FORM 10-QSB
SECURITIES AND EXCHANGE COMMISSION
Washington D.C. 20549
MARK ONE
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2004
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________ to ________
Commission File Number 0-9494
ASPEN EXPLORATION CORPORATION
-----------------------------
(Exact Name of Aspen as Specified in its Charter)
Delaware 84-0811316
-------- ----------
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
Suite 208, 2050 S. Oneida St.,
Denver, Colorado 80224-2426
---------------- ----------
(Address 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 12, 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 May 12, 2004
----- ---------------------------
Common stock, $.005 par value 5,863,828
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
March 31, June 30,
2004 2003
----------- -----------
(Unaudited)
Current Assets:
Cash and cash equivalents, including $475,500
and $516,365 of invested cash at March 31, 2004
and June 30, 2003, respectively ................... $ 533,998 $ 776,566
Precious metals ................................... 18,823 18,823
Accounts receivable, trade ........................ 292,782 269,259
Accounts receivable - related party ............... 21,224 6,302
Prepaid expenses .................................. 9,525 22,181
----------- -----------
Total current assets ......................... 876,352 1,093,131
----------- -----------
Investment in oil and gas properties, at cost (full
cost method of accounting) ........................ 7,650,360 6,723,579
Less accumulated depletion and valuation
allowance ......................................... (3,047,469) (2,674,469)
----------- -----------
4,602,891 4,049,110
----------- -----------
Property and equipment, at cost:
Furniture, fixtures and vehicles .................. 112,562 112,562
Less accumulated depreciation ..................... (77,953) (64,178)
----------- -----------
34,609 48,384
----------- -----------
TOTAL ASSETS ................................. $ 5,513,852 $ 5,190,625
=========== ===========
(Statement Continues)
See notes to Condensed Consolidated Financial Statements
2
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
March 31, June 30,
2004 2003
----------- -----------
(Unaudited)
Current liabilities:
Accounts payable and accrued expenses .......... $ 136,944 $ 581,895
Accounts payable - related party ............... 21,099 17,685
Advances from joint owners ..................... 480,864 150,821
Notes payable - current ........................ 150,000 -0-
----------- -----------
Total current liabilities ...................... 788,907 750,401
----------- -----------
Asset retirement obligation .................... 45,081 17,841
Deferred income tax payable - long term ........ 131,350 131,350
Notes payable - long term ...................... 37,500 -0-
----------- -----------
Total long term liabilities .................... 213,931 149,191
----------- -----------
Total liabilities .............................. 1,002,838 899,592
----------- -----------
Stockholders' equity:
Common stock, $.005 par value:
Authorized: 50,000,000 shares
Issued: At March 31, 2004: 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 ............................ (1,536,919) (1,756,900)
Deferred compensation .......................... (7,184) (7,184)
----------- -----------
Total stockholders' equity ..................... 4,511,014 4,291,033
----------- -----------
Total liabilities and stockholders' equity ..... $ 5,513,852 $ 5,190,625
=========== ===========
See Notes to Condensed Consolidated Financial Statements
3
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended Nine Months Ended
March 31, March 31,
-------------------------- --------------------------
2004 2003 2004 2003
----------- ----------- ----------- -----------
Revenues:
Oil and gas .................................. $ 401,941 $ 314,222 $ 1,106,809 $ 754,353
Management fees .............................. 38,613 22,323 150,634 119,118
Interest and other, net ...................... (427) 931 4,338 7,981
----------- ----------- ----------- -----------
Total Revenues ................................. 440,127 337,476 1,261,781 881,452
----------- ----------- ----------- -----------
Costs and expenses:
Oil and gas production ....................... 85,912 64,700 188,301 141,225
Depreciation, depletion and amortization ..... 127,575 108,656 385,524 292,045
Selling, general and administrative .......... 146,800 135,372 464,026 478,853
Interest expense ............................. 3,078 -0- 3,949 479
----------- ----------- ----------- -----------
Total Costs and Expenses ....................... 363,365 308,728 1,041,800 912,602
----------- ----------- ----------- -----------
