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 December 31, 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 Aspen Exploration Corporation is a shell company
(as defined in Rule 12b-2 of the Exchange Act):
Yes [ ] No [ X ]
Indicate the number of shares outstanding of each of the Issuer's classes of
common stock as of the latest practicable date.
Class Outstanding at February 9, 2006
----- -------------------------------
Common stock, $.005 par value 6,776,641
Transitional small business disclosure format: ___ Yes XX No
Part One. FINANCIAL INFORMATION
Item 1. Financial Statements
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, June 30,
2005 2005
------------ ------------
Current Assets:
Cash and cash equivalents, including $2,455,406 and
$2,812,971 of invested cash at December 31, 2005 and
June 30, 2005 respectively ................................ $ 3,370,131 $ 3,430,146
Accounts receivables ...................................... 1,511,881 614,720
Receivable, related party ................................. 38,153 13,000
Prepaid expenses .......................................... 10,283 15,422
Precious metals ........................................... 18,823 18,823
------------ ------------
Total current assets 4,949,271 4,092,111
------------ ------------
Investment in oil and gas properties, at cost (full cost
method of accounting) ..................................... 11,890,506 9,670,383
Less accumulated depletion and valuation allowance ........ (5,087,090) (4,587,090)
------------ ------------
6,803,416 5,083,293
------------ ------------
Property and equipment, at cost:
Furniture, fixtures and vehicles .......................... 122,576 154,819
Less accumulated depreciation ............................. (44,341) (74,044)
------------ ------------
78,235 80,775
------------ ------------
TOTAL ASSETS ......................................... $ 11,830,922 $ 9,256,179
============ ============
(Statement Continues)
See notes to Consolidated Financial Statements
2
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
December 31, June 30,
2005 2005
------------ ------------
Current liabilities:
Accounts payable and accrued expenses ........... $ 1,258,829 $ 655,190
Accounts payable - related party (Note 2) ....... 8,267 103,233
Income taxes payable (Note 7) ................... 209,256 0
Advances from joint interest owners ............. 553,774 710,477
Asset retirement obligation (Note 3) ............ 40,494 13,826
------------ ------------
Total current liabilities ....................... 2,070,620 1,482,726
------------ ------------
Asset retirement obligation, net of current
portion (Note 3) ................................ 81,716 82,384
Deferred income taxes (Note 7) .................. 1,378,286 1,015,488
------------ ------------
Total long term liabilities ..................... 1,460,002 1,097,872
------------ ------------
Total liabilities ............................... 3,530,622 2,580,598
------------ ------------
Stockholders' equity:
(Notes 1 and 5):
Common stock, $.005 par value:
Authorized: 50,000,000 shares
Issued and outstanding: At December 31, 2005,
6,768,308 shares and June 30, 2005, 6,733,308 33,841 33,666
Capital in excess of par value .................. 6,806,396 6,728,321
Retained earnings (deficit) ..................... 1,497,396 (69,169)
Deferred compensation and consulting fees ....... (37,333) (17,237)
------------ ------------
Total stockholders' equity ...................... 8,300,300 6,675,581
------------ ------------
Total liabilities and stockholders' equity ...... $ 11,830,922 $ 9,256,179
============ ============
See Notes to Consolidated Financial Statements
3
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended Six Months Ended
December 31, December 31,
2005 2004 2005 2004
----------- ----------- ----------- -----------
Revenues:
Oil and gas ............................ $ 2,017,233 $ 1,132,359 $ 3,079,776 $ 1,829,912
Management fees ........................ 82,162 59,768 203,086 141,825
----------- ----------- ----------- -----------
Total Revenues ........................... 2,099,395 1,192,127 3,282,862 1,971,737
----------- ----------- ----------- -----------
Costs and expenses:
Oil and gas production ................. 121,151 99,495 192,170 163,856
Depreciation, depletion and amortization 254,704 154,001 509,040 310,001
Selling, general and administrative .... 235,946 205,364 463,062 376,468
----------- ----------- ----------- -----------
Total Costs and Expenses ................. 611,801 458,860 1,164,272 850,325
----------- ----------- ----------- -----------
Operating Income ......................... 1,487,594 733,267 2,118,590 1,121,412
Other income (expense)
Interest and other, net ................ 9,328 (1,794) 20,029 2,895
Interest (expense) ..................... 0 (1,724) 0 (4,778)
----------- ----------- ----------- -----------
Income before taxes ...................... 1,496,922 729,749 2,138,619 1,119,529
Provision for income taxes ............... 391,659 267,674 572,054 435,837
----------- ----------- ----------- -----------
Net income ............................... $ 1,105,263 $ 462,075 $ 1,566,565 $ 683,692
=========== =========== =========== ===========
Basic income per common share ............ $ .16 $ .07 $ .23 $ .11
=========== =========== =========== ===========
Diluted income per common share .......... $ .16 $ .07 $ .22 $ .10
=========== =========== =========== ===========
Basic weighted average number of
common shares outstanding ................ 6,756,351 6,284,788 6,756,351 6,284,788
=========== =========== =========== ===========
Diluted weighted average number of
common shares outstanding ................ 7,125,295 6,576,591 7,125,295 6,576,591
=========== =========== =========== ===========
The accompanying notes are an integral
part of these statements.
