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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------------------
FORM 10-KSB
(Mark One)
[ X ] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934.
For the fiscal year ended June 30, 2003
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934.
For the transition period from to
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Commission file number: 001-12531
ASPEN EXPLORATION CORPORATION
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(Name of small business issuer in its charter)
Delaware 84-0811316
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(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
2050 S. Oneida St., Suite 208
Denver, Colorado 80224-2426
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(Address of principal executive offices) (Zip Code)
Issuer's telephone number: (303) 639-9860
Securities registered pursuant to Section 12(b) of the Exchange Act: None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $0.005 par value
Check whether the issuer (1) filed all reports required to be filed by
Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such
shorter period that the registrant was required to file such reports), and (2)
has been subject to such filing requirements for the past 90 days.
Yes X No
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Check if there is no disclosure of delinquent filers in response to Item
405 of Regulation S-B contained in this form, and no disclosure will be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-KSB
or any amendment to this Form 10-KSB. Yes X No
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Aspen's revenues for the fiscal year ended June 30, 2003 were $1,323,673.
At September 22, 2003, the aggregate market value of the shares held by
non-affiliates was approximately $2,269,314. The aggregate market value was
calculated by multiplying the mean of the closing bid and asked prices ($0.60)
of the common stock of Aspen on the Over-the-Counter Bulletin Board listing for
that date, by the number of shares of stock held by non-affiliates of Aspen
(3,782,190).
At September 22, 2003, there were 5,863,828 shares of common stock (Aspen's
only class of voting stock) outstanding.
Transitional Small Business Disclosure Format (check one): Yes No X
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PART I
ITEM 1. BUSINESS
-----------------
Because we want to provide you with more meaningful and useful information,
this Annual Report on Form 10-KSB contains certain "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 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-KSB.
Summary of Our Business
Aspen was incorporated under the laws of the State of Delaware on February
28, 1980 for the primary purpose of acquiring, exploring and developing oil and
gas and other mineral properties. Our principal executive offices are located at
2050 S. Oneida St., Suite 208, Denver, Colorado 80224-2426. Our telephone number
is (303) 639-9860, and our facsimile number is 303-639-9863. Our websites are
WWW.ASPENEXPLORATION.COM and WWW.ASPNX.COM and our email address is
AECORP2@QWEST.NET. We are currently engaged primarily in the exploration and
development of oil and gas properties in California. We also had a 25% interest
in Aspen Power Systems, LLC, a company we incorporated to investigate, finance,
and construct electrical power generation projects. Effective December 31, 2002,
Aspen Power Systems, LLC wound up its affairs and ceased operations. We have
also acquired some acreage in Colorado for a possible coalbed methane project.
Oil and Gas Exploration and Development. Our major emphasis has been
participation in the oil and gas segment, acquiring interests in producing oil
or gas properties and participating in drilling operations. We engage in a broad
range of activities associated with the oil and gas business in an effort to
develop oil and gas reserves. With the assistance of our management, independent
contractors retained from time to time by Aspen, and, to a lesser extent,
unsolicited submissions, we have identified and will continue to identify
prospects that we believe are suitable for drilling and acquisition.
Currently, our primary area of interest is in the state of California. We
have acquired a number of interests in oil and gas properties in California, as
described below in more detail. In addition, we also act as operator for most of
our producing wells and receive management fees for these services.
Aspen has information on hand which indicates coal deposits exist under the
approximate 2,074 acres of leases which Aspen has obtained in Arapahoe and
Elbert Counties, Colorado. We do not know if it is possible or economically
feasible to produce any coalbed methane which may exist on these leases. The
leases are paid-up oil and gas leases (which include coalbed methane) with a
three year term and are renewable for an additional two years. We do not intend
to proceed with exploration and development of these properties on our own,
rather, we intend to farm out the project to another party. To date, we have had
no interest in a farmout of this project by industry partners, and we intend to
let these leases expire on their own terms at the end of their primary term.