Income (loss) before taxes ..................... 76,762 28,748 219,981 (31,150)
----------- ----------- ----------- -----------
Provision for income taxes ..................... (--) (--) (--) (--)
----------- ----------- ----------- -----------
Net income (loss) .............................. $ 76,762 $ 28,748 $ 219,981 $ (31,150)
=========== =========== =========== ===========
Basic earnings (loss) per common share ......... $ .01 $ -- $ .04 $ --
=========== =========== =========== ===========
Diluted earnings (loss) per common share ....... $ .01 $ -- $ .04 $ --
=========== =========== =========== ===========
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 .................................... 5,951,553 5,863,828 5,951,553 5,863,828
=========== =========== =========== ===========
See Notes to Condensed Consolidated Financial Statements
4
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine months ended March 31,
2004 2003
----------- -----------
Cash flows from operating activities:
-------------------------------------
Net income (loss) .................................... $ 219,981 $ (31,150)
Adjustments to reconcile net income (loss) to net cash
provided used by operating activities:
Depreciation, depletion and amortization ........... 385,524 292,045
Amortization of deferred compensation .............. -0- 3,375
Changes in assets and liabilities:
Decrease (increase) in receivable .................. (38,445) 77,162
Decrease in prepaid expense ........................ 12,656 4,928
Increase (decrease) in accounts payable
and accrued expense .............................. (111,494) 494,233
----------- -----------
Net cash provided by operating activities .......... 468,222 840,593
----------- -----------
Cash flows from investing activities:
-------------------------------------
Additions to oil and gas properties ................ (1,033,040) (626,385)
Proceeds - sale of oil and gas properties .......... 134,750 69,422
Proceeds - sale of idle equipment .................. -0- 1,155
----------- -----------
Net cash (used) by investing activities ............ (898,290) (555,808)
----------- -----------
Cash flow from financing activities:
------------------------------------
Proceeds from notes payable ........................ 225,000 -0-
Payment of notes payable ........................... (37,500) -0-
----------- -----------
187,500 -0-
----------- -----------
Net increase (decrease) in cash and cash equivalents (242,568) 284,785
Cash and cash equivalents, beginning of period ..... 776,566 916,001
----------- -----------
Cash and cash equivalents, end of period ........... $ 533,998 $ 1,200,786
=========== ===========
Other information:
Interest paid ...................................... $ 3,949 $ 479
=========== ===========
Non-cash investing activities
Asset retirement obligation ........................ $ 28,491 $ 0
=========== ===========
See Notes to Condensed Consolidated Financial Statements
5
ASPEN EXPLORATION CORPORATION
Notes to Condensed Consolidated Financial Statements
(Unaudited)
March 31, 2004
Note 1 BASIS OF PRESENTATION
The accompanying financial statements are unaudited. However, in our opinion,
the accompanying financial statements reflect all adjustments, consisting of
only normal recurring adjustments, necessary for fair presentation. Interim
results of operations are not necessarily indicative of results for subsequent
interim periods or the remainder of the year. These financial statements should
be read in conjunction with our Annual Report on Form 10-KSB for the year ended
June 30, 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.
In March 2004, the Emerging Issues Task Force ("EITF") reached a consensus that
mineral rights, as defined in EITF Issue No. 04-2, "Whether Mineral Rights Are
Tangible or Intangible Assets," are tangible assets and that they should be
removed as examples of intangible assets in SFAS No. 141, "Business
Combinations" and No. 142, "Goodwill and Other Intangible Assets". The FASB has
recently ratified this consensus and directed the FASB staff to amend SFAS Nos.
141 and 142 through the issuance of FASB Staff Position FAS Nos. 141-1 and
142-1. Historically, Aspen has included the costs of such mineral rights as
tangible assets, which is consistent with the EITF's consensus. As such, EITF
04-02 has not affected the Company's consolidated financial statements.
6
Note 3 RECEIVABLE - RELATED PARTIES
The receivable from related parties constitutes amounts due from officers and
consultants for joint operating costs of wells operated by us. The transactions
are in the normal course of business with the same terms as other joint owners
and are repaid in a normal business cycle.
