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 March 31, 2002
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 May 10, 2002
----- ---------------------------
Common stock, $.005 par value 5,863,828
Part One. FINANCIAL INFORMATION
Item 1. Financial Statements
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, June 30,
2002 2001
---- ----
(Unaudited) (Audited)
Current Assets:
Cash and cash equivalents, including $1,210,075 and
$2,636,342 of invested cash at March 31, 2002 and
June 30, 2001 respectively ........................ $ 1,265,013 $ 2,695,583
Precious metals ................................... 18,823 18,823
Accounts receivable, trade ........................ 244,838 554,159
Accounts receivable - related party (Note 7) ...... -0- 20,000
Prepaid expenses .................................. 51,001 14,898
----------- -----------
Total current assets ......................... 1,579,675 3,303,463
----------- -----------
Investment in oil and gas properties, at cost
(full cost method of accounting) .................. 4,899,510 4,297,306
Less accumulated depletion and valuation allowance (2,256,413) (1,921,413)
----------- -----------
2,643,097 2,375,893
----------- -----------
Property and equipment, at cost:
Furniture, fixtures and vehicles .................. 109,653 104,368
Less accumulated depreciation ..................... (41,154) (28,133)
----------- -----------
68,499 76,235
----------- -----------
Cash surrender value, life insurance .............. 239,095 239,095
----------- -----------
TOTAL ASSETS ................................. $ 4,530,366 $ 5,994,686
=========== ===========
(Statement Continues)
See notes to Consolidated Financial Statements
2
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS (Continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
March 31, June 30,
2002 2001
---- ----
(Unaudited) (Audited)
Current liabilities:
Accounts payable and accrued expenses .......... $ 73,157 $ 1,036,715
Advances from joint owners ..................... 156,838 444,232
----------- -----------
Total current liabilities ...................... 229,995 1,480,947
Deferred income tax payable .................... 179,200 179,200
----------- -----------
Total liabilities .............................. 409,195 1,660,147
----------- -----------
Stockholders' equity:
Common stock, $.005 par value:
Authorized: 50,000,000 shares
Issued: At March 31, 2002: 5,863,828
and June 30, 2001: 5,812,205 ............... 29,320 29,060
Capital in excess of par value ................. 6,024,513 6,015,279
Accumulated deficit ............................ (1,919,161) (1,692,592)
Deferred compensation .......................... (13,501) (17,208)
----------- -----------
Total stockholders' equity ..................... 4,121,171 4,334,539
----------- -----------
Total liabilities and stockholders' equity ..... $ 4,530,366 $ 5,994,686
=========== ===========
See Notes to Consolidated Financial Statements
3
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended Nine Months Ended
March 31, March 31,
--------- ---------
2002 2001 2002 2001
---- ---- ---- ----
Revenues:
Oil and gas ...................................... $ 124,257 $ 1,109,992 $ 513,444 $ 2,688,142
Management fees .................................. 23,632 26,135 91,269 138,397
Interest and other, net .......................... 10,395 43,387 46,600 72,533
----------- ----------- ----------- -----------
Total Revenues ..................................... 158,284 1,179,514 651,313 2,899,072
----------- ----------- ----------- -----------
Costs and expenses:
Oil and gas production ........................... 34,415 27,058 102,688 151,585
Depreciation, depletion and amortization ......... 121,741 77,000 348,020 220,000
Aspen Power Systems expense ...................... 0 0 25,500 0
Selling, general and administrative .............. 164,246 146,322 471,725 449,805
Interest expense ................................. 479 70 479 7,949
----------- ----------- ----------- -----------
Total Costs and Expenses ........................... 320,881 250,450 948,412 829,339
----------- ----------- ----------- -----------
Net income (loss) before taxes ..................... $ (162,597) $ 929,064 $ (297,099) $ 2,069,733
----------- ----------- ----------- -----------
Provision for (recovery of) income taxes
Notes 2 and 6 ...................................... (70,530) 82,165 (70,530) 162,165
----------- ----------- ----------- -----------
Net income (loss) .................................. $ (92,067) $ 846,899 $ (226,569) $ 1,907,568
=========== =========== =========== ===========
Basic earnings (loss) per common share ............. $ (.02) $ .16 $ (.04) $ .35
=========== =========== =========== ===========
Diluted earnings (loss) per common
share .............................................. $ (.02) $ .15 $ (.04) $ .34
=========== =========== =========== ===========
Basic weighted average number of
common shares outstanding .......................... 5,831,800 5,401,678 5,831,800 5,401,678
=========== =========== =========== ===========
Diluted weighted average number of
common shares outstanding .......................... 6,022,414 5,661,678 6,022,414 5,661,678
=========== =========== =========== ===========
The accompanying notes are an integral
part of these statements.