Power Generation. In 1999, we formed a subsidiary named Aspen Power
Systems, LLC ("APS"), a Colorado limited liability company to provide an
opportunity for Aspen to participate in the growing demand for electrical power
generated by turbines. Our objectives for APS were to seek opportunities or
situations where our analysis indicated that a gas turbine generation plant
could be constructed and operate profitably. Any plant construction would
require a significant amount of capital for property acquisition, permitting,
engineering and design, and construction. Neither Aspen nor the other owners of
APS were able to provide this required capital. Consequently, any such
activities would have required the availability of funds from third parties, and
we were unable to obtain these funds. Aspen owned a 25% interest in APS.
2
Although APS attempted to undertake projects with other power producers
(and received reimbursement of $246,000 in fees and expenses relating to our
Solano, California, project from a third party), APS was unable to initiate any
economic projects. On December 31, 2002 APS ceased operations and filed its
final tax returns. See Item 12 for more information regarding APS.
Company Strategy:
At the present time, we cannot finance our oil and gas acquisitions and
drilling activities solely through our own resources. Consequently, we identify
prospects or production to acquire and drill prospects, and seek other industry
investors who are willing to participate in these activities with us. We
frequently retain a promotional interest in these prospects, but generally we
have to finance a portion (and sometimes a significant portion) of the
acquisition and drilling costs. We have in the past acquired interests in
producing properties by issuing shares of our common stock, but because of the
current low price of our stock, it has become more difficult and expensive to do
so.
Where we acquire an interest in acreage on which exploration or development
drilling is planned, we will seldom assume the entire risk of acquisition or
drilling. Rather, we prefer to assess the relative potential and risks of each
prospect and determine the degree to which we will participate in the
exploration or development drilling. Generally, we have determined that it is
more beneficial to invite industry participants to share the risk and the reward
of the prospect by financing some or all of the costs of drilling contemplated
wells. In such cases, we may retain a carried working interest, a reversionary
interest, or may be required to finance all or a portion of our proportional
interest in the prospect. Although this approach reduces our potential return
should the drilling operations prove successful, it also reduces our risk and
financial commitment to a particular prospect.
Conversely, we may from time to time participate in drilling prospects
offered by other persons if we believe that the potential benefit from the
drilling operations outweighs the risk and the cost of the proposed operations.
This approach allows us to diversify into a larger number of prospects at a
lower cost per prospect, but these operations (commonly known as "farm-ins") are
generally more expensive than operations where we offer the participation to
others (known as "farm-outs"). As of this writing, we have participated in the
drilling of two farm-in wells.
Principal Products Produced and Services Rendered. Our principal products
during fiscal 2003 were crude oil and natural gas. Crude oil and natural gas are
generally sold to various entities, including pipeline companies, which usually
service the area in which our producing wells are located. In the fiscal year
ended June 30, 2003, crude oil and natural gas sales and revenues from operating
oil and gas properties accounted for $1,313,821, or 99% of our total revenues;
while $9,852, or 1%, was from interest and other income.
Distribution Methods of the Products or Services. We are not involved in
the distribution aspect of the oil and gas industry.
Status of any Publicly Announced New Products or Services. We do not have a
new product or service that would require the investment of a material amount of
our assets or which we believe is material to our business. Therefore, we have
not made a public announcement of nor have we made information otherwise public
about any such product or service.
Competitive Business Conditions: The exploration for, and development,
production and acquisition of, oil, gas, precious metals and other minerals are
subject to intense competition, as is the production and sale of electrical
power. The principal methods of compensation for the acquisition of oil and gas
and other mineral properties are the payment of:
(i) cash bonuses at the time of the acquisition of leases;
(ii) delay rentals and the amount of annual rental payments;
(iii) advance royalties and the use of differential royalty rates; and
(iv) the stipulations requiring exploration and production commitments by
the lessee.
Some of our current competitors, and many of our potential competitors in
the oil and gas industry have vast experience, are larger and have significantly
greater financial resources, existing staff and labor forces, equipment, and
other resources than we do. Consequently, these competitors may be in a better
position to compete for oil and gas projects.
3
In addition, the availability of a ready market for oil and gas will depend
upon numerous factors beyond our control, including the extent of domestic
production and imports of oil and gas, proximity and capacity of pipelines, and
the effect of federal and state regulation of oil and gas sales, as well as
environmental restrictions on exploration and usage of oil and gas. Further, we
expect that competition for leasing of oil and gas prospects will become even
more intense in the future. We have a minimal competitive position in the oil
and gas industry.
