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, 2003
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 the number of shares outstanding of each of the Issuer's classes of
common stock as of the latest practicable date.
Class Outstanding at February 11, 2004
----- --------------------------------
Common stock, $.005 par value 5,863,828
Transitional small business disclosure format: [ ] Yes [X] No
Part One. FINANCIAL INFORMATION
Item 1. Financial Statements
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, June 30,
2003 2003
---- ----
(Unaudited) (Audited)
Current Assets:
Cash and cash equivalents, including $247,570
and $516,365 of invested cash at December
31, 2003 and June 30, 2003 respectively .......... $ 916,031 $ 776,566
Precious metals .................................. 18,823 18,823
Accounts receivable .............................. 318,450 269,259
Receivable, related party ........................ 11,314 6,302
Prepaid expenses ................................. 11,370 22,181
----------- -----------
Total current assets ........................ 1,275,988 1,093,131
----------- -----------
Investment in oil and gas properties, at cost
(full cost method of accounting) ................. 7,642,168 6,723,579
Less accumulated depletion and valuation
allowance ........................................ (2,924,469) (2,674,469)
----------- -----------
4,717,699 4,049,110
----------- -----------
Property and equipment, at cost:
Furniture, fixtures and vehicles ................. 112,562 112,562
Less accumulated depreciation .................... (73,378) (64,178)
----------- -----------
39,184 48,384
----------- -----------
TOTAL ASSETS ................................ $ 6,032,871 $ 5,190,625
=========== ===========
(Statement Continues)
See notes to Consolidated Financial Statements
2
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS (Continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
December 31, June 30,
2003 2003
---- ----
(Unaudited) (Audited)
Current liabilities:
Accounts payable and accrued expenses .......... $ 1,043,005 $ 581,895
Accounts payable - related party ............... 12,188 17,685
Advances from joint interest owners ............ 141,995 150,821
Notes payable - current ........................ 150,000 0
----------- -----------
Total current liabilities ...................... 1,347,188 750,401
----------- -----------
Asset retirement obligation .................... 45,081 17,841
Deferred income taxes .......................... 131,350 131,350
Notes payable - long term ...................... 75,000 0
----------- -----------
Total long term liabilities .................... 251,431 149,191
----------- -----------
Total liabilities .............................. 1,598,619 899,592
----------- -----------
Stockholders' equity:
Common stock, $.005 par value:
Authorized: 50,000,000 shares
Issued: at December 31, 2003 5,863,828
and June 30, 2003: 5,863,828 ............... 29,320 29,320
Capital in excess of par value ................. 6,025,797 6,025,797
Accumulated deficit ............................ (1,613,681) (1,756,900)
Deferred compensation .......................... (7,184) (7,184)
----------- -----------
Total stockholders' equity ..................... 4,434,252 4,291,033
----------- -----------
Total liabilities and stockholders' equity ..... $ 6,032,871 $ 5,190,625
=========== ===========
See Notes to Consolidated Financial Statements
3
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended Six Months Ended
December 31, December 31,
------------------------- -------------------------
2003 2002 2003 2002
----------- ----------- ----------- -----------
Revenues:
Oil and gas ............................ $ 362,942 $ 241,700 $ 704,868 $ 440,131
Management fees ........................ 66,106 34,066 112,021 96,795
Interest and other, net ................ 4,269 3,314 4,765 7,050
----------- ----------- ----------- -----------
Total Revenues ........................... 433,317 279,080 821,654 543,976
----------- ----------- ----------- -----------
Costs and expenses:
Oil and gas production ................. 63,287 38,611 102,389 76,525
Depreciation, depletion and amortization 130,349 97,969 257,949 183,389
Selling, general and administrative .... 145,788 157,681 317,226 343,481
Interest expense ....................... 871 479 871 479
----------- ----------- ----------- -----------
Total Costs and Expenses ................. 340,295 294,740 678,435 603,874
----------- ----------- ----------- -----------
Income (loss) before taxes ............... 93,022 (15,660) 143,219 (59,898)
----------- ----------- ----------- -----------
Provision for income taxes ............... 0 0 0 0
----------- ----------- ----------- -----------
Net income (loss) ........................ $ 93,022 $ (15,660) $ 143,219 $ (59,898)
=========== =========== =========== ===========
Basic income (loss) per common share ..... $ .01 $ ( -- ) $ .02 $ (.01)
=========== =========== =========== ===========
Diluted income (loss) per common share ... $ .01 $ ( -- ) $ .02 $ (.01)
=========== =========== =========== ===========
Basic weighted average number of
common shares outstanding ................ 5,863,828 5,863,828 5,863,828 5,863,828
=========== =========== =========== ===========
Diluted weighted average number of
common shares outstanding ................ 6,144,999 5,863,828 6,144,999 5,863,828
=========== =========== =========== ===========
The accompanying notes are an integral
part of these statements.
