under the terms of a revised
employment agreement (see Note 11) with Mr. Bailey, effective May 1, 2003
he will be responsible for his own medical insurance premiums and will no
longer be reimbursed excess medical expenses.

Note 3 MAJOR CUSTOMERS

We derived in excess of 10% of revenue from our major customers as follows:

Company
---------
A B C
----- ----- -----
Year ended:

June 30, 2005 36% 51% *
June 30, 2004 21% 52% 15%

* Less than 10% for fiscal 2005

Note 4 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. In July 2004, the debt was converted to 300,500 share of common
stock as consideration for payment of principal and interest. See Note 6.

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 would
receive $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.

The holder exercised the warrant before March 31, 2005 and received an
additional warrant exercisable to purchase another 300,000 shares at $1.25
per share.

The outstanding 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. The discount was
amortized until the debt was converted to common stock in July 2004 at
which time the unamortized balance was expensed.

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 6 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.

During fiscal 2005, two directors, one officer, 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 60,171. The effect of the
transaction is a net increase to the common stock par value of $658 and a
corresponding decrease to additional paid in capital of $658.

On April 27, 2005 stock options to acquire 260,000 shares of our common
stock were granted to officers, directors, consultants and employees. The
grant price was $2.67 per share and are exercisable over a three year
period ending January, 2008.

As of June 30, 2005, we had an aggregate of 552,000 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.

Total compensation expense in the statement of operations includes
amortization of prior stock awards of $62,725 and $3,592 for the years
ended June 30, 2005 and 2004, respectively.

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, 2003 776,000 $ .58
========

Granted -0- --
========

Exercised (192,000) --
========

Forfeited or expensed (100,000) --
========
--------

Outstanding balance June 30, 2004 484,000 .58
========

Granted 260,000 2.67
========

Exercised (192,000) .57
========
--------

Outstanding balance June 30, 2005 552,000 $ 1.56
======== ========

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information concerning outstanding and
exercisable options as of June 30, 2005:

Outstanding Exercisable
------------------------------- ----------------------
Weighted
Average Weighted Weighted
Remaining Average Average
Exercise Number Contractual Exercisable Number Exercise
Price Outstanding Life In Years Price Exercisable Price
----- ----------- ------------- ----- ----------- -----

$ .57 142,000 08/15/2005(1) $ .57 -0- $ .57

.57 150,000 08/15/2007(1) .57 -0- .57

2.67 260,000 01/01/2007(1) 2.67 -0- 2.67
-------

552,000
=======

(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 stock options using APB No. 25 for directors and employees
and SFAS No. 123 for consultants.

There were 260,000 options granted in 2005. Directors and employees were
granted 235,000 and consultants were granted 25,000. 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
159.54%, risk free interest rates of 3.92% and expected lives of 4.5 years.
The resulting compensation expense relating to the option grant to
directors and employees of $549,821 and consultant of $58,492 will be
included as an operating expense ratably over the vesting period. The
options vest one-third January 2006, 2007 and 2008.

Note 5 INCOME TAXES

We recorded a deferred income tax liability of $1,015,488 and $296,320 as
of June 30, 2005 and 2004, respectively. We paid $800 in California state
income taxes in fiscal 2005. During 2005, we used approximately $2,000,000
in net operating loss carryforwards leaving $7,000 available federal net
operating loss carryforwards as of June 30, 2005.

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.

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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:

2005 2004
----------- -----------
Deferred tax assets:

Federal tax loss
carryforwards $ 2,189 $ 669,929
Asset retirement obligation 5,715 4,727
----------- -----------
7,904 674,656
----------- -----------

Deferred tax (liabilities):
Property, plant and
equipment (2,365) (2,684)
Oil and gas properties (1,021,027) (968,292)
----------- -----------

(1,023,392) (970,976)
----------- -----------
$(1,015,488) $ (296,320)
=========== ===========

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A reconciliation between the statutory federal income tax rate (34%) and
the effective rate of income tax expense for the two years ended June 30 is
as follows:

2005 2004
--------- ---------
Statutory federal income
tax rate 34% 34%

Statutory state income tax
rate, net of federal benefit 9% 9%

Other (10%) (2%)
--------- ---------

Effective rate 33% 45%
========= =========

The provision for income taxes consists of the following components:

2005 2004
--------- ---------

Current tax expense (refund),
state $ -0- $ -0-

Deferred tax expense 719,168 164,970
--------- ---------

Total income tax provision $ 719,168 $ 164,970
========= =========

At June 30, 2005, we have $7,000 available federal net operating loss
carryforwards having offset approximately $2,000,000 of net operating
losses available at the beginning of fiscal 2005 with current taxable
income.