Sources and Availability of Raw Materials: To conduct business, we depend
on such items as drilling rigs and other equipment, casing pipe, drilling mud
and other supplies, core drilling equipment, and other equipment necessary for
our operations. Such items have been commonly available from a number of
sources. Although we foresee no short supply or difficulty in acquiring any
equipment relevant to the conduct of business, we cannot offer any assurances
that these items will be available or that we will be able to acquire the items
on economically feasible terms.
Dependence Upon One or a Few Major Customers: We generally sell our oil and
gas production to a limited number of companies. In fiscal 2003 we obtained more
than 10% of our revenues from sales to Calpine Corporation and Enserco Energy,
Inc.; in 2002 more than 10% of our revenues derived from ConocoPhillips, Calpine
Corporation and Slawson Corporation. We do not believe the loss of these
customers would adversely impact our revenues because we believe that oil and
gas sales are primarily market driven and are not dependent on particular
purchasers. Consequently, we believe that substitute purchasers would be
available based on the widespread uses of and the need for oil and gas.
Patents, Trademarks, Licenses, Franchises, Concessions, Royalty Agreements
or Labor Contracts (Including Duration). We do not own any patents, licenses,
franchises, or concessions except oil, gas and other mineral interests granted
by governmental authorities and private landowners. We received a trademark
registration (serial no. 74-396,919 registered on March 1, 1994) for our
corporate logo. The registration is for a term of ten years. To maintain the
registration for its entire term we filed an affidavit of commercial use on
February 21, 2000.
Need for Governmental Approval of Principal Products or Services. We do not
need to seek government approval of our principal products.
Effect of Existing or Probable Governmental Regulation. Oil and gas
exploration and production are open to significant governmental regulation
including worker health and safety laws, employment regulations and
environmental regulations. Operations that occur on public lands may be subject
to further regulation by the Bureau of Land Management, the U.S. Army Corps of
Engineers, or the U.S. Forest Service as well as other federal and state
agencies.
Estimate of Amounts Spent on Research and Development Activities. We have
not engaged in any material research and development activities since our
inception.
Costs and Effects of Compliance with Environmental Laws (federal, state and
local). Because we are engaged in extracting natural resources, our business is
subject to various federal, state and local provisions regarding environmental
and ecological matters. Therefore, compliance with environmental laws may
necessitate significant capital outlays, affect our earnings potential, and
cause material changes in our current and proposed business activities.
At the present time, however, the environmental laws do not materially
hinder nor adversely affect our business. Capital expenditures relating to
environmental control facilities have not been material to our operations since
our inception.
Employees.
At June 30, 2003, we employed two full-time persons. We also employ
independent contractors and other consultants, as needed.
4
ITEM 2. PROPERTIES
-------------------
General Information:
We have a significant amount of information regarding the proven developed
and undeveloped oil and gas reserves which can be found in below in this Item 2
as well as in the notes to our financial statements.
Drilling and Acquisition Activity:
During the fiscal year ended June 30, 2003 we participated in the drilling
of 8 gross (1.45 net) wells, of which 7 gross (1.22 net) were completed as gas
wells and 1 was a dry hole. Of the 8 wells drilled, 3 operated wells (1 dry hole
and 2 gas wells) were drilled in the Sour Grass Prospect, 1 operated gas well
was drilled in the Millar Field, 2 operated gas wells were drilled in the Kirk
Buckeye Field, 1 non-operated gas well was drilled in the South Dixon Field and
1 non-operated gas well was drilled in the West Grimes Field.
In addition to the drilling activity, 9 operated gas wells were acquired in
the West Grimes Field in Colusa County, California and 1 shut-in gas well was
acquired in Sutter County, California.