Note 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 credit adjusted risk-free rate of 6%. Revisions to
the liability could occur due to changes in plugging and abandonment costs,
useful well lives or if federal or state regulators enact new regulations on the
plugging and abandonment of wells.
A reconciliation of our liability for the year ended March 31, 2004 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
March 31, 2004 $ 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
$219,981 for the nine months ended March 31, 2004 and a net loss of $31,150 for
the nine months ended March 31, 2003. Because of the net loss for the nine
months ended March 31, 2003, 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.
Nine months ended March 31, 2004
--------------------------------
Net Per Share
Income Shares Amount
---------- ---------- -------
Basic earnings per share:
Net income and
share amounts $ 219,981 5,863,828 $ .04
Dilutive securities:
stock options -- 676,000 --
Repurchased shares -- (588,275) --
---------- ---------- -------
Diluted earnings per share:
Net income and assumed
share conversion $ 219,981 5,951,553 $ .04
========== ========== =======
Note 6 STOCKHOLDERS' EQUITY
Stock Options
-------------
On March 2, 2000, stock options were granted to the President of Aspen
Power Systems, LLC for 100,000 shares of the Company's common stock at a
grant price of $0.625 per share. These options vest 25,000 shares per annum
from March 15, 2000 through March 15, 2003. The options are exercisable
through March 15, 2004. As of this filing, no options were exercised, and
the options have expired.
As of March 31, 2004, we had an aggregate of 676,000 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.
8
Note 6 STOCKHOLDERS' EQUITY (CONTINUED)
The following information summarizes information with respect to options
granted under our equity plans:
Number of Weighted Average Exercise
Shares Price of Shares Under Plans
------ ---------------------------
Outstanding balance June 30, 2003 776,000 $ .58
========
Granted -0- --
========
Exercised -0- --
========
Forfeited or expensed (100,000) .625
-------- ========
Outstanding balance March 31, 2004 676,000 $ .57
======== ========
The following table summarizes information concerning outstanding and
exercisable options as of March 31, 2004:
Outstanding Exercisable
------------------------------- ----------------------
Weighted
Average Weighted Weighted
Remaining Average Average
Exercise Number Contractual Exercisable Number Exercise
Price Outstanding Life In Years Price Exercisable Price
----- ----------- ------------- ----- ----------- -----
$.57 426,000 08/15/2005(1) $ .57 -0- $ .57
.57 250,000 08/15/2007(1) .57 -0- .57
-------
676,000
=======
(1) The term of the option will be the earlier of the contractual life of
the options or 90 days after the date the optionee is no longer an
employee, consultant or director of the Company.
We account for the two stock option plans using APB No. 25 for directors
and employees and SFAS No. 123 for consultants. There were 676,000 options
granted in 2002. Directors and employees were granted 601,000 and
consultants were granted 75,000. The consultant options were valued using
the fair value method of SFAS No. 123 as calculated by the Black-Scholes
option-pricing model. The fair value of each option grant, as opposed to
its exercisable price, is estimated on the date of grant using the
Black-Scholes option-pricing model with the following weighted average
assumptions: no dividend yield, expected volatility of 14.9%, credit
adjusted risk free interest rates of 8.5% and expected lives of 3.4 to 4.4
years. The resulting compensation expense relating to the consultant option
grant will be included as an operating expense as the options vest.
9
Note 7 NOTES PAYABLE
The Company incurred the following debt:
March 31, June 30,
2004 2003
-------- --------
Note payable to a bank for the acquisition of
producing gas properties located in several
counties in the Sacramento Valley,
California, maturing June, 2005, principal
payments are $12,500 per month plus interest
at the bank's prime rate plus 2%. (Rate was
6% at March 31, 2004.) The loan is
collateralized by accounts receivable, other
rights to payments and all inventory. $187,500 $ 0
-------- --------
Less current portion 150,000 0
-------- --------
Long term portion $ 37,500 $ 0
======== ========
Note 8 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 nine months ended March 31, 2004 and 2003, there were no
intersegment revenues. The accounting policies applied by each segment are
the same as those used by us in general.