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 NOTES PAYABLE

The Company incurred the following debt:

June 30, June 30,
2005 2004
--------- ---------

Note payable to a bank $ -0- $ 150,000

Convertible debenture issued to a
privately held corporation -0- 300,000
--------- ---------

-0- 450,000

Less discount -0- (39,281)
--------- ---------

$ -0- $ 410,719
========= =========

Proceeds from the note payable to a bank was used for the acquisition of
producing gas properties located in several counties in the Sacramento
Valley, California. The note matured in June 2005, principal payments were
$12,500 per month plus interest at the bank's prime rate plus 2%. The loan
was collateralized by accounts receivable, other rights to payments and all
inventory.

On June 28, 2004, a privately-held Oklahoma corporation purchased a
$300,000 convertible debenture from Aspen Exploration Corporation. We also
issued warrants to purchase 300,000 shares of our common stock (see Note
4).

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.

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 7 RELATED PARTY TRANSACTIONS

During fiscal 2005, we assigned the following overrides at no cost to
employees:

R. V. R. A. J. L.
Bailey Cohan Shelton
------ ----- -------

Griffin 1-1 0.8500% 1.2500% 0.4000%
Meckfessel 1-24 1.1900% 1.7500% 0.5600%

R. V. Bailey, Vice President and former President and director of the
Company, Robert A. Cohan, President and director of the Company, have
working and royalty interests in certain of the California oil and gas
properties operated by us. The related parties paid for their proportionate
working interest share of all costs to acquire, develop and operate these
properties on the same terms as other unaffiliated participants. Mr. Bailey
and Mr. Cohan purchased working interests amounts totaling $195,800 and
$82,800, respectively, for the year ended June 30, 2005, and $166,005 and
$77,325, respectively, for the year ended June 30, 2004. Mr. Bailey and Mr.
Cohan also received royalty interest payments totaling $96,224 and
$128,055, respectively, for the year ended June 30, 2005, and $55,840 and
$51,022, respectively, for the year ended June 30, 2004. As of June 30,
2005, working interests of us and related parties in certain producing
California properties are as set forth below:

GROSS WELLS NET WELLS
GAS GAS
--- ---
Aspen Exploration 59 11.52
R. V. Bailey 39 1.15
R. A. Cohan 39 .71
R. K. Davis 47 .94
J. L. Shelton 31 .08

We have received advances from Messrs. Bailey, Cohan and Davis for working
interests in uncompleted wells of $37,640, $21,400 and $38,100,
respectively, as of June 30, 2005 and $27,410, $18,269 and $16,573 as of
June 30, 2004, respectively. Additionally, we owed Mr. Bailey $5,887 for
reimbursement of expenses made on our behalf as of June 30, 2005 and we owe
Mr. Bailey and Mr. Cohan $6,062 and $2,460 for reimbursed expenses on our
behalf in 2004. Messrs. Bailey, Cohan and Davis owed us $8,255, $2,120 and
$2,986, respectively, as of June 30, 2005 and $8,252, $1,694 and $2,796,
respectively, as of June 30, 2004 for their portion of well operating
expenses.

See Note 10 for additional related party disclosure.

Note 8 CONCENTRATION OF CREDIT RISK

Financial instruments, which potentially subject us to concentrations of
credit risk, consist principally of cash and cash equivalents, accounts
receivable and the cash surrender value of life insurance. While as of June
30, 2005 we have approximately $3,330,000 in excess of the Federal Deposit
Insurance Corporation $100,000 limit at one bank, we place our cash and
cash equivalents with high quality financial institutions in order to limit
credit risk. Concentrations of credit risk with respect to accounts
receivable are distributed across unrelated businesses and individuals,
with the exception of two major gas purchasers and one investor in our
wells, who normally settle within 25 days of the previous month's gas
purchases. We believe our exposure to credit risk is minimal.