West Grimes Field, Colusa County, California
--------------------------------------------
Aspen acquired nine shut-in gas wells located in the West Grimes Field,
Colusa County, California, approximately 100 miles northeast of Sacramento. All
of these shut-in gas wells were tested; nine of them have proven productive and
one tested gas at sub-commercial rates and was plugged and abandoned. The nine
productive wells have been equipped and hooked up via 5 miles of newly
constructed pipeline facilities. Gas sales from these wells commenced in late
March and are currently 800 MCFPD. Several of these wells have additional gas
potential in behind-pipe zones, which have not yet been perforated. Aspen has
also acquired in excess of 5,000 acres in this area which includes highly
prospective lands for additional exploratory and development drilling. Prior to
selection of the drill sites, an extensive 3-D seismic program will be acquired
in October-November 2003 to better define drilling targets. Quality targets will
be identified and prepared for the 2004 drilling season. Aspen has a 21.0%
operated working interest in this prospect
Millar Field, Yolo County, California
-------------------------------------
The Pope Bypass #1-5 well located in Yolo County, California, approximately
50 miles southwest of Sacramento, was drilled to a depth of 7,800 feet and
encountered approximately 70 feet of potential net gas pay in several intervals
of the Winters formation. The Winters sands in this area are extremely porous
and permeable, and exhibit excellent electric log characteristics. One 2 foot
interval (top of a 6 foot sand) was perforated and tested at a stabilized rate
of 2,161 MCFPD of natural gas with a flowing tubing pressure of 2,780 psig and a
flowing casing pressure of 2,800 psig. The shut in pressures were approximately
2,810 psig, indicating a very high permeability reservoir with slight pressure
drawdown during the flow period. Aspen has a 27.75% operated working interest in
this well. Gas sales commenced on June 20th and the well is currently flowing at
a stable rate of 950 MCFPD with a flowing tubing pressure of 2,450 psig and a
flowing casing pressure of 2,700 psig.
Feather River Prospect, Sutter County,
--------------------------------------
Aspen recently completed a 12 1/2 square mile 3-D seismic survey over
leased acreage in Sutter County, California. This data is currently being
processed and will be interpreted over the next few months. It is hopeful that
analysis of the data will yield several exciting shallow gas targets (2,500
feet) although initial indications show only a few small gas anomalies. On a
positive note, Aspen has acquired 2 gas wells located on this property. One of
these wells tested at 3,000 MCFPD and will probably commence gas sales in
November 2003 at a rate of 500 MCFPD after pipeline construction is completed.
The other well commenced gas sales in mid-August and is producing a steady 200
MCFPD with no pressure decline. Aspen has a 20.0% operated working interest in
this project.
Kirk-Buckeye Field, Colusa County, California
---------------------------------------------
Aspen has drilled 4 gas wells out of 4 attempts in this field during the
last 2 fiscal years. These wells produce from multiple horizons in the Forbes
formation from depths ranging from 7,500 feet to 9,500 feet. Aspen will commence
drilling on its Sac Outing Farms #31-3 well in October 2003. This well will be
drilled to a depth of 9,400 feet to test multiple Forbes objectives. Aspen has
operated working interests in these wells ranging from approximately 15% to 36%.
5
Sour Grass Prospect, Tehama County, California
----------------------------------------------
The Sour Grass prospect area is a 2,800 acre play located in southern
Tehama County. In this project, for which a 7.5 square mile area 3-D seismic
survey has been acquired, Aspen has a 23.33% operated working interest. There is
also abundant well data for the area as well as previous 2-D seismic survey
information. Five to ten prospective locations have been identified through an
analysis of the data, with numerous pay zones from 2,000 to 6,000 feet in depth.
Drilling of the first five wells in this project resulted in four producers and
one dry hole. We may drill additional wells in this area next year.
Denverton Creek Field, Solano County, California.
-------------------------------------------------
For the past three years, we have been the recipient of the California
Division of Oil, Gas, and Geothermal Resources (CDOGGR) "Outstanding Lease
Maintenance Award" for our operations in the Denverton Creek gas field. CDOGGR
gives this award to operators who not only meet, but exceed, the requirements
for producing well operations set by CDOGGR.
Aspen did not drill any wells in this field during the 2003 fiscal year.