There have been no differences from the last annual report in the basis of
measuring segment profit or loss. There have been no material changes in
the amount of assets for any operating segment since the last annual report
except for the oil and gas segment which capitalized approximately
$1,033,040 for the development and acquisition of oil and gas properties.
10
Note 8 SEGMENT INFORMATION (CONTINUED)
Segment information consists of the following for the nine months ended
March 31:
Oil and Gas Corporate Consolidated
----------- --------- ------------
Revenues:
2004 $ 1,257,443 $ 4,338 $ 1,261,781
2003 873,471 7,981 881,452
Income (loss) from operations:
2004 $ 693,444 $ (473,463) $ 219,981
2003 453,459 (484,609) (31,150)
Identifiable assets:
2004 $ 4,723,147 $ 790,705 $ 5,513,852
2003 3,743,528 1,527,090 5,270,618
Depreciation, depletion and valuation
charged to identifiable assets:
2004 $ 371,749 $ 13,775 $ 385,524
2003 278,787 13,258 292,045
Capital expenditures:
2004 $ 1,033,040 $ -0- $ 1,033,040
2003 626,385 -0- 626,385
Note 9 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
- - -
9 months ended:
March 31, 2004 14% 23% 51%
March 31, 2003 - 22% 55%
11
Note 10 COMMITMENTS AND CONTINGENCIES
We have a proposed drilling budget for the period April through December
2004. The budget includes drilling eight wells in the Sacramento gas
province of northern California and the completion of the Verona Pipeline.
Our share of the estimated costs to complete this program is set forth in
the following table:
Complete &
Area Wells Drill Equip Total
--------------------- ---------- ---------- ---------- ----------
Momentum Farmout 3 $ 57,000 $ 273,000 $ 330,000
Various Counties, CA
Denverton Creek Field 1 26,000 19,000 45,000
Solano County, CA
West Grimes Field 4 375,000 250,000 625,000
Colusa County, CA
Verona Pipeline -- 70,000 70,000
---------- ---------- ---------- ----------
Total Expenditure 8 $ 458,000 $ 612,000 $1,070,000
========== ========== ========== ==========
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 11 INCOME TAXES
The Company has made no provision for income taxes for the nine month
period ended March 31, 2004 since it utilizes net operating loss
carryforwards. The Company had approximately $1,796,000 of such
carryforwards at June 30, 2003.
Note 12 SUBSEQUENT EVENTS
The Ettl #1-10, located in the Grimes Gas Field, Sutter County, California,
was drilled to a depth of 7,700'. Production casing was run based on
promising mud log and electric log responses. A Forbes sand interval was
perforated and tested at approximately 1,000 MCFPD. The shut-in tubing and
casing pressures were 2,600 psig. Gas sales should commence in
approximately 30 days. Aspen has a 28.75% operated working interest in this
well.
12
Note 12 SUBSEQUENT EVENTS (CONTINUED)
The Emigh #35-6, located in the Denverton Creek Field, Solano County,
California, was drilled to a depth of 11,200'. Production casing was run
based on encouraging mud log and electric log responses. The well will be
perforated in May 2004 to determine if commercial production can be
established. Aspen has a 5.25% operated working interest in this well.
Note 13 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.
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.
13
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, 2003, which has been
filed with the Securities and Exchange Commission. The management discussion and
analysis and other portions of this report contain forward-looking statements
(as such term is defined in Section 21E of the Securities Exchange Act of 1934,
as amended). These statements reflect our current expectations regarding our
possible future results of operations, performance, and achievements. These
forward-looking statements are made pursuant to the safe harbor provisions of
the Private Securities Litigation Reform Act of 1995.
Wherever possible, we have tried to identify these forward-looking
statements by using words such as "anticipate," "believe," "estimate," "expect,"
"plan," "intend," and similar expressions. These statements reflect our current
beliefs and are based on information currently available to us. Accordingly,
these statements are subject to certain risks, uncertainties, and contingencies,
which could cause our actual results, performance, or achievements to differ
materially from those expressed in, or implied by, such statements. These risks,
uncertainties and contingencies include, without limitation, the factors set
forth in our Form 10-KSB under "Item 6. Management's Discussion and Analysis of
Financial Conditions or Plan of Operation - Factors that may affect future
operating results." We have no obligation to update or revise any such
forward-looking statements that may be made to reflect events or circumstances
after the date of this Form 10-QSB.