4
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six months ended December 31,
-----------------------------
2003 2002
----------- -----------
Cash flows from operating activities:
Net income (loss) ................................ $ 143,219 $ (59,898)
Adjustments to reconcile net income (loss)
to net cash provided by operating activities:
Depreciation, depletion and amortization ....... 257,949 183,390
Changes in assets and liabilities:
Decrease (increase) in receivable .............. (54,413) 89,373
Decrease in prepaid expense .................... 10,811 5,026
Increase in accounts payable and accrued expense 446,787 205,792
----------- -----------
Net cash provided by operating activities ...... 804,353 423,683
----------- -----------
Cash flows from investing activities:
Additions to oil and gas properties ............ (889,888) (396,504)
Proceeds - sale of oil and gas properties ...... -- 69,422
Proceeds - sale of idle equipment .............. -- 1,155
----------- -----------
Net cash (used) by investing activities ........ (889,888) (325,927)
Cash flow from financing activities:
Proceeds from notes payable .................... 225,000 --
----------- -----------
Net increase in cash and cash equivalents ...... 139,465 97,756
Cash and cash equivalents, beginning of year ... 776,566 916,001
----------- -----------
Cash and cash equivalents, end of year ......... $ 916,031 $ 1,013,757
=========== ===========
Other information:
Interest paid .................................. $ 871 $ 479
=========== ===========
Non-cash investing activities
Asset retirement obligation .................... $ 29,007 $ 0
=========== ===========
The accompanying notes are an integral
part of these statements.
5
ASPEN EXPLORATION CORPORATION
Notes to Consolidated Financial Statements
(Unaudited)
December 31, 2003
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 the full
year. These financial statements should be read in conjunction with our Annual
Report on Form 10-KSB for the year ended June 30, 2003.
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, 2003.
Note 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No.
141, "Business Combinations," which requires the purchase method of accounting
for business combinations initiated after June 30, 2001 and eliminates the
pooling-of-interests method. In July 2001, the FASB issued SFAS No. 142,
"Goodwill and Other Intangible Assets," which discontinues the practice of
amortizing goodwill and indefinite lived intangible assets and initiates an
annual review for impairment. Intangible assets with a determinable useful life
will continue to be amortized over that period. The oil and gas industry is
currently discussing the appropriate balance sheet classification of oil and gas
mineral rights held by lease or contract. We classify these assets as a
component of oil and gas properties in accordance with its interpretation of
SFAS No. 19 and common industry practice. There is also a view that these
mineral rights are intangible assets as defined in SFAS No. 141, "Business
Combinations", and, therefore, should be classified separately on the balance
sheet as intangible assets.
We did not change or reclassify contractual mineral rights included in oil and
gas properties on the balance sheet upon adoption of SFAS No. 141. We believe
its current accounting of such mineral rights as part of oil and gas properties
is appropriate under the full cost method of accounting. However, if the
accounting for mineral rights held by lease or contract is ultimately changed so
that costs associated with mineral rights not held under fee title and pursuant
to the guidelines of SFAS No. 141 are required to be classified as long term
intangible assets, then the reclassified amount as of December 31, 2003 and June
30, 2003 (the end of our last completed fiscal year) would be approximately $1.6
million. Management does not believe that the ultimate outcome of this issue
will have a significant impact on our cash flows, results of operations or
financial position.
6
Note 3 RECEIVABLE - RELATED PARTIES
The receivable from related parties constitutes amounts due from officers for
joint operating costs of wells operated by us. The transactions are in the
normal course of business with the same terms as other joint owners and are
repaid in a normal business cycle.