4
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine months ended March 31,
2002 2001
----------- -----------
Cash flows from operating activities:
-------------------------------------
Net income (loss) .................................... $ (226,569) $ 1,907,567
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation, depletion & amortization ............. 348,020 220,000
Amortization of deferred compensation .............. 13,200 13,203
Changes in assets and liabilities:
(Increase) decrease in accounts receivable ......... 329,321 (36,018)
(Increase) decrease in prepaid expense ............. (36,103) 3,616
Increase (decrease) in accounts payable and accrued
expense .......................................... (1,250,950) 279,272
----------- -----------
Net cash provided (used) by operating activities ... (823,081) 2,387,640
----------- -----------
Cash flows from investing activities:
-------------------------------------
Additions to oil & gas properties .................. (628,244) (420,138)
Purchase of office equipment & vehicle ............. (5,285) (21,133)
Sale of idle equipment at cost ..................... 0 6,000
Sale of oil and gas properties ..................... 26,040 0
----------- -----------
Net cash (used) by investing activities ............ (607,489) (435,271)
----------- -----------
Cash flows from financing activities:
-------------------------------------
Repayment of notes payable ......................... 0 (236,746)
----------- -----------
Net cash used in financing activities .............. 0 (236,746)
----------- -----------
Net increase (decrease) in cash and cash equivalents (1,430,570) 1,715,623
Cash and cash equivalents, beginning of year ....... 2,695,583 507,382
----------- -----------
Cash and cash equivalents, end of period ........... $ 1,265,013 $ 2,223,005
----------- -----------
Interest paid ...................................... $ 479 $ 7,949
=========== ===========
Income taxes paid (refund) ......................... $ (70,530) $ 83,000
=========== ===========
The accompanying notes are an integral
part of these statements.
5
ASPEN EXPLORATION CORPORATION
Notes to Consolidated Financial Statements
(Unaudited)
March 31, 2002
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, 2001.
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, 2001.
Note 2 EARNINGS PER SHARE
In February 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 128 ("SFAS No. 128"), addressing
earnings per share. SFAS No. 128 changed the methodology of calculating
earnings per share and renamed the two calculations basic earnings per
share and diluted earnings per share. The calculations differ by
eliminating any common stock equivalents (such as stock options, warrants,
and convertible preferred stock) from basic earnings per share and changes
certain calculations when computing diluted earnings per share. We adopted
SFAS No. 128 in fiscal year 1998.
6
Note 2 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 for the six
months ended March 31, 2002 and 2001:
March 31, 2002 March 31, 2001
----------------------------------- --------------------------------
Per Per
Net Share Net Share
Income Shares Amount Income Shares Amount
---------- ---------- ------- ---------- ---------- ------
Basic earnings per share:
Net income and
share amounts ........... $ (226,569) 5,831,800 $ (.04) $1,907,568 5,401,678 $ .35
Dilutive securities
stock options ........... 776,000 380,000
Repurchased shares ...... (585,386) (120,000)
---------- ---------- ------- ---------- ---------- ------
Diluted earnings per share:
Net income and assumed
share conversion ........ $ (226,569) 6,022,414 $ (.04) $1,907,568 5,661,678 $ .34
========== ========== ======= ========== ========== ======
On December 17, 2001 a director exercised his stock options for 80,000
shares of our common stock at an average exercise price of $0.26 per share.
As consideration for the option shares purchased, the director surrendered
common stock with a fair value equal to the exercise price of the option
shares. The fair value of the shares surrendered was based on a ten-day
average bid price immediately prior to the exercise date. Total shares
surrendered were 28,377. The effect of this transaction is a net increase
to the common stock par value of $260 and a corresponding decrease to
additional paid in capital of $260. The filing of this stock option
exercise with the Securities and Exchange Commission by Form 4 was not
timely filed.