Overview
--------
Aspen Exploration Corporation was organized in 1980 for the purpose of
acquiring, exploring and developing oil and gas and other mineral properties.
Since 1996, we have focused our efforts on the exploration, development and
operation of natural gas properties in the Sacramento Valley of northern
California. We are currently the operator of 38 gas wells and have a
non-operated interest in 16 additional gas wells.
We currently have offices in Bakersfield, California and Denver, Colorado
and have 2 full time employees as well as the Chairman of the Board who
allocates a portion of his time to the Company. We also make extensive use of
consultants for the conduct of our business, ranging from financial,
engineering, land, legal, and geological and geophysical specialists.
We will typically review 20 to 25 prospects for every well we participate
in, using 3-D seismic and well control geology to evaluate each prospect. Our
goal is to identify low to moderate risk wells with good gas reserve potential.
Where possible, we attempt to be the operator of each property we invest
in. Our knowledge of drilling and operating wells in the Sacramento Valley
allows us to maximize the potential return of each property. Administrative
charges to the properties help cover approximately 33% of our selling, general
and administrative expenses.
Outlook and Trends
------------------
We expect our natural gas production volumes to range between 290,000 to
320,000 MMBTU for the fiscal year ending June 30, 2004. We also anticipate that
the average price for our product will be in the range of $4.70 to $5.20 per
MMBTU for the fiscal year ended June 30, 2004.
14
Over the past five years we have been able to replace our produced reserves
and increase our yearly natural gas production. We have also benefited from a
general increase in natural gas prices over the past two years, from a low of
$2.78 per MMBTU average during the first quarter of fiscal 2003 to $5.28 per
MMBTU for the quarter ended March 31, 2004.
Quantitative and Qualitative Disclosure About Risk
--------------------------------------------------
Our ability to replace reserves, dissipated through production or
recalculation, will depend largely on how successful our drilling and
acquisition efforts will be in the future. While we cannot predict the future,
our historic success ratio over the past three years has been 80%. With the use
of 3-D seismic and well control data, interpreted by our geological and
geophysical consultants, we feel we can manage our dry hole risk as well as
anyone in the industry.
Commodity prices are impacted by many factors that are outside of our
control. Historically, commodity prices have been volatile and we expect them to
remain volatile. Commodity prices are affected by changes in market demands,
overall economic activity, weather, pipeline capacity constraints, inventory
storage levels, basis differentials and other factors. As a result, we cannot
accurately predict future natural gas and NGL (natural gas liquids) prices, and
therefore, we cannot determine what effect increases or decreases in production
volumes will have on future revenues.
On regulatory and operational matters, we actively manage our exploration
and production activities. We value sound stewardship and strong relationships
with all stakeholders in conducting our business. We attempt to stay abreast of
emerging issues to effectively anticipate and manage potential impacts to our
operations.
To manage commercial risk, we may use financial tools to hedge the price we
will receive for our product. The primary purpose of hedging is to provide
adequate return on our investments, grow our reserves while leaving as much
commodity price upside as possible.
In the past, Aspen has borrowed funds from an affiliate in 1997 and
withdrew funds from a life insurance policy in 1997 and 2000 to drill, develop
and produce our reserves. We are exposed to interest rate risk to the extent we
have borrowed funds. During December 2003, we borrowed $225,000 from a bank for
a modest acquisition. We currently pay 2% over the bank's prime rate for that
facility. At March 31, 2004, the effective interest rate was 6%.
Liquidity and Capital Resources
-------------------------------
We have historically financed our operations with internally generated
funds and limited borrowings from banks and third parties, and farmout
arrangements, which permit third parties (including some related parties) to
participate in our drilling prospects. Our principal uses of cash are for
operating expenses, the acquisition, drilling and production of prospects, the
acquisition of producing properties, working capital, servicing debt and the
payment of income taxes.