Aspen has drilled a total of 12 productive gas wells out of 15 attempts, an 80%
success rate. Cumulative gross production from the field is in excess of 9.5 BCF
of natural gas. The field is productive from 10 separate horizons ranging in
depth from 9,000 feet to 12,000 feet. Aspen has extended the former field limits
by 2 miles to the northeast and discovered new pay horizons. Current gross
production is in excess of 700 MCFPD of high quality natural gas (1085 BTU) with
numerous behind-pipe zones in many of the wells.
Drilling Activity:
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The following table sets forth the results of our drilling activities
during the fiscal years ended June 30, 2001, 2002 and 2003:
Drilling Activity
-----------------
Gross Wells Net Wells
----------- ---------
Year Total Producing Dry Total Producing Dry
---- ----- --------- --- ----- --------- ---
2001 Exploratory 10 6 4 1.22 .58 .64
2002 Exploratory 6 4 2 1.32 .98 .34
2003 Exploratory 8 7 1 1.45 1.22 .23
6
Production Information:
Net Production, Average Sales Price and Average Production Costs (Lifting).
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The table below sets forth the net quantities of oil and gas production (net of
all royalties, overriding royalties and production due to others) attributable
to Aspen for the fiscal years ended June 30, 2003, 2002, and 2001, and the
average sales prices, average production costs and direct lifting costs per unit
of production.
Years Ended June 30,
--------------------
2003 2002 2001
---- ---- ----
Net Production
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Oil (Bbls) 768 3,055 5,206
Gas (MMcf) 248 227 377
Average Sales Prices
--------------------
Oil (per Bbl) $ 26.13 $ 20.20 $ 26.64
Gas (per Mcf) $ 4.23 $ 2.78 $ 9.20
Average Production Cost1
-----------------------=
Per equivalent
Bbl of oil $ 12.83 $ 11.21 $ 7.53
Average Lifting Costs2
----------------------
Per equivalent
Bbl of oil $ 3.61 $ 2.86 $ 1.65
1 Production costs include all operating expenses, depreciation, depletion and
amortization, lease operating expenses and all associated taxes.
2 Direct lifting costs do not include impairment expense, ceiling write-down, or
depreciation, depletion and amortization.
7
Productive Wells and Acreage:
Gross and Net Productive Gas Wells, Developed Acres, and Overriding Royalty
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Interests.
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Leasehold Interests - Productive Wells and Developed Acres: The tables
below sets forth Aspen's leasehold interests in productive and shut-in gas
wells, and in developed acres, at June 30, 2003:
Producing and Shut-In Wells
---------------------------
Gross Net1
----- ----
Prospect Gas Gas
-------- --- ---
California:
Armstrong 17-4 1 0.36000
Balsdon 3-21 1 0.05983
Balsdon 6 1 0.04134
Cygnus 2 1 0.05125
Deane 1 1 0.12938
Dragon 1 1 0.28350
Eastby 36-2 1 0.07770
Elektra 1 1 0.07560
Emigh 34-1 1 0.28800
Emigh 35-1 1 0.28525
Emigh 35-2 1 0.32800
Emigh 35-3 1 0.11900
Firestone 1-10 1 0.03850
Gay Unit 2 0.42000
Grey Wolf 1 1 0.18000
HSRCC 1 1 0.01857
Houghton 25-1 1 0.07770
Johnson Unit 4 0.84000
Kuppenbender 20-2 1 0.19950
Kuppenbender 20-3 1 0.15200
Leal 22-1 1 0.23334
McCullough 36-1 1 0.19750
NL&F 26-1 1 0.23334
Pinheiro 1-10 1 0.01890
Pinheiro 2-10 1 0.01890
Pope Bypass 1-5 1 0.27750
Porter 26-2 1 0.23334
Quarre 30-2 1 0.23334
Sanborn 3-3 1 0.12762
Sanborn 4-10 1 0.02979
Sciortino 1-7 1 0.03000
Tiahrt 1-4 1 0.03617
Verona Farms 1 1 0.20000
West Grimes Unit 14 2 0.42000
West Grimes Unit 15 3 0.63000
West Grimes Unit 16 2 0.42000
Strain Ranches 16-3 1 0.21000
Strain Ranches 17-1 1 0.21000
Zimmerman 1-24 1 0.23334
TOTAL 47 8.01826
1 A net well is deemed to exist when the sum of fractional ownership working
interests in gross wells equals one. The number of net wells is the sum of the
fractional working interests owned in gross wells expressed as whole numbers and
fractions thereof.
