FORM 10-Q-SB

                       SECURITIES AND EXCHANGE COMMISSION

                              Washington D.C. 20549

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

                For the quarterly period ended September 30, 2005

                                       OR

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

               For the transition period from ________ to ________

                          Commission File Number 0-9494

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

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

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

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

Indicate by check mark whether Aspen (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that Aspen was required to file
such reports), and (2) has been subject to such filing requirements for the past
90 days.
                            Yes  [ X ]   No  [   ]

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

                            Yes  [   ]   No  [ X ]

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

              Class                            Outstanding at November 10, 2005
              -----                            --------------------------------
Common stock, $.005 par value                           6,758,308

Transitional small business disclosure format:       ___ Yes          XX No
                                                                      -----

<PAGE>


Part One.  FINANCIAL INFORMATION
<TABLE>
<CAPTION>

         Item 1.  Financial Statements

                                      ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
                                         CONDENSED CONSOLIDATED BALANCE SHEETS

                                                         ASSETS


                                                                             September 30,            June 30,
                                                                                 2005                   2005
                                                                                 ----                   ----
Current Assets:

<S>                                                                           <C>                   <C>
Cash and cash equivalents, including $3,410,281 and
$2,812,971 of invested cashat September 30, 2005 and
June 30, 2005 respectively ..........................................        $  3,658,625           $  3,430,146
Accounts & trade receivables ........................................             791,211                614,720
Accounts receivable, related party ..................................              36,845                 13,000
Prepaid expenses.....................................................              13,088                 15,422
Precious metals .....................................................              18,823                 18,823
                                                                             ------------           ------------

     Total current assets ...........................................           4,518,592              4,092,111
                                                                             ------------           ------------

Investment in oil and gas properties, at cost (full cost method of
accounting) .........................................................          10,799,378              9,670,383

Less accumulated depletion and valuation allowance ..................          (4,837,090)            (4,587,090)
                                                                             ------------           ------------
                                                                                5,962,288              5,083,293
                                                                             ------------           ------------
Property and equipment, at cost:
Furniture, fixtures and vehicles ....................................             114,076                154,819
Less accumulated depreciation .......................................             (39,637)               (74,044)
                                                                             ------------           ------------
                                                                                   74,439                 80,775
                                                                             ------------           ------------
     TOTAL ASSETS ...................................................        $ 10,555,319           $  9,256,179
                                                                             ============           ============

                              (Statement Continues)
                 See notes to Consolidated Financial Statements

                                       3
<PAGE>


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

                                      LIABILITIES AND STOCKHOLDERS' EQUITY


                                                                               September 30,           June 30,
                                                                                   2005                   2005
                                                                                   ----                   ----
Current liabilities:

Accounts payable and accrued expenses .................................        $    977,105            $    655,190
Accounts payable - related party (Note 6) .............................              73,767                 103,233
Advances from joint interest owners ...................................           1,035,221                 710,477
Asset retirement obligation (Note 3) ..................................              13,826                  13,826
                                                                               ------------            ------------

Total current liabilities                                                         2,099,919               1,482,726
                                                                               ------------            ------------
Asset retirement obligation, net of current portion (Note 3) ..........             108,384                  82,384
Deferred income taxes (Note 9) ........................................           1,195,883               1,015,488
                                                                               ------------            ------------
Total long term liabilities ...........................................           1,304,267               1,097,872
                                                                               ------------            ------------
Total liabilities .....................................................           3,404,186               2,580,598
                                                                               ------------            ------------
Stockholders' equity:
(Notes 1 and 5):
Common stock, $.005 par value:
    Authorized: 50,000,000 shares
    Issued and outstanding: At September 30, 2005,
    6,758,308 shares and June 30, 2005, 6,733,308 .....................              33,791                  33,666

Capital in excess of par value ........................................           6,742,446               6,728,321
Accumulated retained earnings (deficit) ...............................             392,133                 (69,169)
Deferred compensation .................................................             (17,237)                (17,237)
                                                                               ------------            ------------
Total stockholders' equity ............................................           7,151,133               6,675,581
                                                                               ------------            ------------
Total liabilities and stockholders' equity ............................        $ 10,555,319            $  9,256,179
                                                                               ============            ============

                                   See Notes to Consolidated Financial Statements

                                                       4
<PAGE>


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


                                                                                       Three Months Ended
                                                                                          September 30,

                                                                                  2005                    2004
                                                                                  ----                    ----
Revenues:
  Oil and gas ....................................................             $1,062,543               $  697,553
  Management fees ................................................                120,924                   82,057
                                                                               ----------               ----------
Total Revenues ...................................................              1,183,467                  779,610
                                                                               ----------               ----------