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cash equivalents are invested through a quality national brokerage firm and
a major regional bank. The cash equivalents consists of liquid short-term
investments. The Securities Investor Protection Corporation insures the
Fund's accounts at this brokerage firm and a commercial insurer up to the
total amount held in the account.

Note 9 OIL AND GAS ACTIVITIES

Capitalized costs
-----------------

Capitalized costs associated with oil and gas producing activities are as
follows:

June 30,
2005 2004
----------- -----------

Proved properties $ 9,670,383 $ 8,216,136
----------- -----------

Accumulated depreciation,
depletion and
amortization (4,367,371) (2,953,452)

Valuation allowance (281,719) (281,719)
----------- -----------

(4,649,090) (3,235,171)
----------- -----------

Net capitalized costs $ 5,083,293 $ 4,980,965
=========== ===========

Results of operations
---------------------

Results of operations for oil and gas producing activities are as follows:

Year ended June 30,
--------------------------
2005 2004
----------- -----------

Revenues* $ 4,119,304 $ 1,820,680
Production costs (346,452) (242,472)
Depreciation, depletion and accretion (1,354,055) (563,622)
Interest expense (6,180) (6,152)
----------- -----------
Results of operations
(excluding corporate overhead) $ 2,412,617 $ 1,008,434
=========== ===========

*Includes oil and gas related fees and management fees.

Fees charged by us to operate the properties totaled approximately $22,177
per month in 2005 and $19,370 per month in 2004.

Unaudited oil and gas reserve quantities
----------------------------------------

The following unaudited reserve estimates presented as of June 30, 2005 and
2004 were prepared by an independent petroleum engineer. There are many
uncertainties inherent in estimating proved reserve quantities and in
projecting future production rates and the timing of development
expenditures. In addition, reserve estimates of new discoveries that have
little production history are more imprecise than those of properties with
more production history. Accordingly, these estimates are expected to
change as future information becomes available.

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Proved oil and gas reserves are the estimated quantities of crude oil,
condensate, natural gas and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions.

Proved developed oil and gas reserves are those reserves expected to be
recovered through existing wells with existing equipment and operating
methods.

Unaudited net quantities of proved and proved developed reserves of crude
oil (including condensate) and natural gas (all located within the United
States) are as follows:

Changes in proved reserves (Bbls) (MCF)
-------------------------- ------ -----
(in thousands)

Estimated quantity, June 30, 2003 3 2,480

Revisions of previous estimates ( 1) (411)
Discoveries - 527
Purchased - 243
Production - (305)
---- -----

Estimated quantity, June 30, 2004 2 2,534

Revisions of previous estimates - (306)
Discoveries - 667
Production - (617)
---- -----

Estimated quantity, June 30, 2005 2 2,278
==== =====

Proved reserves Developed
at year end Developed Non-Producing Total
----------- --------- ------------- -----
(In Thousands)
Oil (Bbls)

June 30, 2005 - 2 2
June 30, 2004 - 2 2

Gas (MCF)

June 30, 2005 1,327 951 2,278
June 30, 2004 1,236 1,298 2,534

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Unaudited standardized measure
------------------------------

The following table presents a standardized measure of the discounted
future net cash flows attributable to our proved oil and gas reserves.
Future cash inflows were computed by applying year-end prices of oil and
gas to the estimated future production of proved oil and gas reserves. The
future production and development costs represent the estimated future
expenditures (based on current costs) to be incurred in developing and
producing the proved reserves, assuming continuation of existing economic
conditions. Future income tax expenses were computed by applying statutory
income tax rates to the difference between pre-tax net cash flows relating
to our proved oil and gas reserves and the tax basis of proved oil and gas
properties and available net operating loss carryforwards. Discounting the
future net cash inflows at 10% is a method to measure the impact of the
time value of money.