8
Developed Acreage Table
-----------------------
Aspen's Developed Acres1
Prospect Gross2 Net3
-------- ----- ---
California:
Denverton Creek 1,271 207
Feather River 320 64
Firestone 1-10 160 6
Grey Wolf 1 120 22
Kirk Buckeye 800 229
Malton Black
Butte Field 2,023 321
McCullough 36-1 583 115
Phillips Acquisition 1,280 71
Pope Bypass 1-5 120 33
Sour Grass 1,184 276
West Grimes 1,920 403
----- ------
TOTAL 9,781 747
===== ======
1 Consists of acres spaced or assignable to productive wells.
2 A gross acre is an acre in which a working interest is owned. The number of
gross acres is the total number of acres in which a working interest is owned.
3 A net acre is deemed to exist when the sum of fractional ownership working
interests in gross acres equals one. The number of net acres is the sum of the
fractional working interests owned in gross acres expressed as whole numbers and
fractions thereof.
Royalty Interests in Productive Wells and Developed Acreage: The following
tables set forth Aspen's royalty interest in productive gas wells and developed
acres at June 30, 2003:
Overriding Royalty Interests
----------------------------
Productive
Wells Gross
Prospect Interest(%) Gas Acreage1
-------- ----------- --- --------
California:
Denverton Creek 1.142816 1 80
Malton Black Butte 7.500000 2 645
Grimes Gas 0.101590 1 615
--- -----
TOTAL 4 1,340
=== =====
1 Consists of acres spaced or assignable to productive wells.
9
Undeveloped Acreage:
Leasehold Interests Undeveloped Acreage: The following table sets forth Aspen's
leasehold interest in undeveloped acreage at June 30, 2003:
Undeveloped Acreage
-------------------
Gross Net
----- ---
California:
Denverton Creek 514 69
Orion 1,677 335
Sacreiter 245 245
Sour Grass 1,376 321
West Grimes 3,273 670
------ ------
Sub Total 7,085 1,640
Colorado:
Coalbed Methane Prospect 2,074 2,074
------ ------
TOTAL 9,159 3,714
======= ======
Delivery Commitments:
We are not obligated to provide a fixed and determinable quantity of oil
and gas in the future under existing contracts and agreements.
Drilling Commitments:
At June 30, 2003, we were committed to the following drilling, development
and seismic projects in California:
Project Aspen Cost
------- ----------
Mengali-Durst #22-1 $ 40,000
Sac Outing Farms #31-3 44,000
West Grimes 3-D 100,000
Verona Pipeline 70,000
---------
Total $ 254,000
---------
Reserve Information - Oil and Gas Reserves:
Cecil Engineering, Inc. evaluated our oil and gas reserves attributable to
our properties at June 30, 2003. Reserve calculations by independent
petroleum engineers involve the estimation of future net recoverable
reserves of oil and gas and the timing and amount of future net revenues to
be received therefrom. Those estimates are based in numerous factors, many
of which are variable and uncertain. Reserve estimators are required to
make numerous judgments based upon professional training, experience and
educational background. The extent and significance of the judgments in
them are sufficient to render reserve estimates of future events, actual
production determinations involve estimates inherently imprecise, since
reserve revenues and operating expenses may not occur as estimated.
Accordingly, it is common for the actual production and revenues later
received to vary from earlier estimates. Estimates made in the first few
years of production from a property are generally not as reliable as later
estimates based on a longer production history. Reserve estimates based
upon volumetric analysis are inherently less reliable than those based on
lengthy production history. Also, potentially productive gas wells may not
generate revenue immediately due to lack of pipeline connections and
potential development wells may have to be abandoned due to unsuccessful
completion techniques. Hence, reserve estimates may vary from year to year.
10
Estimated Proved Reserves/ Developed and Undeveloped Reserves: The
following tables set forth the estimated proved developed and proved undeveloped
oil and gas reserves of Aspen for the years ended June 30, 2003 and 2002. See
Note 9 to the Consolidated Financial Statements and the above discussion.