Costs and expenses:
  Oil and gas production .........................................                 71,019                   64,361
  Depreciation, depletion and amortization .......................                254,336                  156,000
  Selling, general and administrative ............................                227,116                  171,104
                                                                               ----------               ----------
Total Costs and Expenses .........................................                552,471                  391,735
                                                                               ----------               ----------
Operating income .................................................                630,996                  387,875
Other income (expense)
  Interest and other, net ........................................                 10,701                    4,689
  Interest (expense) .............................................                      0                   (3,053)
                                                                               ----------               ----------
Income before taxes ..............................................                641,697                  389,781
Provision for income taxes .......................................                180,395                  168,163
                                                                               ----------               ----------
Net income .......................................................             $  461,302               $  221,618
                                                                               ==========               ==========
Basic income per common share ....................................             $      .07               $      .04
                                                                               ==========               ==========
Diluted income per common share ..................................             $      .06               $      .04
                                                                               ==========               ==========
Basic weighted average number of common shares
outstanding
                                                                                6,745,808                6,235,824
                                                                               ==========               ==========
Diluted weighted average number of common shares
outstanding
                                                                                7,163,243                6,421,889
                                                                               ==========               ==========

                              The accompanying notes are an integral part of these statements.

                                                             5
<PAGE>


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


                                                                                   Three months ended September 30,
                                                                                    2005                  2004
                                                                                -----------            -----------
Cash flows from operating activities:

Net income ............................................................         $   461,302            $   221,618

Adjustments to reconcile net income to net cash
provided used by operating activities:

  Depreciation, depletion and amortization ............................             254,336                156,000
  Stock issued for interest expense ...................................                --                      500
  Deferred income tax provision .......................................             180,395                168,163

Changes in assets and liabilities:

  (Increase) in receivable ............................................            (200,336)               (65,267)
  Decrease in prepaid expense .........................................               2,334                  6,705
  Increase (decrease) in accounts payable and accrued expense .........             617,193               (143,242)
                                                                                -----------            -----------
  Net cash provided by operating activities ...........................           1,315,224                344,477
                                                                                -----------            -----------

Cash flows from investing activities:

  Additions to oil and gas properties .................................          (1,102,995)              (467,629)
  Purchase of producing properties ....................................                --                  (60,520)
  Equipment inventory sales ...........................................               2,000                   --
                                                                                -----------            -----------

  Net cash (used) by investing activities .............................          (1,100,995)              (528,149)
                                                                                -----------            -----------

Cash flow from financing activities:

  Common stock options exercised ......................................              14,250                   --
  Payment of notes payable ............................................                --                  (37,500)
                                                                                -----------            -----------
                                                                                     14,250                (37,500)
                                                                                -----------            -----------

  Net increase (decrease) in cash and cash equivalents ................             228,479               (221,172)

  Cash and cash equivalents, beginning of year ........................           3,430,146              1,329,376
                                                                                -----------            -----------

  Cash and cash equivalents, end of year ..............................         $ 3,658,625            $ 1,108,204
                                                                                ===========            ===========

Other information
  Interest paid .......................................................         $      -0-              $     3,053
                                                                                ===========            ===========

 Non-cash transactions additions to asset retirement obligation .......         $    26,000            $      --
                                                                                ===========            ===========

                            The accompanying notes are an integral part of these statements.

                                                           6
</TABLE>

<PAGE>


                          ASPEN EXPLORATION CORPORATION

              Notes to Condensed Consolidated Financial Statements
                                   (Unaudited)

                               September 30, 2005


Note 1   BASIS OF PRESENTATION

     The accompanying financial statements are unaudited. However, in our
     opinion, the accompanying financial statements reflect all adjustments,
     consisting of only normal recurring adjustments, necessary for fair
     presentation. Interim results of operations are not necessarily indicative
     of results for subsequent interim periods or the remainder of the year.
     These financial statements should be read in conjunction with our Annual
     Report on Form 10-KSB for the year ended June 30, 2005.

     Except for the historical information contained in this Form 10-QSB, this
     Form contains forward-looking statements that involve risks and
     uncertainties. Our actual results could differ materially from those
     discussed in this Report. Factors that could cause or contribute to such
     differences include, but are not limited to, those discussed in this Report
     and any documents incorporated herein by reference, as well as the Annual
     Report on Form 10-KSB for the year ended June 30, 2005.


Note 2   RECEIVABLE - RELATED PARTIES

     The receivable from related parties constitutes amounts due from officers
     and consultants for joint operating costs of wells operated by us. The
     transactions are in the normal course of business and provide for the same
     terms as other unaffiliated joint owners and are repaid in a normal
     business cycle.