4
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six months ended December 31,
2005 2004
----------- -----------
Cash flows from operating activities:
-------------------------------------
Net income ......................................... $ 1,566,565 $ 683,692
Adjustments to reconcile net income to net cash
provided (used) by operating activities:
Depreciation, depletion and amortization ......... 509,040 310,001
Amortization of deferred compensation ............ 43,904 15,082
Deferred income tax provision .................... 572,054 435,837
Changes in assets and liabilities:
Increase in receivable ........................... (922,314) (81,703)
Decrease in prepaid expense ...................... 5,139 7,724
Increase in accounts payable and accrued expense . 351,970 762,109
----------- -----------
Net cash provided by operating activities ........ 2,126,358 2,132,742
----------- -----------
Cash flows from investing activities:
-------------------------------------
Equipment inventory sale ......................... 2,000 0
Additions to oil and gas properties .............. (2,194,123) (1,169,965)
Purchase of producing properties ................. 0 (19,248)
Purchase of furniture and fixtures ............... (8,500) (7,360)
----------- -----------
Net cash (used) by investing activities (2,200,623) (1,196,573)
----------- -----------
Cash flow from financing activities:
------------------------------------
Common stock options exercised ................... 14,250 0
Payment of notes payable ......................... 0 (75,000)
----------- -----------
Net cash provided (used) by financing activities . 14,250 (75,000)
----------- -----------
Net increase/decrease in cash and cash equivalents (60,015) 861,169
Cash and cash equivalents, beginning of year ..... 3,430,146 1,329,376
----------- -----------
Cash and cash equivalents, end of year ........... $ 3,370,131 $ 2,190,545
=========== ===========
Other information:
Interest paid .................................... $ 0 $ 4,778
=========== ===========
Non-cash investing and financing activities
Asset retirement obligation additions ............ $ 26,000 $ 8,000
=========== ===========
Stock issued for deferred consulting services .... $ 64,000 0
=========== ===========
The accompanying notes are an integral
part of these statements.
5
ASPEN EXPLORATION CORPORATION
Notes to Condensed Consolidated Financial Statements
(Unaudited)
December 31, 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, PAYABLE - RELATED PARTIES
The receivable from related parties constitutes amounts due from officers
and consultants for joint operating costs of wells operated by us. The
transactions are in the normal course of business with the same terms as
other joint owners and are repaid in a normal business cycle. The payable
from related parties represents unexpended prepayments made by officers and
consultants on wells operated by us as well as unpaid business expenses due
officers. These transactions are in the normal course of business.
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
6
Note 3 ASSET RETIREMENT OBLIGATION (CONTINUED)
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 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 six months ended December 31,
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
December 31, 2005 $122,210
========
*Accretion not material
Note 4 EARNINGS PER SHARE
We follow Statement of Financial Accounting Standards ("SFAS") No. 128,
addressing earnings per share. SFAS No. 128 established the methodology of
calculating basic earnings per share and diluted earnings per share. The
calculations differ by adding any instruments convertible to common stock
(such as stock options, warrants, and convertible preferred stock) to
weighted average shares outstanding when computing diluted earnings per
share.
The following is a reconciliation of the numerators and denominators used
in the calculations of basic and diluted earnings per share. We had a net
income of $1,566,565 for the six months ended December 31, 2005 and
$683,692 for the six months ended December 31, 2004.