Cash of $468,200 and $840,600 was provided by our operations for the nine
months ended March 31, 2004 and 2003. Even though the 2003 period generated a
loss of $(31,150), we were able to generate a larger positive cash flow from
operations during the first nine months of fiscal 2003 as compared to the 2004
period (when we generated net income of $219,981) because of:
15
Lower depreciation, depletion and amortization expenses ($292,045 in 2003
as compared to $385,524 in 2004);
A $77,162 decrease in accounts receivable during 2003 (which provided cash)
compared to an increase in accounts receivable during 2004 of $38,445; and
A $494,233 increase in accounts payable and accrued expenses in 2003 (which
conserved cash) compared to an $111,494 reduction in accounts payable and
accrued expenses in 2004 (which required cash payments).
Investing activities used cash to increase capitalized oil and gas costs of
$1,033,000 and $626,400 in the nine months ended March 31, 2004 and 2003. Cash
in the current nine month period ended 2004 was used for lease acquisition and
seismic work ($712,600), intangible drilling and well workovers ($284,000), and
the purchase of oil and gas well equipment ($36,400). These expenditures were
offset by the sale of interests in wells to be drilled charged to third party
investors.
We have a proposed drilling, completion and construction budget for the
period April through December 2004. The budget includes drilling eight wells in
the Sacramento gas province of northern California and the completion of the
Verona Pipeline. Our share of the estimated costs to complete this program over
the next eight months is set forth in the following table:
Complete &
Area Wells Drill Equip Total
--------------------- ---------- ---------- ---------- ----------
Momentum Farmout 3 $ 57,000 $ 273,000 $ 330,000
Various Counties, CA
Denverton Creek Field 1 26,000 19,000 45,000
Solano County, CA
West Grimes Field 4 375,000 250,000 625,000
Colusa County, CA
Verona Pipeline -- 70,000 70,000
---------- ---------- ---------- ----------
Total Expenditure 8 $ 458,000 $ 612,000 $1,070,000
========== ========== ========== ==========
Our working capital (current assets less current liabilities) at March 31,
2004, was $87,445. We anticipate that our working capital and anticipated cash
flow from operations and future successful drilling will be sufficient to pay
our current liabilities as long as our gas production continues to provide us
with sufficient cash flow. As discussed below, this is dependent, in part, on
maintaining or increasing our level of production and the national and world
market maintaining its current prices for our gas production.
Our capital requirements can fluctuate over a twelve month period because
our drilling program is usually carried out in California's dry season, from
late April until November, after which wet weather either precludes further
activity or makes it cost prohibitive.
16
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. If our drilling efforts
are successful, the anticipated increased cash flow from the new gas
discoveries, in addition to our existing cash flow, should be sufficient to fund
our share of any future completion and pipeline costs.
Results of Operations
---------------------
March 31, 2004 Compared to March 31, 2003
-----------------------------------------
For the nine months ended March 31, 2004 our operations continued to be focused
on the production of oil and gas, and the investigation for possible acquisition
of producing oil and gas properties in California. During the 2004 period our
revenues increased by more than $352,000 as compared to the comparable period of
our 2003 fiscal year because of:
Increased production (224,400 MMBTU sold as compared to 187,400 MMBTU sold
during the first nine months of our 2003 fiscal year);
Increased price received for our production (an average of $4.88 per MMBTU
during the first nine months of our 2004 fiscal year as compared to $3.23
per MMBTU received during that period in 2003); and
Increased management fees received ($150,634 during 2004 as compared to
$119,118 during 2003) because we were operators of more wells during 2004
(38 wells compared to 33 wells in 2003).
When comparing the three month periods ended March 31, 2004 and 2003, our
revenues increased by more than $100,000 and net income increased by $48,000, or
167%, from $28,750 to $76,760 due to:
Increased production (71,900 MMBTU sold compared to 57,900 MMBTU sold
during the previous three months 2003 fiscal quarter) a 24% improvement;
Decreased price received for our production (an average of $5.28 per MMBTU
during the quarter ended March 31, 2004 as compared to $5.47 per MMBTU
received during that period in 2003) a 3.5% decline; and
Increased management fees received ($38,600 as compared to $22,300 during
2003) a 73% increase.