Note 3   ASSET RETIREMENT OBLIGATION

     We have adopted the provisions of Statement of Financial Accounting
     Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations."
     SFAS No. 143 generally applies to legal obligations associated with the
     retirement of long-lived assets that result from the acquisition,
     construction, development and/or the normal operation of a long-lived
     asset. SFAS No. 143 requires us to recognize an estimated liability for the
     plugging and abandonment of our gas wells. We have recognized the future
     cost to plug and abandon the gas wells over the estimated useful lives of
     the wells in accordance with SFAS No. 143. A liability for the fair value
     of an asset retirement obligation with a corresponding increase in the
     carrying value of the related long-lived asset is recorded at the time a
     producing well is purchased or a drilled well is completed and ready for
     production. We will amortize the amount added to the oil and gas properties
     and recognize accretion expense in connection with the discounted liability
     over the remaining life of the respective well. The estimated liability is
     based on historical experience in plugging and abandoning wells, estimated
     useful lives based on engineering studies, external estimates as to the
     cost to plug and abandon wells in the future and federal and state
     regulatory requirements. The liability is a discounted liability using

                                       7
<PAGE>



Note 3   ASSET RETIREMENT OBLIGATION (CONTINUED)

     a credit adjusted risk-free rate of 6%. Revisions to the liability could
     occur due to changes in plugging and abandonment costs, useful well lives
     or if federal or state regulators enact new regulations on the plugging and
     abandonment of wells.

     A reconciliation of our liability for the year ended September 30, 2005 is
     as follows:

                  Asset retirement obligations as of
                  June 30, 2005                               $  96,210
                  ARO additions                                  26,000
                  Liabilities settled                               -0-
                  Accretion expense                                 -0-*
                  Revision of estimate                              -0-
                                                              ---------
                  Asset retirement obligation as of
                  September 30, 2005                          $ 122,210
                                                              =========

                  * Accretion not material


Note 4   EARNINGS PER SHARE

     We follow SFAS No. 128, addressing earnings per share. SFAS No. 128
     established the methodology of calculating basic earnings per share and
     diluted earnings per share. The calculations differ by adding any
     instruments convertible to common stock (such as stock options, warrants,
     and convertible preferred stock) to weighted average shares outstanding
     when computing diluted earnings per share.

     The following is a reconciliation of the numerators and denominators used
     in the calculations of basic and diluted earnings per share. We had a net
     income of $461,302 for the three months ended September 30, 2005 and
     $221,618 for the three months ended September 30, 2004.

<TABLE>
<CAPTION>

                                                                     Three Months Ended
                                             September 30, 2005                              September 30, 2004
                                     ----------------------------------     -----------------------------------------

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

<S>                                  <C>              <C>           <C>      <C>           <C>                 <C>
Basic earnings per share:

Net income and share amounts          $  461,302    6,745,808    $   .07    $  221,618     6,235,824         $   .04

Dilutive securities:
stock options                               --        527,000        --                      392,000

Repurchased shares                          --       (109,565)       --                     (205,935)
                                      -------------------------------------------------------------------------------
Diluted earnings per share:

Net income and assumed  share
conversion                            $  461,302     7,163,243    $   .06    $ 221,618     6,421,889          $   .04
                                      ==========    ==========    =======    =========     =========          ========
</TABLE>

                                                              8
<PAGE>

Note 5   STOCKHOLDERS' EQUITY

     Stock Options
     -------------

     On August 15, 2005, a consultant exercised options for 25,000 shares of our
     common stock granted March 14, 2002 at an average price of $0.57 per share.
     The consultant paid us $14,250 to exercise his options on the 25,000
     shares.

     As of September 30, 2005, we had an aggregate of 527,000 common shares
     reserved for issuance under our stock option plans. These plans provide for
     the issuance of common shares pursuant to stock option exercises,
     restricted stock awards and other equity based awards.

     The following information summarizes information with respect to options
     granted under our equity plans:
<TABLE>
<CAPTION>

                                                              Number of         Weighted Average Exercise
                                                              Shares            Price of Shares Under Plans
                                                              ------            ---------------------------

<S>                                                           <C>                      <C>
         Outstanding balance June 30, 2005                     552,000                  $1.559
                                                                                        ======

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

         Exercised                                             (25,000)                    .57
                                                                                        ======

         Forfeited or expensed                                     -0-                      --
                                                                                        ======
                                                              -------

         Outstanding balance September 30, 2005                527,000                  $1.606
                                                              ========                  ======

         The following table summarizes information concerning outstanding and
         exercisable options as of September 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    117,000           08/15/2006(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
                  -------

                  527,000
</TABLE>

     (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

                                       9
<PAGE>


Note 5   STOCKHOLDERS' EQUITY (CONTINUED)

     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 6            MAJOR CUSTOMERS

     We derived in excess of 10% of our revenue from various sources (oil and
     gas sales) as follows:

                                                  The Company
                                                  -----------

                                      A           B                 C       D
                                      -           -                 -       -
         Quarter ended:

         September 30, 2005           46%         40%               *       11%
         September 30, 2004           26%         55%               11%     *

         * Less than 10%.


Note 7   INCOME TAXES

     We have recorded a deferred income tax liability of $1,195,883 as of
     September 30, 2005. During the first quarter of 2005, we used no net
     operating loss carryforwards leaving approximately $164,000 in available
     federal net operating loss carryforwards as of September 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.