Six Months Ended
December 31, 2005 December 31, 2004
----------------------------------- ---------------------------------
Per Per
Net Share Net Share
Income Shares Amount Income Shares Amount
----------- ----------- ------ ----------- ----------- ------
Basic earnings per share:
Net income and share amounts $ 1,566,565 6,756,351 $ .23 $ 683,692 6,284,788 $ .11
Dilutive securities:
stock options 527,000 392,000
Repurchased shares (158,056) (100,197)
----------- ----------- ------ ----------- ----------- ------
Diluted earnings per share:
Net income and assumed share
conversion $ 1,566,565 7,125,295 $ .22 $ 683,692 6,576,591 $ .10
=========== =========== ===== =========== =========== =====
7
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 December 31, 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:
Number of Weighted Average Exercise
Shares Price of Shares Under Plans
------ ---------------------------
Outstanding balance June 30, 2005 552,000 $ 1.559
=======
Granted -0- --
=======
Exercised (25,000) .57
=======
Forfeited or expensed -0- --
=======
--------
Outstanding balance December 31, 2005 527,000 $ 1.606
======== =======
The following table summarizes information concerning outstanding and
exercisable options as of December 31, 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
=======
(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.
We have adopted SFAS Standards No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure" - an amendment of FASB Statement
No. 123. SFAS No. 148 amends No. SFAS 123, "Accounting for Stock-Based
Compensation" to provide alternative methods of transition for a voluntary
change to the fair value based method of accounting for stock-based
employee compensation. In addition, SFAS No. 148 amends the disclosure
8
Note 5 STOCKHOLDERS' EQUITY (CONTINUED)
requirements of SFAS No. 123 to require prominent disclosures in both
annual and interim financial statements about the method of accounting for
stock-based employee compensation and the effect of the method used on
reported results. We will continue to account for stock based compensation
using the methods detailed in the stock-based compensation accounting
standard.
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 exercise 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 in each of January 2006, 2007 and 2008.
Note 6 MAJOR CUSTOMERS
We derived in excess of 10% of our revenue from oil and gas sales made to
two customers, as follows. One of these (Calpine Corporation, Customer B)
has filed a petition for protection under the federal bankruptcy laws as
described in Note 8, below.
The Company
-----------
A B
- -
Quarter ended:
December 31, 2005 66% 26%
December 31, 2004 35% 50%
We do not believe that the concentration of our revenues from these two
customers constitutes a significant risk to us because there are other
customers available to purchase our oil and gas production, and because the
market for oil and gas is driven by many factors beyond local economics and
the relationship between a single customer and producer.
Note 7 INCOME TAXES
We have recorded a deferred income tax liability of $1,378,286 and an
estimated current income tax liability of 209,256. During the first six
months of fiscal 2006, we used all of our net operating loss carryforwards.
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
9
Note 7 INCOME TAXES (CONTINUED)
allowance for financial reporting purposes. Primarily, our proved oil and
gas reserves substantially exceed our expected future costs and hence, we
believe it more likely than not that the benefit will be realized.
At December 31, 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 $ 0 $ 285,462
Asset retirement obligation 133,354 4,727
----------- -----------
133,354 290,189
----------- -----------
Deferred tax (liabilities):
Property, plant and equipment 521 (1,855)
Oil and gas properties (1,720,375) (1,020,491)
----------- -----------
(1,720,896) (1,022,346)
----------- -----------
$ 1,587,542 $ 732,157
=========== ===========
A reconciliation between the statutory federal income tax rate (34%) and
the effective rate of income tax expense for the two six month periods
ended December 31 is as follows:
2005 2004
---- ----
Statutory federal income
tax rate 34% 34%
Other (3)% (4)%
--- ---
Net federal income tax rate 31% 30%
Statutory state income tax
rate, net of federal benefit 9% 9%
--- ---
Effective rate 40% 39%
=== ===
10
Note 7 INCOME TAXES (CONTINUED)
The provision for income taxes consists of the following components:
2005 2004
-------- --------
Current tax expense,
state $209,256 $ 0
Deferred tax expense 362,798 435,837
-------- --------
Total income tax provision $572,054 $435,837
======== ========
Note 8 CONTINGENCIES AND DRILLING COMMITMENTS
On December 20, 2005 Calpine Corporation, one of our major purchasers of
natural gas (currently purchases about 25% of our gas), filed for Chapter
11 bankruptcy protection in New York. At the time of the filing, Calpine
Corporation owed us, exclusive of etal participation, approximately
$193,000. We believe that the amount due to us at the filing will be
collectible, but because of issues associated with all bankruptcies, we
cannot offer any assurance that it will be collected. We will continue to
monitor the situation with respect to collectibility and take further
actions as we determine to be appropriate.