June 30,
--------------------
2005 2004
-------- --------
(in thousands)

Future cash inflows $ 13,837 $ 14,800
Future production and development costs (1,483) (1,568)
Future income tax expense (4,119) (4,679)
-------- --------

Future net cash flows 8,235 8,553

10% annual discount for estimated timing
of cash flows (2,510) (2,609)
-------- --------

Standardized measure of discounted future
net cash flows $ 5,725 $ 5,944
======== ========

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following presents the principal sources of the changes in the
standardized measure of discounted future net cash flows:

Years ended June 30,
--------------------
2005 2004
------- -------
(in thousands)
Standardized measure of discounted
future net cash flows, beginning of year $ 5,944 $ 4,833
------- -------

Sales and transfers of oil and gas produced,
net of production costs (3,507) (1,346)

Net changes in prices and production costs
and other 178 638

Net change due to discoveries 2,510 1,544

Acquisition of reserves -- 711

Revisions of previous quantity estimates (21) (15)

Development costs incurred 49 60

Accretion of discount 913 721

Net change in income taxes 456 (755)

Other (796) (447)
------- -------

(219) 1,111
------- -------
Standardized measure of discounted future
cash flows, end of year $ 5,725 $ 5,944
======= =======

Net changes in prices and production costs of $178 were the result of an
increase in the price received for oil and gas at year end which was offset
slightly by an increase in operating costs associated with more producing
gas wells in 2005 than in 2004. The revision of previous estimates of $(21)
was the result of assigning approximately 260 fewer barrels of recoverable
oil and reducing recoverable reserves of gas by approximately 306,000 MCF,
while the volumes were reduced, the price applied to the remaining
recoverable reserves increased substantially, resulting in a modest
decrease. All adjustments were based on performance reviews of individual
wells. A successful drilling program added $2.5 million to our future net
cash flow. These additions represent approximately 667,000 MCF of
recoverable reserves.

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 10 COMMITMENTS AND CONTINGENCIES

Drilling Completion &
Area Wells Costs Equipping Costs Total
------------------- ----- ---------- --------------- -----------
Kirk-Buckeye Field 2 $323,000 $248,000 $571,000
Colusa County, CA

West Grimes Field 4 470,000 330,000 800,000
Colusa County, CA

Malton Black Butte 2 181,000 180,000 361,000
Tehama County, CA

Winters Gas Field 1 38,000 53,000 91,000
Yolo County, CA

----- ---------- ---------------- -----------

Total Expenditure 9 $1,012,000 $811,000 $1,823,000
===== ========== ================ ===========

Employment contracts and termination of employment and change in control
arrangements:

Mr. Bailey: Effective May 1, 2003 we entered into a new employment
agreement with Chairman of the Board, R. V. Bailey. Some of the pertinent
provisions include an employment period ending May 1, 2009, the title of
Vice President subject to the general direction of the President, Robert A.
Cohan, and the Board of Directors of Aspen. Mr. Bailey's salary will be
$45,000 per year from May 1, 2003 to December 31, 2006 and $60,000 per year
from January 1, 2007, ending May 1, 2009. Mr. Bailey will also participate
in Aspen's stock options and royalty interest programs. During the term of
the agreement, we have agreed to pay Mr. Bailey a monthly $1,700 allowance
to cover such items as prescriptions, medical and dental coverage for
himself and his dependents and other expenses not covered in the agreement.

Mr. Bailey will continue to use the Company vehicle and may trade the
current vehicle for a similar vehicle of his choice prior to June 30, 2006.
During 2007 or thereafter, Mr. Bailey may purchase the vehicle for $500.

We may terminate this agreement upon Mr. Bailey's death by paying his
estate all compensation that had or will accrue to the end of the year of
his death plus $75,000. Should Mr. Bailey become totally and permanently
disabled, we will pay Mr. Bailey one half of the salary and benefits set
forth in our agreement with him for the remainder of the term of the
agreement.

Mr. Cohan: In April 2005 Mr. Cohan's employment agreement was renewed to
December 31, 2008 with a salary increase to $160,000 per year. Other
benefits and duties will remain the same as the previous employment
contract.

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Gas sales contract

Effective April 1, 2005, we entered a contract to sell Enserco 2,000 MMBTU
of gas per day at a fixed price of $6.49 less transportation and other
expenses; and a contract to sell Calpine 1,500 MMBTU of gas per day at a
fixed price of $6.90 less transportation and other expenses. The contracts
are for the term April 1, 2005 - September 30, 2005, required Enserco and
Calpine to purchase the stated quantities at the stated prices, and
contained monetary penalties for non-delivery of the gas.