                                       10
<PAGE>


Note 7   INCOME TAXES (CONTINUED)

     At September 30, the income tax effect of temporary differences comprising
     the deferred tax assets and deferred tax liabilities on the accompanying
     balance sheet is the result of the following:

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

  Federal tax loss
    carryforwards                                                   $   149,133
  Asset retirement obligation                                            10,999
                                                                    -----------

                                                                        160,132

Deferred tax (liabilities):

  Property, plant and equipment                                             277
  Oil and gas properties                                             (1,356,292)
                                                                    -----------

                                                                     (1,356,015)
                                                                    -----------
                                                                    $(1,195,883)

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

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

Less:  Net operating losses and
          Future deductions                         (15)%
                                                   ----

Net federal income tax rate                          19%

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


Effective rate                                       28%
                                                    ====

                                       11
<PAGE>


Note 7            INCOME TAXES (CONTINUED)

         The provision for income taxes consists of the following components:

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

Current tax expense, state                             $   --           $   --

Deferred tax expense                                    180,395          168,163
                                                       --------         --------

Total income tax provision                             $180,395         $168,163
                                                       ========         ========

     We have available federal net operating loss carryforwards of approximately
     $164,000 (net operating losses expire beginning June 30, 2023 through the
     year ending June 30, 2026).


Note 8   DRILLING COMMITMENTS AND CONTINGENCIES

     We have a proposed drilling budget for the period October through December
     2005. The budget includes drilling four 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:

<TABLE>
<CAPTION>

                                                                                           Completion &
                    Area                       Wells            Drilling Costs           Equipping Costs             Total
      ----------------------------------    ------------     ---------------------    -----------------------    --------------

<S>                                              <C>                     <C>                         <C>              <C>
      Denverton Creek Field,                     1                       $170,000                    $76,000          $246,000
      Solano County, CA

      West Grimes Field                          1                        139,000                     86,000           225,000
      Colusa County,
      CA

      Buckeye, Colusa                            1                        165,000                    132,000           297,000
      County, CA

      Winters, Yolo                              1                         85,000                     81,000           166,000
      County, CA
                                            ------------     ---------------------    -----------------------    --------------

      Total Expenditure                          4                       $559,000                   $375,000          $934,000
                                            ============     =====================    =======================    ==============
</TABLE>

                                       12

<PAGE>


Note 9   SUBSEQUENT EVENTS

     The Kalfsbeek #1-13 well located in the Buckeye Gas Field, Colusa County,
     California, was drilled to a depth of 8,800 feet and encountered
     approximately 90 feet of potential gas pay in several intervals in the
     Forbes formation. Production casing was run based on favorable mud log and
     electric log responses. Several of these Forbes intervals were perforated
     and tested gas at a stabilized rate of 2,909 MCFPD with a flowing tubing
     pressure of 2,005 psig and a flowing casing pressure of 2,080 psig. The
     shut in tubing and casing pressures were 3,250 psig. Aspen has a 30.625%
     operated working interest in this well.

     The WGU #15-10 well located in the West Grimes Gas Field, Colusa County,
     California, was directionally drilled to a depth of 8,520 feet (7,975 feet
     TVD) and encountered approximately 100 feet of potential 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% operated
     working interest in this well.

     The Street #1-3 well located in the Dry Slough Gas Field, Yolo County,
     California, was directionally drilled to a depth of 6,450 feet (5,563 feet
     TVD) and encountered approximately 45 feet of potential gas pay in several
     intervals in the Starkey and Winters formations. Production casing was run
     based on favorable mud log and electric log responses. The well will be
     completed in the near future. Aspen has a 21.875% operated working interest
     in this well.


                                       13
<PAGE>


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

     This segment should be read in conjunction with the management's discussion
and analysis of financial condition and results of operations contained in our
Annual Report on Form 10-KSB for the year ended June 30, 2005, which has been
filed with the Securities and Exchange Commission. The management discussion and
analysis and other portions of this report contain forward-looking statements
(as such term is defined in Section 21E of the Securities Exchange Act of 1934,
as amended). These statements reflect our current expectations regarding our
possible future results of operations, performance, and achievements. These
forward-looking statements are made pursuant to the safe harbor provisions of
the Private Securities Litigation Reform Act of 1995.

     Wherever possible, we have tried to identify these forward-looking
statements by using words such as "anticipate," "believe," "estimate," "expect,"
"plan," "intend," and similar expressions. These statements reflect our current
beliefs and are based on information currently available to us. Accordingly,
these statements are subject to certain risks, uncertainties, and contingencies,
which could cause our actual results, performance, or achievements to differ
materially from those expressed in, or implied by, such statements. These risks,
uncertainties and contingencies include, without limitation, the factors set
forth in our Form 10-KSB under "Item 6. Management's Discussion and Analysis of
Financial Conditions or Plan of Operation - Factors that may affect future
operating results." We have no obligation to update or revise any such
forward-looking statements that may be made to reflect events or circumstances
after the date of this Form 10-QSB.