We have a proposed drilling budget for the period January through March
2006. The budget includes drilling seven wells in the Sacramento gas
province of northern California and one well in Kern County, California.
Our share of the estimated costs to complete this program is set forth in
the following table:
Completion &
Equipping
Area Wells Drilling Costs Costs Total
------------------------ ---------- -------------- ---------- ----------
Denverton Creek Field, 2 $ 380,000 $ 130,000 $ 510,000
Solano County, CA
West Grimes Field 3 264,000 80,000 344,000
Colusa County, CA
Malton Black Butte 2 168,000 87,000 255,000
Field, Colusa County, CA
San Emidio Field, 1 203,000 56,000 259,000
Kern County, CA
---------- ---------- ---------- ----------
Total Expenditure 8 $1,015,000 $ 353,000 $1,368,000
========== ========== ========== ==========
11
Note 9 NEW ACCOUNTING PRONOUNCEMENTS
FASB 151 - Inventory Costs
In November 2004, the FASB issued FASB Statement No. 151, which revised ARB
No. 43, relating to inventory costs. This revision is to clarify the
accounting for abnormal amounts of idle facility expense, freight, handling
costs and wasted material (spoilage). This Statement requires that these
items be recognized as a current period charge regardless of whether they
meet the criterion specified in ARB 43. In addition, this Statement
requires the allocation of fixed production overheads to the costs of
conversion be based on normal capacity of the production facilities. This
Statement became effective for financial statements for fiscal years
beginning after June 15, 2005. Management believes this Statement has not
any and will not have any material impact on our financial statements.
FASB 153 - Exchanges of Non-monetary Assets
In December 2004, the FASB issued FASB Statement No. 153. This Statement
addresses the measurement of exchanges of non-monetary assets. The guidance
in APB Opinion No. 29, "Accounting for Non-monetary Transactions", is based
on the principle that exchanges of non-monetary assets should be measured
based on the fair value of the assets exchanged. The guidance in that
Opinion, however, included certain exceptions to that principle. This
Statement amends Opinion 29 to eliminate the exception for non-monetary
exchanges of similar productive assets and replaces it with a general
exception for exchanges of non-monetary assets that do not have commercial
substance. A non-monetary exchange has commercial substance if the future
cash flows of the entity are expected to change significantly as a result
of the exchange. This Statement is effective for financial statements for
fiscal years beginning after June 15, 2005. Earlier application is
permitted for non-monetary asset exchanges incurred during fiscal years
beginning after the date of this Statement is issued. Management believes
this Statement will have no impact on our financial statements.
FASB 123 (revised 2004) - Share-Based Payments
In December 2004, the FASB issued a revision to FASB Statement No. 123,
"Accounting for Stock Based Compensation". This Statement supersedes APB
Opinion No. 25, "Accounting for Stock Issued to Employees", and its related
implementation guidance. This Statement establishes standards for the
accounting for transactions in which an entity exchanges its equity
instruments for goods or services. It also addresses transactions in which
an entity incurs liabilities in exchange for goods or services that are
based on the fair value of the entity's equity instruments or that may be
settled by the issuance of those equity instruments. This Statement focuses
primarily on accounting for transactions in which an entity obtains
employee services in share-based payment transactions. This Statement does
not change the accounting guidance for share-based payment transactions
with parties other than employees provided in Statement 123 as originally
issued and EITF Issue No. 96-18, "Accounting for Equity Instruments That
Are Issued to Other Than Employees for Acquiring, or in Conjunction with
Selling, Goods or Services." This Statement does not address the accounting
for employee share ownership plans, which are subject to AICPA Statement of
Position 93-6, Employers' Accounting for Employee Stock Ownership Plans.
12
Note 9 NEW ACCOUNTING PRONOUNCEMENTS (CONTINUED)
A nonpublic entity will measure the cost of employee services received in
exchange for an award of equity instruments based on the grant-date fair
value of those instruments, except in certain circumstances.
A public entity will initially measure the cost of employee services
received in exchange for an award of liability instruments based on its
current fair value; the fair value of that award will be re-measured
subsequently at each reporting date through the settlement date. Changes in
fair value during the requisite service period will be recognized as
compensation cost over that period. A nonpublic entity may elect to measure
its liability awards at their intrinsic value through the date of
settlement.