Effective November 1, 2005, we entered a contract to sell Enserco 1,000
MMBTU of gas per day at a fixed price of $8.40 less transportation and
other expenses; and a contract to sell Calpine 1,000 MMBTU of gas per day
at a fixed price of $8.43 less transportation and other expenses. The
contracts are for the term November 1, 2005 - March 31, 2006, required
Enserco and Calpine to purchase the stated quantities at the stated prices,
and contained monetary penalties for non-delivery of the gas.

Effective November 1, 2005, we entered a contract to sell Enserco 500 MMBTU
of gas per day at a fixed price of $9.49 less transportation and other
expenses; and a contract to sell Calpine 500 MMBTU of gas per day at a
fixed price of $9.48 less transportation and other expenses. The contracts
are for the term November 1, 2005 - March 31, 2006, required Enserco and
Calpine to purchase the stated quantities at the stated prices, and
contained monetary penalties for non-delivery of the gas.

Effective November 1, 2005, we entered a contract to sell Enserco 500 MMBTU
of gas per day at a fixed price of $11.02 less transportation and other
expenses; and a contract to sell Calpine 250 MMBTU of gas per day at a
fixed price of $11.02 less transportation and other expenses. The contracts
are for the term November 1, 2005 - March 31, 2006, required Enserco and
Calpine to purchase the stated quantities at the stated prices, and
contained monetary penalties for non-delivery of the gas.

Note 11 GAIN ON SALE OF INVESTMENT

In 1998, we sold certain geological data to ISL Resources Corporation (ISL)
for $250,000 in cash and 2 million shares of ISL common stock. Because ISL
was not a publicly trade company and no market value could be determined
for the common stock, we recorded the 2 million shares of common stock with
a zero cost basis. During 2004, with the reorganization of ISL, we received
500,000 shares of the new company, known as UR Energy (UR), a non-public
Canadian Company, common stock and 250,000 options to purchase common stock
of UR in exchange for our 2 million shares of ISL common stock. We
continued to report the stock with a zero basis through fiscal 2004. During
fiscal 2005, UR agreed to purchase our 500,000 shares of UR common stock
for $560,090.

Note 12 INTERIM FINANCIAL DATA

The year-end adjustment that is material to the results of the fourth
quarter ending June 30, 2005 and June 30, 2004 is the adjustment to
depreciation, depletion and amortization as a result of receiving the
reserve study from an independent reservoir engineer. The aggregate effect
of this year-end adjustment to the results of the fourth quarter was to
increase depletion expense for the fiscal year 2005 from an estimated
$610,000 based on prior years' reserve studies to an actual depletion
expense of approximately $1,354,000, an increase of $744,000 or 122% for
fiscal 2005 and approximately $496,000 to approximately $564,000, an
increase of $68,000, or 26% for fiscal 2004.

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 13 CONTRACTUAL OBLIGATIONS

We had four contractual obligations as of June 30, 2005. The following
table lists our significant liabilities at June 30, 2005:

Payments Due By Period
------------------------------------------------------------

Less than After
Contractual Obligations 1 year 2-3 years 4-5 years 5 years Total
------------------------------ ---------- ---------- --------- ------ ----------

Employment Obligations $218,500 $504,400 $67,400 -0- $790,300

Contract Service Obligations 20,000 -0- -0- -0- 20,000

Operating Leases 9,500 4,000 -0- -0- 13,500
---------- ---------- --------- ------ ----------

Total contractual
cash obligations $248,000 $508,400 $67,400 $-0- $823,800
========== ========== ========= ====== ==========

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 rent
on a month to month basis for $1,261 per month. The Bakersfield, California
office has 546 square feet and a monthly rental fee of $793 over the term
of the lease. The three year lease expires February 8, 2006. Rent expense
for the years ended June 30, 2005 and 2004 were $24,370 and $24,370,
respectively.