Overview
--------

     Aspen Exploration Corporation was organized in 1980 for the purpose of
acquiring, exploring and developing oil and gas and other mineral properties.
Since 1996, we have focused our efforts on the exploration, development and
operation of natural gas properties in the Sacramento Valley of northern
California. We are currently the operator of 51 gas wells and have a
non-operated interest in 15 additional gas wells.

     We currently have offices in Bakersfield, California and Denver, Colorado
and have 2 full time employees as well as the Chairman of the Board who
allocates a portion of his time to the Company. We also make extensive use of
consultants for the conduct of our business, ranging from financial,
engineering, land, legal, and geological and geophysical specialists. Our goal
is to identify low to moderate risk wells with good gas reserve potential.

     Where possible, we attempt to be the operator of each property we invest
in. Our knowledge of drilling and operating wells in the Sacramento Valley
allows us to maximize the potential return of each property. Administrative
charges to the properties help cover approximately 53% of our selling, general
and administrative expenses.

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 gas price for our product will be in the range of $7.00
to $13.00 per MMBTU for the fiscal year ended June 30, 2006 as compared to the
gas price of $6.20 during our 2005 fiscal year.

                                       14

<PAGE>


     Over the past five years we have been able to replace the majority of our
produced reserves and increase our yearly natural gas production. We have also
benefited from a general increase in natural gas prices over the past two years,
from a low of $2.78 per MMBTU average during the first quarter of fiscal 2003 to
$7.26 per MMBTU for the quarter ended September 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 five years has been 88%. With the use
of 3-D seismic and well control data, interpreted by our geological and
geophysical consultants, we feel we can manage our dry hole risk as well as
anyone in the industry.

     Commodity prices are impacted by many factors that are outside of our
control. Historically, commodity prices have been volatile and we expect them to
remain volatile. Commodity prices are affected by changes in market demands,
overall economic activity, weather, pipeline capacity constraints, inventory
storage levels, basis differentials and other factors. As a result, we cannot
accurately predict future natural gas and NGL (natural gas liquids) prices, and
therefore, we cannot determine what effect increases or decreases in production
volumes will have on future revenues.

     On regulatory and operational matters, we actively manage our exploration
and production activities. We value sound stewardship and strong relationships
with all stakeholders in conducting our business. We attempt to stay abreast of
emerging issues to effectively anticipate and manage potential impacts to our
operations.

     To manage commercial risk, we may use financial tools to hedge the price we
will receive for our product. The primary purpose of hedging is to provide
adequate return on our investments, grow our reserves while leaving as much
commodity price upside as possible. During the period November 1, 2005 through
March 31, 2006, we are contractually obligated to deliver 3,750 MMBTU per day to
two of our natural gas purchasers as follows:

         1,000 MMBTU/Day @ $8.43 per MMBTU
         1,000 MMBTU/Day @ $8.40 per MMBTU
            500 MMBTU/Day @ $9.49 per MMBTU
            500 MMBTU/Day @ $9.48 per MMBTU
            750 MMBTU/Day @ $11.02 per MMBTU

The average price received during the first quarter of fiscal 2006 for our
natural gas was approximately $7.21 per MMBTU.

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

     We have historically financed our operations with internally generated
funds and limited borrowings from banks and third parties, and farmout
arrangements, which permit third parties (including some related parties) to
participate in our drilling prospects. Our principal uses of cash are for
operating expenses, the acquisition, drilling, completion and production of
prospects, the acquisition of producing properties, working capital, servicing
debt and the payment of income taxes.

                                       15

<PAGE>


     Cash of $1,315,224 and $344,477 was provided by our operations for the
three months ended September 30, 2005 and 2004. The 2005 period generated net
income of $461,302, and we were able to generate increased positive cash flow
from operations during the first three months of fiscal 2005 as compared to the
2004 period (when we generated net income of $221,618) because of:

         An increase in oil and gas sales (52%) due to increased volumes sold
         (13%) and the price received for our gas (37%); and

         An increase in accounts payable and accrued expenses of $617,193 in
         2005 (which conserved cash) compared to a decrease in accounts payable
         and accrued expenses of $143,242 (which used cash during the 2004
         period); and

         These changes were offset by increased depletion, depreciation and
         amortization expense of $254,336 in 2005 compared to $156,000 in 2004.

     Investing activities used cash to increase net capitalized oil and gas
costs of $1,100,995 and $528,149 in the three months ended September 30, 2005
and 2004. Cash in the current three month period ended September 30, 2005 was
used for lease acquisition, seismic work, intangible drilling and well workovers
($878,875), and the purchase of oil and gas well equipment ($222,120). These
expenditures are net of the sale of interests in wells to be drilled charged to
third party investors.