Estimated Proved Reserves
-------------------------
Proved Reserves Oil (Bbls) Gas (Mcf)
--------------- ---------- ---------
Estimated quantity, June 30, 2001 13,000 2,243,000
--------- ---------
Revisions of previous estimates 2,000 (115,000)
Discoveries 0 258,000
Production (3,000) (227,000)
Purchased reserves 0 51,000
Sold reserves (1,000) 0
--------- ---------
Estimated quantity, June 30, 2002 11,000 2,210,000
Revisions of previous estimates (1,000) (184,000)
Discoveries 0 481,000
Production (1,000) (248,000)
Purchased reserves 0 221,000
Sold reserves (6,000) 0
--------- ---------
Estimated quantity, June 30, 2003 3,000 2,480,000
========= =========
Developed and Undeveloped Reserves
----------------------------------
Developed Undeveloped Total
--------- ----------- -----
Oil (Bbls)
June 30, 2002 7,000 4,000 11,000
June 30, 2003 - 3,000 3,000
Gas (Mcf)
June 30, 2002 482,000 1,728,000 2,210,000
June 30, 2003 655,000 1,825,000 2,480,000
For information concerning the standardized measure of discounted future
net cash flows, estimated future net cash flows and present values of such cash
flows attributable to our proved oil and gas reserves as well as other reserve
information, see Note 9 to the Consolidated Financial Statements.
Oil and Gas Reserves Reported to Other Agencies: We did not file any
estimates of total proved net oil or gas reserves with, or include such
information in reports to, any federal authority or agency since the beginning
of the fiscal year ended June 30, 2003.
Title Examinations: Oil and Gas: As is customary in the oil and gas
industry, we perform only a perfunctory title examination at the time of
acquisition of undeveloped properties. Prior to the commencement of drilling, in
most cases, and in any event where we are the Operator, a thorough title
examination is conducted and significant defects remedied before proceeding with
operations. We believe that the title to our properties is generally acceptable
to a reasonably prudent operator in the oil and gas industry. The properties we
own are subject to royalty, overriding royalty and other interests customary in
the industry, liens incidental to operating agreements, current taxes and other
burdens, minor encumbrances, easements and restrictions. We do not believe that
any of these burdens materially detract from the value of the properties or will
materially interfere with our business.
We have purchased producing properties on which no updated title opinion
was prepared. In such cases, we have retained third party certified petroleum
landmen to review title.
11
Office Facilities:
Our principal office is located in Denver, Colorado. We also have an office
located in 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 to December 31, 2003 for a lease rate of
$1,261 per month.
We also subleased from R.V. Bailey, our vice president, a portion of an
office building owned by Mr. Bailey in Castle Rock, Colorado on a month-to-month
basis for $500 per month. This sublease terminated on April 30, 2003 per the
revised employment agreement with Mr. Bailey. See Item 10, R. V. Bailey
Employment Contract.
We pay $730 per month for the Bakersfield, California office, which
consists of approximately 546 square feet. The Bakersfield, California lease
expires February 8, 2006.
ITEM 3. LEGAL PROCEEDINGS
--------------------------
We are not subject to any pending or, to our knowledge, threatened, legal
proceedings.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
------------------------------------------------------------
No matters were presented to security holders for a vote during the year
ended June 30, 2003, or any subsequent period.
PART II
ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
-----------------------------------------------------------------
Market Information:
Our common stock is quoted on the Over-the-Counter Bulletin Board ("OTCBB")
under the symbol "ASPN". The quotations reflect inter-dealer prices without
retail mark-up, mark-down or commission and may not reflect actual transactions.
The OTCBB adopted new rules that result in companies not current in their
reporting requirements under the Securities Exchange Act of 1934 being removed
from the quotation service. At June 30, 2002 and 2003, we believe that we were
in full compliance with these rules.