On March 14, 2002 we issued options to purchase 676,000 shares of our
common stock at $0.57 per share to our officers, directors, employees and
consulting accountant as follows:
R. V. Bailey 150,000
Robert A. Cohan 250,000
Robert F. Sheldon 150,000
Ray K. Davis 75,000
Judith L. Shelton 51,000
-------
Total Shares 676,000
=======
Bailey, Sheldon, Davis and Shelton options will vest one-third each on
August 15, 2003, 2004 and 2005. The Cohan options will vest one-fifth each
on August 15, 2003 through 2007.
7
Note 2 EARNINGS PER SHARE (CONTINUED)
The options to the consultant were valued using the fair value method of
SFAS No. 123 as calculated by the Black-Scholes option-pricing model with
the following weighted average assumptions: no dividend yield, expected
volatility of 13.88%, a risk free interest rate of 8.50% and an expected
life of 4.5 years. The resulting compensation of $12,936 will be included
in operating expense as the options vest.
The options to officers, directors and employees were valued using the
intrinsic method of APB No. 25, resulting in no compensation expense
recorded in connection with these options. The adjustment to net income for
compensation expense would be recorded under SFAS No. 123 as the options
vest. Therefore, there is no proforma effect relating to these options
required to be disclosed under SFAS No. 123.
Note 3 SEGMENT INFORMATION
We operate in one industry segment within the United States, oil and gas
exploration and development.
Identified assets by industry are those assets that are used in our
operations in that industry. Corporate assets are principally cash, cash
surrender value of life insurance, furniture, fixtures and vehicles.
During the fourth quarter of 1998, we adopted Statement of Financial
Accounting Standards No. 131, "Disclosures about Segments of an Enterprise
and Related Information" (SFAS No. 131). The adoption of 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, 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, with the exception of the elimination of
the mineral and power plant segments which we are no longer active in and
are not material. 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 sold oil and gas properties for $26,040 and
capitalized $628,244 for the development and acquisition of oil and gas
properties, and the corporate segment which purchased $5,285 of computer
equipment during the period.
8
Note 3 SEGMENT INFORMATION (CONTINUED)
Segment information consists of the following for the nine months ended
March 31:
Oil and Gas Power Plant Corporate Consolidated
----------- ----------- --------- ------------
Revenues:
2002 $ 604,713 $ -0- $ 46,600 $ 651,313
2001 2,826,539 -0- 72,533 2,899,072
Income (loss) from operations:
2002 $ 167,025 $(25,500) $ (368,094) $ (226,569)
2001 2,304,789 -0- (397,221) 1,907,568
Identifiable assets:
2002 $ 2,887,935 $ -0- $ 1,642,431 $ 4,530,366
2001 2,010,456 -0- 2,562,664 4,573,120
Depreciation, depletion and valuation
charged to identifiable assets:
2002 $ (2,256,413) $ -0- $ (41,154) $(2,297,567)
2001 (1,728,589) -0- (140,689) (1,869,278)
Capital expenditures:
2002 $ 628,244 $ -0- $ 5,285 $ 633,529
2001 420,138 -0- 21,133 441,271
Note 4 MAJOR CUSTOMERS
We derived in excess of 10% of our revenue from various sources (oil and
gas sales) as follows:
The Company
-----------
A B C D
- - - -
Year ended:
March 31, 2002 36% -- 32% 12%
March 31, 2001 35% 12% 49% --
Note 5 COMMITMENTS AND CONTINGENCIES
At March 31, 2002 the Company was committed to the following drilling and
development projects in California:
9
Note 5 COMMITMENTS AND CONTINGENCIES (CONTINUED)
1. Two Tehama County, California wells. The average total costs for each
well is estimated at $520,000 with our share of the average net costs
per well approximately $121,000.
2. One Colusa County, California well that is estimated to cost $755,000
with our share of the net costs approximately $70,000, net of prospect
fees.
Note 6 INCOME TAXES
The Company has made no provision for income taxes for the nine month
period ended March 31, 2002 since it utilizes net operating loss
carryforwards. The Company had $583,321 of such carryforwards at June 30,
2001.
On March 26, 2002 we received a refund of overpaid income taxes of $70,530
from the State of California for our fiscal year ended June 30, 2001.