17
The following table sets forth certain items from our Condensed Consolidated
Statements of Operations as expressed as a percentage of total revenues, shown
by quarter for the nine months of fiscal 2004 and 2003:
For the Quarter Ended For the Quarter Ended
------------------------------------ --------------------------------------
3/31/2004 12/31/2003 9/30/2003 3/31/2003 12/31/2002 9/30/2002
--------- ---------- --------- --------- ---------- ---------
Total revenues 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
Oil & gas production costs 19.5 14.6 10.1 19.2 13.8 14.3
--------- ---------- --------- --------- ---------- ---------
Income from operations 80.5 85.4 89.9 80.8 86.2 85.7
--------- ---------- --------- --------- ---------- ---------
Costs and expenses
Depreciation and depletion 29.0 30.1 32.9 32.2 35.1 32.2
Selling, general and administrative 33.4 33.6 44.1 40.1 56.5 70.1
Interest expense .7 .0 .0 .0 .2 .0
--------- ---------- --------- --------- ---------- ---------
Total costs and expenses 63.1 63.7 77.0 72.3 91.8 102.3
--------- ---------- --------- --------- ---------- ---------
Income before income taxes 17.4 21.7 12.9 8.5 (5.6) (16.6)
Provision for income taxes .0 .0 .0 .0 .0 .0
--------- ---------- --------- --------- ---------- ---------
Net income (loss) 17.4 21.7 12.9 8.5 (5.6) (16.6)
========= ========== ========= ========= ========== =========
To facilitate discussion of our operating results for the nine months ended
March 31, 2004 and 2003, we have included the following selected data from our
Condensed Consolidated Statements of Operations:
Comparison of the Fiscal
Nine Months Ended March 31, Increase (Decrease)
-------------------------- ----------------------
2004 2003 Amount Percentage
---------- ---------- ---------- ----------
Revenues:
Oil and gas sales $1,106,809 $ 754,353 $ 352,456 46.7%
Management fees 150,634 119,118 31,516 26.5
Interest and other 4,338 7,981 (3,643) (45.6)
---------- ---------- ---------- -------
Total revenues 1,261,781 881,452 380,329 43.1
---------- ---------- ---------- -------
Cost and expenses:
Oil and gas production 188,301 141,225 47,076 33.3
Depreciation and depletion 385,524 292,045 93,479 32.0
Selling, general and administrative 464,026 478,853 (14,827) (3.1)
Interest expense 3,949 479 3,470 724.4
---------- ---------- ---------- -------
Total costs and expenses 1,041,800 912,602 129,198 14.2%
---------- ---------- ---------- -------
Net income (loss) $ 219,981 $ (31,150)
========== ==========
18
Central to the issue of success of the nine months operations ended March 31,
2004 is the discussion of changes in oil and gas sales, volumes of natural gas
sold and the price received for those sales. We present them here in tabular
form:
Oil & Gas MMBTU (1)
Sales Sold Price/MMBTU
---------- ---------- -----------
2004
----
lst Quarter $ 341,926 72,600 $ 4.75
2nd Quarter 362,942 79,900 4.64
3rd Quarter 401,941 71,900 5.28
---------- ---------- ---------
Year to date 1,106,809 224,400 4.88
---------- ---------- ---------
2003
----
lst Quarter 198,431 65,800 2.78
2nd Quarter 241,700 63,700 3.76
3rd Quarter 314,222 57,900 5.47
---------- ---------- ---------
Year to date 754,353 187,400 3.23
---------- ---------- ---------
Year to date change
Amount $ 352,456 37,000 $ 1.65
Percentage 46.7% 19.7% 51%
(1) Price per MMBTU may not agree with oil and gas sales because of the
inclusion of oil and NGL sales.
Oil and gas revenue, volumes sold and price received for our product have shown
a steady improvement over the past nine months of fiscal 2004 and the twelve
months of fiscal 2003. As the table above notes, revenue has increased
approximately 47% when comparing the two nine month periods ended March 31, 2004
and 2003. Volumes sold increased approximately 20%, while the price received for
our product increased 51%.