Note 4 ASSET RETIREMENT OBLIGATION
Effective July 1, 2002, we adopted the provisions of SFAS No. 143, "Accounting
for Asset Retirement Obligations." SFAS No. 143 generally applies to legal
obligations associated with the retirement of long-lived assets that result from
the acquisition, construction, development and/or the normal operation of a
long-lived asset. SFAS No. 143 requires us to recognize an estimated liability
for the plugging and abandonment of our gas wells. 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 a 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 December 31, 2003 is as
follows:
Asset retirement obligations as of
June 30, 2003 $ 17,841
ARO additions 29,007
Liabilities settled (516)
Accretion expense 857
Revision of estimate (2,108)
--------
Asset retirement obligation as of
December 31, 2003 $ 45,081
========
Note 5 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.
7
Note 5 EARNINGS PER SHARE (CONTINUED)
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
$143,219 for the six months ended December 31, 2003 and a net loss of $59,898
for the six months ended December 31, 2002. Because of the net loss for the six
months ended December 31, 2002, the basic and diluted average outstanding shares
are considered the same, since including the dilutive shares would have an
antidilutive effect on the loss per share calculation.
December 31, 2003
--------------------------------
Per
Net Share
Income Shares Amount
--------- --------- -------
Basic earnings per share:
Net income and
share amounts $ 143,219 5,863,828 $ .02
Dilutive securities:
stock options 776,000
Repurchased shares (494,829)
--------- --------- -------
Diluted earnings per share:
Net income and assumed
share conversion $ 143,219 6,144,999 $ .02
========= ========= =======
Note 6 NOTES PAYABLE
The Company incurred the following debt:
December 31, June 30,
2003 2003
-------- --------
Note payable to a bank for the acquisition of
producing gas properties located in several
counties in the Sacramento Valley,
California, principal payments are $12,500
per month plus interest at the bank's prime
rate plus 2%. (Rate was 6% at December 31,
2003.) The loan is collateralized by accounts
receivable, other rights to payments and all
inventory $225,000 $ 0
-------- --------
Less current portion 150,000 0
-------- --------
Long term portion $ 75,000 $ 0
======== ========
8
Note 7 SEGMENT INFORMATION
We operate in one industry segment within the United States, oil and gas
exploration and production.
Identified assets by industry are those assets that are used in our operations
in that industry. Corporate assets are principally cash, furniture, fixtures and
vehicles.
We have adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and
Related Information." SFAS No. 131 requires the presentation of descriptive
information about reportable segments which is consistent with that made
available to the management of the Company to assess performance.
Our oil and gas segment derives its revenues from the sale of oil and gas and
prospect generation and administrative overhead fees charged to participants in
our oil and gas ventures. Corporate income is primarily derived from interest
income on funds held in money market accounts.
During the six months ended December 31, 2003 and 2002 there were no
intersegment revenues. The accounting policies applied by each segment are the
same as those used by us in general.
There have been no differences from the last annual report in the basis of
measuring segment profit or loss. There have been no material changes in the
amount of assets for any operating segment since the last annual report except
for the oil and gas segment which capitalized approximately $889,888 for the
development and acquisition of oil and gas properties.
9
Note 7 SEGMENT INFORMATION (CONTINUED)
Segment information consists of the following for the six months ended December
31:
Oil and Gas Corporate Consolidated
----------- --------- ------------
Revenues:
2003 $ 816,889 $ 4,765 $ 821,654
2002 536,926 7,050 543,976
Income (loss) from
operations:
2003 $ 465,751 $ (322,532) $ 143,219
2002 285,850 (345,748) (59,898)
Identifiable assets:
2003 $ 4,849,966 $ 1,182,905 $ 6,032,871
2002 3,605,672 1,344,382 4,950,054
Depreciation, depletion and
valuation charged to
identifiable assets:
2003 $ (248,749) $ (9,200) $ (257,949)
2002 (174,551) (8,838) (183,389)
Capital expenditures:
2003 $ 889,888 $ -0- $ 889,888
2002 396,504 -0- 396,504
Note 8 MAJOR CUSTOMERS
We derived in excess of 10% of our revenue from various sources (oil and gas
sales) as follows:
The Company
-----------
A B C
- - -
Year ended:
December 31, 2003 26% 54% 11%
December 31, 2002 24% 53% -
10
Note 9 COMMITMENTS AND CONTINGENCIES
At December 31, 2003, the Company was committed to the following drilling and
development projects in California:
Project Aspen Cost
------- ----------
6 well farmout $ 0
Verona Pipeline 70,000
--------
Total $ 70,000
========
We are committed to a 6 well farmout and drilling program to be completed during
fiscal 2004 and 2005. Our 30% working interest share of the costs of this
project are estimated to be $-0- because of prospect fees charged to the other
working interest owners.