Note 7 SUBSEQUENT EVENTS
On October 4, 2001 the California Power Authority notified our affiliate,
Aspen Power Systems ("APS") that no further action would be taken on APS'
proposal to build and operate a 323 MW natural gas fired electrical
generating plant for the State of California. Consequently, we have written
off a $20,000 advance we provided APS, as well as an additional $5,500
payment made to APS in the quarter ended December 31, 2001. The additional
$5,500 payment along with a like amount from each of the other three
participants in APS was applied to the outstanding obligations of APS at
December 31, 2001. At December 31, 2001 we received approximately $10,000
from APS for the services of our president R. V. Bailey. These services
were administrative in nature and were mainly for negotiations with third
parties for the construction of power plants in California. Future power
plant construction opportunities in California appear remote, given current
economic conditions, and APS has scaled back its efforts and is seeking
other approaches to contracts and financing for power generation facilities
in Solano County, California. There is no assurance these efforts will be
successful.
On April 22, 2002 we closed on the purchase and sales agreement with an
affiliated company to acquire all of its interest in 8 producing gas wells
in Northern California. The purchase is effective January 1, 2002. The
purchase price of these properties was approximately $118,000. We acquired
60% of the working interest in these properties for $66,075. The balance of
40% was acquired by affiliated investors for $51,925.
On April 27, 2002 we commenced drilling operations on the Porter 26-2, a
6800 foot exploratory gas well in Tehama County, California. We have
committed to drill the Porter 26-2 and two additional wells in Tehama and
Colusa Counties as follows:
10
Note 7 SUBSEQUENT EVENTS (CONTINUED)
Estimated Our Estimated
Well Spud Date Total Depth Dry Hole Cost
---- --------- ----------- -------------
Porter 26-2 4-27-02 6800 feet $ 80,000
Leal 22-1 5-15-02 5600 feet 57,000
Kuppenbender 20-3 5-15-02 9000 feet 25,000
---------
$ 162,000
=========
Results of these proposed drilling operations will be disclosed in future
reports.
11
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, 2001, 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
-------------------------------
March 31, 2002 as compared to March 31, 2001
--------------------------------------------
At March 31, 2002 current assets were $1,579,675 and current liabilities were
$229,995 and we had positive working capital of $1,349,680 compared to current
assets of $3,303,463 at June 30, 2001 and current liabilities of $1,480,947 at
the same date, resulting in working capital at June 30, 2001 of $1,822,516. Our
current assets decreased by 52%, while current liabilities decreased by 84% from
June 30, 2001 to March 31, 2002 for several reasons.
Our current assets decreased primarily because cash and cash equivalents
decreased from approximately $2.7 million to approximately $1.3 million.
Accounts receivable - trade decreased by about 56% because of the lower
prices received for oil and gas production, and decreased production
volumes experienced during the nine months ended March 31, 2002.
Our current liabilities decreased to $230,000 at March 31, 2002, from
approximately $1.5 million at June 30, 2001. This reduction was due to a
number of factors, including a decrease in accounts payable of $963,000 due
to a decrease in drilling activity caused by the completion of planned
drilling projects, a decrease of $287,000 in advance payments received from
joint owners also caused by project completions at March 31, 2002.
We anticipate that our current assets will be sufficient to pay our current
liabilities as long as our oil and 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 oil and gas production.
12
During the nine month period ending March 31, 2002, we experienced a sharp
decline in production and prices received for the natural gas we produced during
that period. At June 30, 2001, we received an average of $10.16 per MMBTU. At
March 31, 2002 our price per MMBTU had been reduced to approximately $2.38 per
MMBTU, a 77% decline. During the month of April 2002 we will receive an average
price of $3.30 per MMBTU, a 39% improvement, but substantially below year ago
prices which averaged $8.87 per MMBTU.
In conjunction with a decline in prices we have also experienced a decline in
production volumes for the period. For the nine months ended March 31, 2002 we
produced approximately 293,000 MMBTU of gas compared to approximately 171,000
MMBTU for the nine months ended March 31, 2002, a 41% decline.
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.