Total revenue increased $380,300, or 43% when comparing the two periods, while
operating and production costs increased $47,100, or 33%.
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 25% for the nine
months ended March 31, 2003 to approximately 32% at March 31, 2004.
When comparing general and administrative expense for 2004 and 2003, costs
declined slightly by $14,800, or 3.1%.
19
Results of operations and net income are presented in the following table:
Quarterly Financial Information (unaudited)
(1) Net Income (loss)
Total Operating Net Income Per Share
2004 Revenues Income (loss) Basic Diluted
---- ---------- ---------- ---------- --------- ---------
lst Quarter $ 388,337 $ 348,739 $ 50,197 .014 .014
2nd Quarter 433,317 365,761 93,022 .016 .016
3rd Quarter 440,127 354,642 76,762 .010 .010
---------- ---------- ---------- --------- ---------
Total 1,261,781 1,069,142 219,981 0.04 0.04
---------- ---------- ---------- --------- ---------
2003
----
lst Quarter 264,896 232,246 (44,238) (.01) (.01)
2nd Quarter 279,080 237,155 (15,660) -- --
3rd Quarter 337,476 271,845 28,748 -- --
---------- ---------- ---------- --------- ---------
Total $ 881,452 $ 741,246 $ (31,150) -- --
---------- ---------- ---------- --------- ---------
(1) Operating income is oil and gas sales plus management fees less direct
operating costs.
As can be seen in the table, revenues and operating income have improved in
every quarter when comparing the nine month periods ended March 31, 2004 and
2003. We believe this is due to the steady increase in production volumes sold
in each subsequent quarter and the fact that we have enjoyed an appreciating
price received for our product. Operating income has increased because
production costs have increased at a lesser rate than production and prices.
Contractual Obligations:
------------------------
We had six contractual obligations as of March 31, 2004. The following table
lists our significant liabilities at March 31, 2004:
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 -0- $669,083
Bank Loans 150,000 37,500 -0- -0- 187,500
Operating Leases 20,310 3,710 -0- -0- 24,020
-------- -------- --------- --------- --------
Total contractual
cash obligations $377,793 $342,010 $ 160,800 $ -0- $880,603
======== ======== ========= ========= ========
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 nine months ended March 31, 2004 and 2003 was $18,337 and
$22,620, respectively.
20
Critical Accounting Policies and Estimates:
-------------------------------------------
We believe the following critical accounting policies affect our most
significant judgments and estimates used in the preparation of our Condensed
Consolidated Financial Statements.
Reserve Estimates:
------------------
Our estimates of oil and natural gas reserves, by necessity, are projections
based on geologic and engineering data, and there are uncertainties inherent in
the interpretation of such data as well as the projection of future rates of
production and the timing of development expenditures. Reserve engineering is a
subjective process of estimating underground accumulations of oil and natural
gas that are difficult to measure. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological
interpretation and judgment. Estimates of economically recoverable oil and
natural gas reserves and future net cash flows necessarily depend upon a number
of variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects of
regulations by governmental agencies and assumptions governing future oil and
natural gas prices, future operating costs, severance and excise taxes,
development costs and workover and remedial costs, all of which may in fact vary
considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of oil and natural gas attributable to any
particular group of properties, classifications of such reserves based on risk
of recovery, and estimates of the future net cash flows expected therefrom may
vary substantially. Any significant variance in the assumptions could materially
affect the estimated quantity and value of the reserves, which could affect the
carrying value of our oil and gas properties and/or the rate of depletion of the
oil and gas properties. Actual production, revenues and expenditures with
respect to our reserves will likely vary from estimates, and such variances may
be material.
Many factors will affect actual future net cash flows, including:
- The amount and timing of actual production;
- Supply and demand for natural gas;
- Curtailments or increases in consumption by natural gas purchasers;
and
- Changes in governmental regulations or taxation.
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.
21
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.
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. Changes in Securities and Small Business Issuer Purchases of Equity
Securities.
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.
23
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
None.
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,
May 12, 2004 Chief Executive Officer,
Principal Financial Officer
24