Effective January 1, 2004 through March 31, 2004, we entered into a purchase and
sales agreement with a major gas purchaser to sell 500 MMBTU' S of gas per day
at an average price of $6.07 per MMBTU. During the month of January, the latest
date price information was available, we would have received approximately $5.66
per MMBTU with our normal pricing structure and no hedging agreements in force.
There is no assurance such prices can be obtained in the future.
Note 10 INCOME TAXES
The Company has made no provision for income taxes for the three month period
ended December 31, 2003 since it utilizes net operating loss carryforwards. The
Company had approximately $1,796,000 of such carryforwards at June 30, 2003.
Note 11 SUBSEQUENT EVENTS
Aspen and partners have recently completed the shooting of a 10.5 square mile
3-D seismic program located over its acreage in the West Grimes Field, Colusa
County, California, approximately 100 miles northeast of Sacramento. The data
has been processed and is currently being evaluated by one of Aspen's consulting
geophysicists.
Note 12 NEW ACCOUNTING PRONOUNCEMENTS
In December 2002, the FASB approved SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure - an amendment of FASB Statement No.
123". SFAS No. 148 amends SFAS No. 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 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. SFAS No. 148
is effective for financial statements for fiscal years ending after December 15,
2002. The Company will continue to account for stock based compensation using
the methods detailed in the stock-based compensation accounting policy.
11
Note 12 NEW ACCOUNTING PRONOUNCEMENTS (CONTINUED)
In April 2003, the FASB approved SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities". SFAS No. 149 is not expected to
apply to the Company's current or planned activities.
In June 2003, the FASB approved SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity". SFAS No. 150
establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and equity. This
Statement is effective for financial instruments entered into or modified after
May 31, 2003, and otherwise is effective at the beginning of the first interim
period beginning after June 15, 2003. SFAS No. 150 is not expected to have an
effect on the Company's financial position.
12
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
This 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, 2003, which has been
filed with the Securities and Exchange Commission. This 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 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.
Liquidity and Capital Resources
-------------------------------
December 31, 2003 as compared to June 30, 2003
----------------------------------------------
At December 31, 2003 current assets were $1,275,988 and current liabilities were
$1,347,188 and we had negative working capital of $71,200 compared to current
assets of $1,093,131 at June 30, 2003 and current liabilities of $750,401 at
June 30, 2003, resulting in working capital at June 30, 2003 of $342,730. Our
working capital decreased $271,530 from June 30, 2003 to December 31, 2003 for
several reasons.
Our current assets increased $182,857 due, in part, to an increase in cash
and cash equivalents of $139,465 from $776,566 to $916,031. Much of the
increase in cash was due to an increase in revenue received by us in
December and disbursed to other revenue interest owners in January 2004. We
also received $56,000 in prospect fees from other working interest owners
for the Mengali-Durst #22-1 and the Sac Outing #31-3 wells, which were
drilled in October 2003. Accounts receivable trade increased by $54,203
because of the completion of various drilling projects, which were in
process at year end. Prepaid expenses decreased $10,811, or 49%, reflecting
a reduction in prepaid taxes and the expensing of engineering fees at the
end of the six month period.
Our current liabilities increased $596,787 to $1,347,188 at December 31,
2003 from $750,401 at June 30, 2003. This increase was due to a number of
factors including the receipt of revenue due to other revenue owners of
approximately $490,000 and the current portion of notes payable of $150,000
incurred in December, the proceeds of which were used to acquire producing
gas wells located in northern California. Other than noted, current
liabilities decreased $43,213.
13
We anticipate that our current assets will be sufficient to pay our current
liabilities as long as our gas production continues to provide us with
sufficient cash flow. As discussed below, this is dependent, in part, on
maintaining or increasing our level of production and the national and world
market maintaining its current prices for our gas production.
Drilling success during the past year added to our cash flow from operations.