Although our drilling and development plans have not been finalized for the
coming year, at March 31, 2002 we have spudded one well and are committed to
drill 2 additional wells at an estimated dry hole cost to us of approximately
$162,000, with the balance (approximately $850,000) to be paid by joint owners
in the properties, including certain affiliated investors. For the nine months
ended March 31, 2002 we invested $600,000 in our oil and gas properties compared
to approximately $420,000 for the nine month period in the preceding fiscal
year. We anticipate additional drilling will occur in fiscal 2002.
We believe that internally generated funds will be sufficient to finance our
drilling and operating expenses for the next twelve months.
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 there from 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.
13
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. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to be Disposed of." Under SFAS No. 121, 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. 121 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.
CONTRACTUAL OBLIGATIONS
We had contractual obligations as of March 31, 2002. The following table lists
our significant liabilities at March 31, 2002:
Payments Due By Period
---------------------------------------------------
Less than After
Contractual Obligations 1 year 2-3 years 4-5 years 5 years Total
----------------------- ------ --------- --------- ------- -----
Operating leases $26,300 $52,600 $52,600 $ -0- $131,500
-------- --------- --------- ----- --------
Total contractual
cash obligations $26,300 $52,600 $52,600 $ -0- $131,500
======== ========= ========= ===== ========
We lease corporate offices in Denver, Colorado with support offices in Castle
Rock, Colorado and Bakersfield, California. The Denver office lease expires
December 31, 2002, the Bakersfield office lease expires February 28, 2003 and
the Castle Rock office is leased on a month to month basis. Combined yearly
lease payments are approximately $26,300.
In addition to office leases, we are responsible for various compressor rentals
located on our California producing properties. These leases are on a month to
month basis and total approximately $21,500 per year.
14
Results of Operations
---------------------
March 31, 2002 Compared to March 31, 2001
-----------------------------------------
For the nine months ended March 31, 2002 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 includes income from management fees, for the nine
months ended March 31, 2002 decreased approximately $2,195,000 from $2,800,000
to $605,000, a 78% decrease. This decrease reflects an erosion of prices and
reduced production volumes in California. Our share of sales of oil and gas for
the nine month period ended March 31, 2002 were 2410 barrels of oil and
approximately 171,000 MMBTU of gas with the price received for oil at $19.32 per
barrel and $2.70 per MMBTU for gas. This is a decrease in total oil production
compared to the 4028 barrels of oil produced in the nine months ended March 31,
2001, and a decrease in natural gas production of 122,000 MMBTU when compared to
the approximately 293,000 MMBTU of gas production achieved during the nine
months ended March 31, 2001. As discussed in Liquidity and Capital Revenues, a
significant factor resulting in the substantial decrease in revenues during the
last nine months of fiscal 2002 was a decrease in the prices received for our
production when compared to prices of $26.90 and $8.87 received for oil and gas
respectively during the first nine months of fiscal 2002.
Oil and gas production costs decreased $48,897 when compared to the last nine
month period, from $151,585 to $102,688. Production costs decreased
approximately $62,000 due to the elimination of non-recurring workover costs for
recompleting wells in upper producing zones. Production costs increased
approximately $13,000 because of the addition of new wells and compression costs
associated with older producing wells, as well as increased water production and
workover costs associated with two oil wells which were sold during the third
quarter of 2002.
Depletion, depreciation and amortization increased $128,000 or 58% for the nine
month period, which is our best estimate of what the full year cost will be.
Selling, general and administrative expense increased approximately 5% from
$449,800 to $471,725 for the nine months ended March 31, 2002. This increase is
primarily due to salary and office rental increases, and was offset by the
receipt of approximately $10,000 from Aspen Power Systems for the services of
our president R. V. Bailey.
As a result of our operations for the nine months ended March 31, 2002, we ended
the period with a net loss of $226,600 after taxes compared to net income of
$1,908,000 for the year earlier. This loss of approximately $226,600 is due to a
decrease in production and the price received for our oil and gas as discussed
earlier as well as the fact that our depletion costs rose substantially during
the nine month period ending March 31, 2002.
Interest and other income decreased approximately $26,000 to $46,600 and is due
to our maintaining a lower average balance of funds in our invested cash
accounts, thereby reducing our interest income by $11,900, and a decrease in
funds received from Aspen Power Systems of $12,800 from $23,200 to $10,400.
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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/ R. V. Bailey
-------------------------------
By: R. V. Bailey,
May 10, 2002 Chief Executive Officer,
Principal Financial Officer
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