The grant-date fair value of employee share options and similar instruments
will be estimated using the option-pricing models adjusted for the unique
characteristics of those instruments (unless observable market prices for
the same or similar instruments are available).
Excess tax benefits, as defined by this Statement, will be recognized as an
addition to paid-in-capital. Cash retained as a result of those excess tax
benefits will be presented in the statement of cash flows as financing cash
inflows. The write-off of deferred tax assets relating to unrealized tax
benefits associated with recognized compensation cost will be recognized as
income tax expense unless there are excess tax benefits from previous
awards remaining in paid-in capital to which it can be offset.
The notes to the financial statements of both public and nonpublic entities
will disclose information to assist users of financial information to
understand the nature of share-based payment transactions and the effects
of those transactions on the financial statements.
The effective date for public entities that do not file as small business
issuers will be as of the beginning of the first interim or annual
reporting period that begins after June 15, 2005. For public entities that
file as small business issuers and nonpublic entities the effective date
will be as of the beginning of the first interim or annual reporting period
that begins after December 15, 2005. Management has complied with this
Statement as of the effective date.
Note 10 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 gas pay in
several intervals in the Forbes formation. Several of these Forbes
intervals were perforated and tested gas on a 1/4 inch choke at a flow rate
of 2,909 MCFPD with a flowing tubing pressure of 2,005 psig. Gas sales
commenced on January 13, 2006 at a flow rate of 1,750 MCFPD with a flowing
tubing pressure of 2,500 psig. Aspen has a 30.625% operated working
interest in this well.
The Merrill #31-2 well located in the Malton Black Butte Field, Tehama
County, California, was drilled to a depth of 2,450 feet and encountered
approximately 40 feet of potential gas pay in the Lower Kione formation.
Production casing was run based on favorable mud log and electric log
responses. This well also encountered approximately 100 gross feet of
partially depleted gas sand in the Upper Kione formation, which yielded
13
Note 10 SUBSEQUENT EVENTS (CONTINUED)
valuable data regarding the possibility of drilling a future under balanced
horizontal well in this zone. The Upper Kione is a prolific gas producing
zone in this area. Aspen has a 31% operated working interest in this well.
14
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
This segment should be read in conjunction with the management's discussion
and analysis of financial condition and results of operations contained in our
Annual Report on Form 10-KSB for the year ended June 30, 2005, which has been
filed with the Securities and Exchange Commission. The management's 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 discussed herein and 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 54 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 44% 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 commence gas
sales, 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 $4.00
to $10.00 per MMBTU for the fiscal year ended June 30, 2006 as compared to the
average gas price of $6.20 received during our 2005 fiscal year.
15
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 three
years, from a low of $3.76 per MMBTU average during the second quarter of fiscal
2003 to $10.14 per MMBTU for the quarter ended December 31, 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.
The prices that we receive for the oil and natural gas (including natural
gas liquids) produced are impacted by many factors that are outside of our
control. Historically, these commodity prices have been volatile and we expect
them to remain volatile. Prices for oil and natural gas are affected by changes
in market demands, overall economic activity, weather, pipeline capacity
constraints, inventory storage levels, the world political situation, basis
differentials and other factors. As a result, we cannot accurately predict
future natural gas and NGL (natural gas liquids) prices, and therefore, we
cannot determine what effect increases or decreases in production volumes will
have on future revenues.
On regulatory and operational matters, we actively manage our exploration
and production activities. We value sound stewardship and strong relationships
with all stakeholders in conducting our business. We attempt to stay abreast of
emerging issues to effectively anticipate and manage potential impacts to our
operations.
To manage commercial risk, we may use financial tools to hedge the price we
will receive for our product. The primary purpose of hedging is to provide
adequate return on our investments, grow our reserves while leaving as much
commodity price upside as possible. 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 six months of fiscal 2006 for our
natural gas was approximately $8.85 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.
16
Cash of $2,126,358 and $2,132,742 was provided by our operations for the
six months ended December 31, 2005 and 2004. The 2005 period generated net
income of $1,566,565, and we were able to generate increased positive cash flow
from operations during the first six months of fiscal 2006 as compared to the
2005 period (when we generated net income of $683,692) because of:
An increase in oil and gas sales (68%) due to increased volumes sold (13%)
and price received for our gas (49%); and
An increase in accounts payable and accrued expenses of $351,970 in 2005
(which conserved cash) compared to an increase in accounts payable and
accrued expenses of $762,109; and
These changes were offset by increased estimated depletion, depreciation
and amortization expense of $509,040 in 2006 compared to $310,001 in 2005.