These successes have been offset by the decline in production rates from older
wells and the sale of our producing oil wells in Kern County in 2002. The
average price received for oil and gas for the quarter ended December 31, 2003
was $23.93 per barrel and $4.67 per MMBTU of gas compared to $25.39 per barrel
and $3.36 per MMBTU of gas at December 31, 2002, a decrease of 6% and increase
of 40%, respectively.
Our capital requirements can fluctuate over a twelve month period because our
drilling program is usually carried out in California's dry season, from late
April until November, after which wet weather either precludes further activity
or makes it cost prohibitive. In October 2003, we drilled and abandoned two
wells at a cost to us of $84,000.
We believe that internally generated funds will be sufficient to finance our
drilling and operating expenses for the next twelve months. However, during
December 2003, we borrowed $225,000 from a bank in California and used the
proceeds to acquire various working interests in producing gas wells located in
several counties in the Sacramento Valley, California.
14
Results of Operations
---------------------
December 31, 2003 Compared to December 31, 2002
-----------------------------------------------
For the six months ended December 31, 2003 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.
Oil and gas revenues, which include income from management fees, for the six
months ended December 31, 2003 increased approximately $279,963 from $536,926 to
$816,889, a 52% increase. This increase reflects an increase in the prices
received for the sale of gas which was partially offset by a decrease in
production in the Denverton Creek and Malton Black Butte fields as well as the
Kern County oil properties, which were sold on September 1, 2002. Our share of
sales of gas for the six month period ended December 31, 2003 was approximately
151,000 MMBTU of gas. The average price received for the six months ended
December 31, 2003 was $4.67 per MMBTU for gas. This is an increase in natural
gas production of 9% when compared to the approximately 138,600 MMBTU of gas
production achieved during the six months of the 2002 fiscal year. Another
factor resulting in increased revenues during the six months of fiscal 2003 was
an increase in the prices received for our gas production when compared to the
price of $3.36 received for gas during the first six months of fiscal 2002.
Oil and gas production costs increased $25,864 from $76,525 to $102,389. The
increase in costs reflects the addition of new wells during normal operations
during the past twelve months, and the addition of compression costs associated
with older gas wells with declining pressures.
Depletion, depreciation and amortization increased approximately $74,600 or 41%
from the previous six months, which is our best estimate of what the full year
cost will be.
Selling, general and administrative expense decreased approximately 8% from
$343,481 to $317,226 for the six months ended December 31, 2003. This decrease
is primarily due to a reduction of salary and benefits to officers.
As a result of our operations, we ended the six month period with net income of
$143,219 compared to net loss of $59,898 for the corresponding six months a year
earlier. This improvement is due primarily to an increase in the price received
for our gas and an increase in gas production volumes, from 138,600 MMBTU to
151,000 MMBTU, a 9% increase. The net income was further enhanced by the
reduction of general and administrative costs as previously discussed. Effective
September 1, 2002, we sold our remaining interest in producing oil wells located
in Kern County, California for approximately $70,000 net to our interest. As of
September 1, 2002, we are only producing and selling natural gas with small
amounts of associated condensate sales.
Interest and other income decreased approximately $2,285 to $4,765 and were
primarily due to a decline in interest rates.
15
Contractual Obligations:
------------------------
We had six contractual obligations as of December 31, 2003. The following table
lists our significant liabilities at December 31, 2003:
Payments Due By Period
-----------------------------------------------------
Less than After
Contractual Obligations 1 year 2-3 years 4-5 years 5 years Total
----------------------- ------ --------- --------- ------- -----
Employment Obligations $207,483 $300,800 $160,800 $ 20,100 $689,183
Bank Loans 150,000 75,000 0 0 225,000
Operating Leases 24,092 5,960 0 0 30,052
-------- -------- -------- -------- --------
Total contractual
cash obligations $381,575 $381,760 $160,800 $ 20,100 $944,235
======== ======== ======== ======== ========
We maintain office space in Denver, Colorado, our principal office, Castle Rock,
Colorado and Bakersfield, California. The Denver office consists of
approximately 1,108 square feet with an additional 750 square feet of basement
storage. We entered into a one-year lease agreement on the Denver office through
December 31, 2004 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, 2003 and 2002 was $11,946 and
$11,596, 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 Consolidated
Financial Statements.