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

                                                                                           Completion &
                    Area                       Wells            Drilling Costs           Equipping Costs             Total
      ----------------------------------    ------------     ---------------------    -----------------------    --------------

<S>                                              <C>                     <C>                         <C>              <C>
      Denverton Creek Field,                     1                       $170,000                    $76,000          $246,000
      Solano County, CA

      West Grimes Field                          1                        139,000                     86,000           225,000
      Colusa County,
      CA

      Buckeye, Colusa                            1                        165,000                    132,000           297,000
      County, CA

      Winters, Yolo                              1                         85,000                     81,000           166,000
      County, CA
                                            ------------     ---------------------    -----------------------    --------------

      Total Expenditure                          4                       $559,000                   $375,000          $934,000
                                            ============     =====================    =======================    ==============
</TABLE>

     Our working capital (current assets less current liabilities) at September
30, 2005, was $2,418,673, which reflects an approximate $190,700 decrease from
our working capital at June 30, 2005. Our working capital declined by 7.3%
during the first quarter of our 2005 fiscal year because of an increase in
advances from joint owners of $325,000 that were not expended for drilling

                                       16

<PAGE>


projects at September 30, 2005, and an increase in accounts payable of $293,000.
These increases were offset somewhat by the increase in cash and accounts
receivable of $429,000. We anticipate that our working capital and anticipated
cash flow from operations and future successful drilling will be sufficient to
pay our current liabilities. Based on national and international concerns, we
anticipate that our gas production will continue to provide us with sufficient
cash flow through our current fiscal year and beyond. As discussed 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
the majority of our drilling program is usually carried out in California's dry
season, from late April until November, after which wet weather either precludes
further activity or makes it cost prohibitive.

     We believe that internally generated funds will be sufficient to finance
our drilling and operating expenses for the next twelve months. If our drilling
efforts are successful, the anticipated increased cash flow from the new gas
discoveries, in addition to our existing cash flow, should be sufficient to fund
our share of planned future completion and pipeline costs.


                                       17
<PAGE>


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

September 30, 2005 Compared to September 30, 2004
-------------------------------------------------

For the three months ended September 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 approximately $410,000 as compared to the
comparable period of our 2004 fiscal year because of:

         Increased production (146,400 MMBTU sold as compared to 130,000 MMBTU
         sold during the first three months of our 2004 fiscal year);

         Increased price received for our production (an average of $7.26 per
         MMBTU during the first three months of our 2006 fiscal year as compared
         to $5.31 per MMBTU received during that period in 2005); and

         Increased management fees received ($120,900 during fiscal 2006 as
         compared to $82,100 during fiscal 2005) because we were operators of
         more wells during 2006 (51 wells compared to 48 wells in 2005).


                                       18
<PAGE>


The following table sets forth certain items from our Condensed Consolidated
Statements of Operations as expressed as a percentage of total revenues, shown
by quarter for the three months of fiscal 2005, 2004, 2003 and 2002:
<TABLE>
<CAPTION>

                                                          For the Three Months Ended
                                              ------------ ------------ ------------- ------------
                                                9/30/05     9/30/2004    9/30/2003     9/30/2002
                                              ------------ ------------ ------------- ------------

<S>                                                <C>          <C>           <C>          <C>
Total revenues                                     100.0%       100.0%        100.0%       100.0%

Oil & gas production costs                            5.9          8.2          10.1         14.3
                                              ------------ ------------ ------------- ------------
Income from operations                               94.1         91.8          89.9         85.7
                                              ------------ ------------ ------------- ------------

Costs and expenses
  Depreciation and depletion                         21.3         19.9          32.9         32.2
  Selling, general and administrative                19.0         21.8          44.1         70.1
  Interest expense                                     .0           .3            .0           .0
                                              ------------ ------------ ------------- ------------
Total costs and expenses                             40.3         42.0          77.0        102.3
                                              ------------ ------------ ------------- ------------

Income before income taxes                           53.8         49.8          12.9       (16.6)

Provision for income taxes                           15.1         21.4            .0           .0

                                               ------------ ------------ ------------- ------------
Net income (loss)                                    38.7         28.4          12.9       (16.6)
                                              ============ ============ ============= ============


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


                                                      Comparison of the Fiscal
                                                  Three Months Ended September 30,            Increase (Decrease)
                                              ---------------------------------------- --------------------------------
                                                      2005                2004              Amount        Percentage
                                              ------------------- -------------------- --------------- ----------------
       Revenues:
       Oil and gas sales                              $1,062,543             $697,553       $ 364,990         52%
       Management fees                                   120,924               82,057          38,867          47
       Interest and other                                 10,701                4,689           6,012         128
                                               ------------------- -------------------- --------------- ---------------
         Total revenues                                1,194,168              784,299         409,869          52
                                               ------------------- -------------------- --------------- ---------------

       Cost and expenses:
       Oil and gas production                             71,019               64,361           6,658          10
       Depreciation and depletion                        254,336              156,000          98,336          63
       Selling, general and administrative               227,116              171,104          56,012          33
       Interest expense                                        0                3,053          (3,053)       (100)
                                               ------------------- -------------------- --------------- ---------------
          Total costs and expenses                       552,471              394,518         157,953          40
                                               ------------------- -------------------- --------------- ---------------