Investing activities used cash to increase net capitalized oil and gas
costs and office equipment of $2,200,623 and $1,196,573 in the six months ended
December 31, 2005 and 2004. Cash in the current six month period ended December
31, 2005 was used for lease acquisition, seismic work, intangible drilling and
well workovers ($1,732,653), the purchase of oil and gas well equipment
($459,470), and office equipment of ($8,500). These expenditures are net of the
sale of interests in wells to be drilled charged to third party investors.
We have a proposed drilling budget for the period January through March
2006. The budget includes drilling seven wells in the Sacramento gas province of
northern California and one well in Kern County, California. Our share of the
estimated costs to complete this program is set forth in the following table:
Completion &
Equipping
Area Wells Drilling Costs Costs Total
------------------------- ---------- -------------- ---------- ----------
Denverton Creek Field, 2 $ 380,000 $ 130,000 $ 510,000
Solano County, CA
West Grimes Field 3 264,000 80,000 344,000
Colusa County, CA
Malton Black Butte 2 168,000 87,000 255,000
Field, Colusa County, CA
San Emidio Field, 1 203,000 56,000 259,000
Kern County, CA
---------- ---------- ---------- ----------
Total Expenditure 8 $1,015,000 $ 353,000 $1,368,000
========== ========== ========== ==========
17
Our working capital (current assets less current liabilities) at December
31, 2005, was $2,878,651, which reflects an approximate $269,000 increase from
our working capital at June 30, 2005. Our working capital increased by 10.3%
during the first six months of our 2006 fiscal year because of
an increase in accounts receivable ($1,511,881 at December 31, 2005 as
compared to $614,720 at June 30, 2005) due to larger production volumes and
greater prices received during the period and the Calpine Corporation
bankruptcy (leaving a receivable of approximately $193,000 net of etal
participation that (at this time) we believe is collectible);
a decrease in advances from joint owners of $156,700 and accounts
payable-related parties of approximately $90,000 that were not expended for
drilling projects at December 31, 2005,
which were partially offset by an increase in accounts payable of $508,700 and
an increase in taxes payable of $209,000 and a decrease during the period in
cash of approximately $60,000.
We anticipate that our working capital and anticipated cash flow from
operations and future successful drilling will be sufficient to pay our
obligations. Based on national and international concerns, we anticipate that
our gas production will continue to provide us with sufficient cash flow through
our current fiscal year and beyond. As discussed herein, this is dependent, in
part, on maintaining or increasing our level of production and the national and
world market maintaining its current prices for our gas production.
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.
18
Results of Operations
---------------------
December 31, 2005 Compared to December 31, 2004
-----------------------------------------------
For the six months ended December 31, 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 $1,311,125 as compared to the
comparable period of our 2004 fiscal year because of:
Increased production (347,800 MMBTU sold as compared to 307,400 MMBTU sold
during the first six months of our 2004 fiscal year);
Increased price received for our production (an average of $8.82 per MMBTU
during the first six months of our 2006 fiscal year as compared to $5.92
per MMBTU received during that period in 2005); and
Increased management fees received ($203,100 during fiscal 2006 as compared
to $141,800 during fiscal 2005) because we were operators of more wells
during 2006 (54 wells compared to 48 wells in 2005).
Our revenues during the second quarter include revenues accrued from (but not
paid by) Calpine Corporation because of its bankruptcy proceeding. We believe
that such revenues are collectible and will be collected. If those revenues are
ultimately not collected, then our revenues for the three and six months ended
December 31, 2005, will decrease by approximately $193,000 of pre-petition
receivables and any unpaid post-petition receivables. (See further discussion in
Note 8 to the financial statements and "Accounts Receivable," below.)