Note 14 ASSET RETIREMENT OBLIGATION

We have adopted the provisions of 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. 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 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 regulatory requirements.
The liability is a discounted liability using a credit-adjusted risk-free
rate of 8%. Revisions to the liability could occur due to changes in
plugging and abandonment costs, well useful lives or if federal or state
regulators enact new guidance on the plugging and abandonment of wells.

A reconciliation of our liability is as follows:

Asset retirement obligation as of
July 1, 2003 $ 17,841
Liabilities incurred 66,454
Liabilities settled (7,634)
Accretion expense 2,921
Revision to estimate -0-
--------
Asset retirement obligation as of
June 30, 2004 $ 79,582
--------

Liabilities incurred 28,977
Liabilities settled (7,881)
Accretion expense 2,136
Revision to estimate (6,604)
--------
Asset retirement obligation as of
June 30, 2005 $ 96,210
========

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 15 SUBSEQUENT EVENTS (Unaudited)

On August 30, 2005, a consultant exercised his option for 25,000 shares of
our common stock granted March 14, 2002 at a price of $0.57 per share. As
consideration for the option shares purchased, the individual paid a cash
consideration of $14,250. The effect of the transaction is a net increase
to the common stock par value of $125 and a corresponding decrease to
additional paid in capital of $125.

MALTON BLACK BUTTE, TEHAMA COUNTY, CA
-------------------------------------

The Johnson Unit #11 well was drilled to a depth of 4,800 feet and
encountered approximately 80 feet of potential gas pay in various intervals
in the Forbes formation. One of the Forbes intervals was perforated and
tested gas at a stabilized rate of approximately 700 MCFPD. The well is
currently producing 400 MCFPD. Aspen has a 21% operated working interest in
this well.

The Merrill #31-1 well was drilled to a depth of 4,875 feet and encountered
approximately 200 feet of potential net gas pay in various intervals in the
Forbes and Kione formations. One of the Forbes intervals was perforated and
tested gas at a stabilized rate of approximately 700 MCFPD. The well is
currently producing 825 MCFPD. We believe numerous potential gas zones
remain behind-pipe in this well. Aspen has a 31% operated working interest
in the Merrill #31-1 well.

WEST GRIMES FIELD, COLUSA COUNTY, CA
------------------------------------

The Morris #12-3 well was drilled to a depth of 8,000 feet and encountered
approximately 60 feet of potential net gas pay in various intervals in the
Forbes formation. A Forbes interval was perforated and tested gas at a
stabilized rate of 2,181 MCFPD. Gas sales commenced on September 8, 2005
and the well is currently producing at the rate of 825 MCFPD.

The Strain #10-2 well was drilled to a depth of 8,012 feet and encountered
approximately 75 feet of potential gross gas pay in two intervals in the
Forbes formation. One of these Forbes intervals was perforated and tested
gas on a 3/16" choke at a stabilized rate of 3,163 MCFPD with a flowing
tubing pressure of 3,900 psig and a flowing casing pressure of 4,000 psig.
The shut in tubing pressure was 4,200 psig. The well only experienced a 7%
pressure drawdown while flowing at the prolific rate of 3,163 MCFPD, which
is indicative that this zone is capable of flowing at a higher gas rate.
Gas sales commenced on September 7, 2005 and the well is currently
producing at the rate of 500 MCFPD. Aspen has a 21% operated working
interest in this field.

The Farnsworth #3-35 well located in the Grimes Gas Field, Colusa County,
California, was drilled to a depth of 7,500 feet and encountered
approximately 80 feet of potential gross gas pay in several intervals in
the Forbes formation. Production casing was run based on favorable mud log
and electric log responses. Aspen has a 21.00% operated working interest in
this well.

KIRK FIELD, COLUSA COUNTY, CA
-----------------------------

The Heidrick #11-1 well was drilled to a depth of 8,532 feet and
encountered approximately 80 feet of potential gross gas pay in several
intervals in the Forbes formation. One of these Forbes intervals was
perforated and tested gas on a 3/16 inch choke at a stabilized rate of
2,283 MCFPD with a flowing tubing pressure of 2,810 psig and a flowing
casing pressure of 2,900 psig. The shut in tubing pressure was 3,360 psig.
Aspen has a 38.67% operated working interest in this well.