Reserve Estimates:
------------------
Our estimates of oil and natural gas reserves, by necessity, are projections
based on geologic and engineering data, and there are uncertainties inherent in
the interpretation of such data as well as the projection of future rates of
production and the timing of development expenditures. Reserve engineering is a
subjective process of estimating underground accumulations of oil and natural
gas that are difficult to measure. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological
interpretation and judgment. Estimates of economically recoverable oil and
natural gas reserves and future net cash flows necessarily depend upon a number
of variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects of
regulations by governmental agencies and assumptions governing future oil and
natural gas prices, future operating costs, severance and excise taxes,
development costs and workover and remedial costs, all of which may in fact vary
considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of oil and natural gas attributable to any
particular group of properties, classifications of such reserves based on risk
of recovery, and estimates of the future net cash flows expected therefrom may
vary substantially. Any significant variance in the assumptions could materially
affect the estimated quantity and value of the reserves, which could affect the
carrying value of our oil and gas properties and/or the rate of depletion of the
oil and gas properties. Actual production, revenues and expenditures with
respect to our reserves will likely vary from estimates, and such variances may
be material.
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Many factors will affect actual future net cash flows, including:
- The amount and timing of actual production;
- Supply and demand for natural gas;
- Curtailments or increases in consumption by natural gas purchasers; and
- Changes in governmental regulations or taxation.
Property, Equipment and Depreciation:
-------------------------------------
We follow the full-cost method of accounting for oil and gas properties. Under
this method, all productive and nonproductive costs incurred in connection with
the exploration for and development of oil and gas reserves are capitalized.
Such capitalized costs include lease acquisition, geological and geophysical
work, delay rentals, drilling, completing and equipping oil and gas wells,
including salaries, benefits and other internal salary related costs directly
attributable to these activities. Costs associated with production and general
corporate activities are expensed in the period incurred. Interest costs related
to unproved properties and properties under development are also capitalized to
oil and gas properties. If the net investment in oil and gas properties exceeds
an amount equal to the sum of (1) the standardized measure of discounted future
net cash flows from proved reserves, and (2) the lower of cost or fair market
value of properties in process of development and unexplored acreage, the excess
is charged to expense as additional depletion. Normal dispositions of oil and
gas properties are accounted for as adjustments of capitalized costs, with no
gain or loss recognized.
We apply SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets." Under SFAS No. 144, long-lived assets and certain intangibles are
reported at the lower of the carrying amount or their estimated recoverable
amounts. Long-lived assets subject to the requirements of SFAS No. 144 are
evaluated for possible impairment through review of undiscounted expected future
cash flows. If the sum of undiscounted expected future cash flows is less than
the carrying amount of the asset or if changes in facts and circumstances
indicate, an impairment loss is recognized.
Asset retirement obligations:
-----------------------------
We recognize the future cost to plug and abandon gas wells over the estimated
useful life of the wells in accordance with the provision of SFAS No. 143. SFAS
No. 143 requires that we record a liability for the present value of the asset
retirement obligation with a corresponding increase to the carrying value of the
related long-lived asset. We amortize the amount added to the oil and gas
properties and recognize accretion expense in connection with the discounted
liability over the remaining lives of the respective gas wells. Our liability
estimate is based on our historical experience in plugging and abandoning gas
wells, estimated well lives based on engineering studies, external estimates as
to the cost to plug and abandon wells in the future and federal and state
regulatory requirements. The liability is discounted using a credit-adjusted
risk-free rate of 6%. 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.
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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. Changes in Securities and Use of Proceeds.
--------------------------------------------------
None.
Item 3. Defaults Upon Senior Securities.
----------------------------------------
None.
Item 4. Submission of Matters to a Vote of Security Holders.
------------------------------------------------------------
No matter was submitted during the first quarter of the fiscal year covered
by this report to a vote of security holders, through the solicitation of
proxies or otherwise.
Item 5. Other Information.
--------------------------
None.
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Item 6. Exhibits and Reports on Form 8-K.
-----------------------------------------
(a) Exhibits
31. Rule 13a-14(a) Certification
32. Section 1350 Certification
(b) Reports on Form 8-K
During the period covered by this report and subsequently, we filed one
report on Form 8-K as follows:
Date: 12/15/2003 Item reported: Item 12, "Results of Operations and
Financial Condition.
No financial statements were filed with this Form 8-K.
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 11, 2004 Chief Executive Officer,
Principal Financial Officer
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