19
The following table sets forth certain items from our Condensed Consolidated
Statements of Operations as expressed as a percentage of total revenues for the
six months of fiscal 2005, 2004, 2003 and 2002:
For the Six Months Ended
------------- ------------- ------------- --------------
12/31/2005 12/31/2004 12/31/2003 12/31/2002
------------- ------------- ------------- --------------
Total revenues 100.0% 100.0% 100.0% 100.0%
Oil & gas production costs 5.9 8.3 12.5 14.1
------------- ------------- ------------- --------------
Income from operations 94.1 91.7 87.5 85.9
------------- ------------- ------------- --------------
Costs and expenses
Depreciation and depletion 15.5 15.7 31.4 33.7
Selling, general and administrative 14.1 19.0 38.6 63.1
Interest expense - - - -
------------- ------------- ------------- --------------
Total costs and expenses 29.6 34.7 70.0 96.8
------------- ------------- ------------- --------------
Income before income taxes 64.5 57.0 17.5 (10.9)
Other income (.6) - - -
Provision for income taxes 17.4 22.1 - -
------------- ------------- ------------- --------------
Net income (loss) 47.7 34.9 17.5 (10.9)
============= ============= ============= ==============
To facilitate discussion of our operating results for the six months ended
December 31, 2005 and 2004, we have included the following selected data from
our Condensed Consolidated Statements of Operations:
Comparison of the Fiscal
Six Months Ended December 31, Increase (Decrease)
-------------------------------------------------------
2005 2004 Amount Percentage
----------- ----------- ----------- -----------
Revenues:
Oil and gas sales $ 3,079,776 $ 1,829,912 $ 1,249,864 68%
Management fees 203,086 141,825 61,261 43
Interest and other 20,029 2,895 17,134 591
----------- ----------- ----------- -----------
Total revenues 3,302,891 1,974,632 1,328,259 67
----------- ----------- ----------- -----------
Cost and expenses:
Oil and gas production 192,170 163,856 28,314 17
Depreciation and depletion 509,040 310,001 199,039 64
General and administrative 463,062 376,468 86,594 23
Interest expense -- 4,778 (4,778) 100
----------- ----------- ----------- -----------
Total costs and expenses 1,164,272 855,103 309,169 36
----------- ----------- ----------- -----------
Income before taxes 2,138,619 1,119,529 1,019,090 91
Provision for income taxes 572,054 435,837 136,217 31
----------- ----------- ----------- -----------
Net income 1,566,565 $ 683,692 $ 882,873 129%
=========== =========== =========== ===========
20
Central to the issue of success of the six months operations ended December 31,
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
------------- ----------- ------------
2006
----------------------------
lst Quarter $1,062,543 146,445 $7.26
2nd Quarter 2,017,233 201,371 10.14
-------------- ----------- ------------
Year to date 3,079,776 347,816 8.85
-------------- ----------- ------------
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
-------------- ----------- ------------
Second Quarter change
----------------------------
2006
----------------------------
Amount $884,874 24,021 $3.77
Percentage 78% 14% 59%
2005
----------------------------
Amount $769,417 97,450 $1.73
Percentage 212% 122% 37%
(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 six months of fiscal 2006 and during the
twelve months of fiscal 2005. As the table above notes, revenue has increased
approximately 78% when comparing the two three month periods ended December 31,
2005 and 2004. Volumes sold increased approximately 14%, while the price
received for our product increased 59%.
Total revenue increased $884,874, or 78% when comparing the two periods, while
operating and production costs increased $21,656, or 22%. 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 22% increase in production costs is even less than the 78%
increase in oil and gas sales.
19
A significant ratio presented is the percentage of management fees charged to
operated wells versus our general and administrative costs. This coverage of
general and administrative costs improved from approximately 38% for the six
months ended December 31, 2004 to approximately 44% at December 31, 2005.
When comparing general and administrative expense for 2006 and 2005, costs
increased approximately $86,600, or 23%, primarily because of increases in
promotion and advertising ($58,900), accounting and audit fees ($11,300), legal
fees, medical insurance, corporate reporting and consulting fees and other
($16,400).
Results of operations and net income are presented in the following table:
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
-------------------
lst Quarter $1,194,168 $1,112,448 $641,697 $.095 $.090
2nd Quarter 2,108,723 1,978,244 1,496,922 .222 .210
--------------- ------------- ---------------------- --------- -----------
Year to date 3,302,891 3,090,692 2,138,619 .31 .30
--------------- ------------- ---------------------- --------- -----------
2005
-------------------
1st Quarter 784,299 715,249 389,781 .063 .061
2nd Quarter 1,190,333 1,092,632 729,749 .116 .111
3rd Quarter 1,163,746 1,056,268 703,738 .109 .106
4th Quarter 980,926 908,704 382,957 .059 .056
--------------- ------------- ---------------------- --------- -----------
Total 4,119,304 3,772,853 2,206,224 .34 .33
--------------- ------------- ---------------------- --------- -----------
2004
-------------------
lst Quarter 388,337 348,739 50,197 .008 .008
2nd Quarter 433,317 365,761 93,022 .016 .015
3rd Quarter 440,127 354,642 76,762 .013 .013
4th Quarter 558,899 509,066 145,664 .025 .022
--------------- ------------- ---------------------- --------- -----------
Total 1,820,680 1,578,208 365,645 .06 .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 six month periods ended December 31, 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.