       Income before taxes                               641,697              389,781
       Provision for income taxes                        180,395              168,163
                                              ------------------- -------------------
       Net income                                       $461,302             $221,618
                                              =================== ===================
</TABLE>

                                       19

<PAGE>


Central to the issue of success of the three months operations ended September
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:
<TABLE>
<CAPTION>

                                            Oil & Gas           MMBTU                 (1)
                                              Sales              Sold             Price/MMBTU
                                          --------------    ---------------    ------------------
         2006
         ----------------------------
<S>                                          <C>                   <C>                     <C>
         lst Quarter                         $1,062,543            146,445                 $7.26
                                          --------------    ---------------    ------------------

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

         First Quarter change
          ----------------------------
         2006
         ----------------------------
         Amount                                $364,990             16,445                 $1.95
         Percentage                                 52%                13%                   37%
         2005
         ----------------------------
         Amount                                $355,627             57,400                  $.56
         Percentage                                104%                79%                   12%
</TABLE>


(1) Price per MMBTU may not agree with oil and gas sales because of the
inclusion of oil and NGL sales.

Oil and gas revenue, volumes sold and price received for our product have shown
a steady improvement over the first three months of fiscal 2006 and during the
twelve months of fiscal 2005. As the table above notes, revenue has increased
approximately 52% when comparing the three month periods ended September 30,
2005 and 2004. Volumes sold increased approximately 13%, while the price
received for our product increased 37%.

Total revenue increased $365,000, or 52% when comparing the two periods, while
operating and production costs increased $6,660, or 10%. Our results during the
current period were favorable in part because we were able to keep increases in
our production costs significantly less than the increases in prices received
for natural gas. The 10% increase in production costs is even less than the 13%
increase in volumes produced.

A significant ratio presented is the percentage of management fees charged to
operated wells versus our general and administrative costs. This coverage of

                                       20

<PAGE>


general and administrative costs improved from approximately 48% for the three
months ended September 30, 2004 to approximately 53% at September 30, 2005.

When comparing general and administrative expense for 2006 and 2005, costs
increased approximately $56,000, or 33%, primarily because of increases in
promotion and advertising ($24,000), accounting and audit fees ($13,000), legal
fees, medical insurance, corporate reporting and consulting fees and other
($19,000).

Results of operations and net income are presented in the following table:
<TABLE>
<CAPTION>

                                           Quarterly Financial Information (unaudited)
                                                                                                         Income (loss)
                                                        (1)                      (2)                  Before Income Taxes
                                     Total           Operating              Income (loss)                  Per Share
                                    Revenues           Income            Before Income Taxes        Basic          Diluted
                                 ---------------    -------------      ------------------------    ---------     -------------
    2006
    ------------------------     ---------------    -------------      ------------------------    ---------     -------------
<S>                                  <C>              <C>                             <C>             <C>               <C>
    lst Quarter                      $1,194,168       $1,112,448                      $641,697        $.095             $.090
                                 ---------------    -------------      ------------------------    ---------     -------------

    2005
    ------------------------
    1st 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.
(2) Before provision for deferred income taxes.

As can be seen in the table, revenues and operating income have improved in
every quarter when comparing the three month periods ended September 30, 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.

                                       21

<PAGE>


Contractual Obligations:
------------------------

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

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

Employment Obligations                       $222,200          $468,200           $87,200               $-0-            $777,600

Contract Services                              30,000               -0-               -0-                -0-              30,000
Obligations

Operating Leases                                9,500             1,600               -0-                -0-              11,100
                                       ---------------    --------------    --------------    ---------------     ---------------

Total contractual
  cash obligations                           $261,700          $469,800           $87,200               $-0-            $818,700
                                       ===============    ==============    ==============    ===============     ===============
</TABLE>

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 on the Denver
office at a lease rate of $1,261 per month. The Bakersfield, California office
has 546 square feet and a monthly rental fee of $730 to $770 over the term of
the lease. The three year lease expires February 8, 2006. Rent expense for the
three months ended September 30, 2005 and 2004 was $6,163 and $6,033,
respectively.

Critical Accounting Policies and Estimates:
-------------------------------------------

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

Reserve Estimates:
------------------

Our estimates of oil and natural gas reserves, by necessity, are projections
based on geologic and engineering data, and there are uncertainties inherent in
the interpretation of such data as well as the projection of future rates of
production and the timing of development expenditures. Reserve engineering is a
subjective process of estimating underground accumulations of oil and natural
gas that are difficult to measure. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological
interpretation and judgment. Estimates of economically recoverable oil and
natural gas reserves and future net cash flows necessarily depend upon a number
of variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects of
regulations by governmental agencies and assumptions governing future oil and
natural gas prices, future operating costs, severance and excise taxes,
development costs and workover and remedial costs, all of which may in fact vary
considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of oil and natural gas attributable to any

                                       22

<PAGE>


particular group of properties, classifications of such reserves based on risk
of recovery, and estimates of the future net cash flows expected therefrom may
vary substantially. Any significant variance in the assumptions could materially
affect the estimated quantity and value of the reserves, which could affect the
carrying value of our oil and gas properties and/or the rate of depletion of the
oil and gas properties. Actual production, revenues and expenditures with
respect to our reserves will likely vary from estimates, and such variances may
be material.