20
Contractual Obligations:
------------------------
We had five contractual obligations as of December 31, 2005. The following table
lists our significant liabilities at December 31, 2005:
Payments Due By Period
------------------------------------------------------------------
Less than After
Contractual Obligations 1 year 2-3 years 4-5 years 5 years Total
---------------------------- ---------- ---------- ---------- ---------- ---------
Employment Obligations $226,000 $512,000 $27,000 $-0- $765,000
Contract Services 15,000 -0- -0- -0- 15,000
Obligations
Operating Leases 9,500 -0- -0- -0- 9,500
---------- ---------- ---------- ---------- ---------
Total contractual
cash obligations $250,500 $512,000 $27,000 $-0- $789,500
========== ========== ========== ========== =========
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
six months ended December 31, 2005 and 2004 was $12,474 and $12,270,
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
21
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 uncollectible accounts based on management's
estimate of the collectibility of customer accounts. If the financial condition
of a customer were to deteriorate, resulting in an impairment of its ability to
make payments, an 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. At the present time, we believe that we will collect
the full amount of the pre-petition and post-petition receivables from Calpine
Corporation (notwithstanding its bankruptcy petition). We will continue to
monitor this situation and revise our estimates as appropriate.
Property, Equipment, Depreciation and Depletion:
------------------------------------------------
We follow the full-cost method of accounting for oil and gas properties. Under
this method, all productive and nonproductive costs incurred in connection with
the exploration for and development of oil and gas reserves are capitalized.
Such capitalized costs include lease acquisition, geological and geophysical
work, delay rentals, drilling, completing and equipping oil and gas wells,
including salaries, benefits and other internal salary related costs directly
attributable to these activities. Costs associated with production and general
corporate activities are expensed in the period incurred. Interest costs related
to unproved properties and properties under development are also capitalized to
oil and gas properties. If the net investment in oil and gas properties exceeds
an amount equal to the sum of (1) the standardized measure of discounted future
net cash flows from proved reserves, and (2) the lower of cost or fair market
value of properties in process of development and unexplored acreage, the excess
is charged to expense as additional depletion. Normal dispositions of oil and
gas properties are accounted for as adjustments of capitalized costs, with no
gain or loss recognized.
We apply SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets." Under SFAS No. 144, long-lived assets and certain intangibles are
reported at the lower of the carrying amount or their estimated recoverable
amounts. Long-lived assets subject to the requirements of SFAS No. 144 are
evaluated for possible impairment through review of undiscounted expected future
cash flows. If the sum of undiscounted expected future cash flows is less than
the carrying amount of the asset or if changes in facts and circumstances
indicate, an impairment loss is recognized.
Asset retirement obligations:
-----------------------------
We recognize the future cost to plug and abandon gas wells over the estimated
useful life of the wells in accordance with the provision of SFAS No. 143. SFAS
No. 143 requires that we record a liability for the present value of the asset
retirement obligation with a corresponding increase to the carrying value of the
related long-lived asset. We amortize the amount added to the oil and gas
properties and recognize accretion expense in connection with the discounted
liability over the remaining lives of the respective gas wells. Our liability
estimate is based on our historical experience in plugging and abandoning gas
wells, estimated well lives based on engineering studies, external estimates as
to the cost to plug and abandon wells in the future and federal and state
regulatory requirements. The liability is discounted using a credit-adjusted
risk-free rate of 6%. Revisions to the liability could occur due to changes in
well lives, or if federal and state regulators enact new requirements on the
plugging and abandonment of gas wells.
Off Balance Sheet Arrangements:
-------------------------------
We have no off balance sheet arrangements and thus no disclosure is required.
22
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
23
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,
February 9, 2006 Chief Executive Officer,
Principal Financial Officer
24