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

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

Accounts Receivable:
--------------------

Accounts receivable balances are evaluated on a continual basis and allowances
are provided for potentially uncollectable accounts based on management's
estimate of the collectability of customer accounts. If the financial condition
of a customer were to deteriorate, resulting in an impairment of its ability to
make payments, an additional allowance may be required. Allowance adjustments
are charged to operations in the period in which the facts that give rise to the
adjustments become known.

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

We follow the full-cost method of accounting for oil and gas properties. Under
this method, all productive and nonproductive costs incurred in connection with
the exploration for and development of oil and gas reserves are capitalized.
Such capitalized costs include lease acquisition, geological and geophysical
work, delay rentals, drilling, completing and equipping oil and gas wells,
including salaries, benefits and other internal salary related costs directly
attributable to these activities. Costs associated with production and general
corporate activities are expensed in the period incurred. Interest costs related
to unproved properties and properties under development are also capitalized to
oil and gas properties. If the net investment in oil and gas properties exceeds
an amount equal to the sum of (1) the standardized measure of discounted future
net cash flows from proved reserves, and (2) the lower of cost or fair market
value of properties in process of development and unexplored acreage, the excess
is charged to expense as additional depletion. Normal dispositions of oil and
gas properties are accounted for as adjustments of capitalized costs, with no
gain or loss recognized.

We apply SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets." Under SFAS No. 144, long-lived assets and certain intangibles are
reported at the lower of the carrying amount or their estimated recoverable
amounts. Long-lived assets subject to the requirements of SFAS No. 144 are
evaluated for possible impairment through review of undiscounted expected future
cash flows. If the sum of undiscounted expected future cash flows is less than
the carrying amount of the asset or if changes in facts and circumstances
indicate, an impairment loss is recognized.

Asset retirement obligations:
-----------------------------

We recognize the future cost to plug and abandon gas wells over the estimated
useful life of the wells in accordance with the provision of SFAS No. 143. SFAS
No. 143 requires that we record a liability for the present value of the asset
retirement obligation with a corresponding increase to the carrying value of the
related long-lived asset. We amortize the amount added to the oil and gas

                                       23

<PAGE>


properties and recognize accretion expense in connection with the discounted
liability over the remaining lives of the respective gas wells. Our liability
estimate is based on our historical experience in plugging and abandoning gas
wells, estimated well lives based on engineering studies, external estimates as
to the cost to plug and abandon wells in the future and federal and state
regulatory requirements. The liability is discounted using a credit-adjusted
risk-free rate of 6%. Revisions to the liability could occur due to changes in
well lives, or if federal and state regulators enact new requirements on the
plugging and abandonment of gas wells.


                                       24
<PAGE>


Item 3.  CONTROLS AND PROCEDURES

     As required by Rule 13a-15 under the Securities Exchange Act of 1934, as of
the filing date of this report, we carried out an evaluation of the
effectiveness of the design and operation of our disclosure controls and
procedures. This evaluation was carried out under the supervision and with the
participation of our principal executive officer (who is also our principal
financial officer), who concluded that our disclosure controls and procedures
are effective. There have been no significant changes in our internal controls
or in other factors, which could significantly affect internal controls
subsequent to the date we carried out our evaluation.

     Disclosure controls and procedures are controls and other procedures that
are designed to ensure that information required to be disclosed in our reports
filed or submitted under the Securities Exchange Act is recorded, processed,
summarized and reported, within the time periods specified in the Securities and
Exchange Commission's rules and forms. Disclosure controls and procedures
include, without limitation, controls and procedures designed to ensure that
information required to be disclosed in our reports filed under the Exchange Act
is accumulated and communicated to management, including our principal executive
officer and our principal financial officer, as appropriate, to allow timely
decisions regarding required disclosure.


PART II

Item 1.  Legal Proceedings.
         -----------------

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

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds.
         ----------------------------------------------------------
     None during the period

Item 3.           Defaults Upon Senior Securities.

     None.

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

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

Item 5.  Other Information.
         -----------------
     None.

Item 6.  Exhibits.
         --------

31.      Rule 13a-14(a) Certification
32.      Section 1350 Certification

                                       25

<PAGE>


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

                                    ASPEN EXPLORATION CORPORATION



                                    /s/ Robert A. Cohan
                                    --------------------------------------------
                                    By:  Robert A. Cohan,
November 10, 2005                  Chief Executive Officer,
                                    Principal Financial Officer

                                       26