Quarter Ended
Sept., Dec., March, June 30,
2002 2002 2003 2003
---- ---- ---- ----
Common Stock ("ASPN")
High $.58 $.38 $.52 $.86
Low $.21 $.31 $.34 $.40
Quarter Ended
Sept., Dec., March, June 30,
2001 2001 2002 2002
---- ---- ---- ----
Common Stock ("ASPN")
High $1.35 $1.00 $.73 $.73
Low $0.77 $0.63 $.54 $.55
12
Holders:
As of June 30, 2002 and 2003, there were approximately 1,197 and 1,182
holders of record of our Common Stock, respectively. This does not include an
indeterminate number of persons who hold our Common Stock in brokerage accounts
and otherwise in 'street name.'
13
Dividends:
We have never declared or paid a cash dividend on our Common Stock. We
presently intend to retain our earnings to fund development and growth of our
business. Decisions concerning dividend payments in the future will depend on
income and cash requirements.
Holders of common stock are entitled to receive such dividends as may be
declared by Aspen's Board of Directors. There were no dividends declared by the
Board of Directors during the fiscal year ended June 30, 2003, or subsequently,
and we have paid no cash dividends on its common stock since inception. There
are no contractual restrictions on our ability to pay dividends to our
shareholders.
Securities authorized for issuance under equity compensation plans.
The following is provided with respect to compensation plans (including
individual compensation arrangements) under which equity securities are
authorized for issuance as of the fiscal year ending June 30, 2003.
-----------------------------------------------------------------------------------------------
Equity Compensation Plan Information (1)
-----------------------------------------------------------------------------------------------
Plan Category and Number of Weighted-average Number of securities
Description Securities to be exercise price of remaining available for
issued upon outstanding future issuance under equity
exercise of options, warrants, compensation plans
outstanding and rights (excluding securities
options, reflected in column (a))
warrants, and
rights
(a) (b) (c)
-----------------------------------------------------------------------------------------------
Equity compensation
plans approved by
security holders -0- $-0- -0-
-----------------------------------------------------------------------------------------------
Equity compensation
plans not approved
by security holders 676,000 $0.57 NA
-----------------------------------------------------------------------------------------------
Total 676,000 $0.57 NA
--------------------------------------------------------------------------------------------
(1) This does not include options held by management and directors that
were not granted as compensation. In each case, the disclosure refers
to options or warrants unless otherwise specifically stated.
14
Recent Sales of Unregistered Securities -- Item 701 Disclosure.
The following sets forth information regarding sales of unregistered securities
within the past two years as required by Item 701 of Regulation S-B.
----------------------- ------------- ------------- ------------ ---------------- -----------
Name and Principal Date Number of Offering Registration Option
Position Common Price Exemption Exercise
Shares Sold ($) Price Per
(#) Share ($)
----------------------- ------------- ------------- ------------ ---------------- -----------
R. F. Sheldon, 12/17/2001 80,000 20,800 Rule 144 .26
director, options
exercised
----------------------- ------------- ------------- ------------ ---------------- -----------
Total 80,000 20,800 .26
----------------------- ------------- ------------- ------------ ---------------- -----------
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION OR PLAN OF
-------------------------------------------------------------------------------
OPERATION
---------
Overview:
Founded in 1980, Aspen Exploration Corporation is an oil and gas company,
which participates in the oil and gas segment by acquiring interest in producing
oil and gas properties, and participating in drilling operations. Historically
we have also participated in exploration for precious minerals and, in uranium
exploration.
In fiscal 2000, we expanded our business scope to include a goal of
participating in the electric power segment. We are not currently actively
pursuing either precious minerals exploration or participation in the electric
power segment (although we had a 25% interest in APS as described above). As of
December 31, 2002, APS ceased operations and went out of business. We have also
acquired an interest in leases for approximately 2,074 acres which we believe
contain coalbed methane gas deposits.
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.
15
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:
-----------------------------
Effective July 1, 2002, 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 5%. 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.
Liquidity and Capital Resources:
During prior years, we had to finance many of our oil and gas operations
through short-term borrowings, which were paid back out of the funds generated
from our operations. During fiscal 2003 and 2002, we were able to finance all of
our oil and gas operations from funds generated from operations and through
farmout agreements and other forms of third party participation. In fiscal 2003
we received cash flow from operations of approximately $900,000. Net income
before taxes and change in accounting principle was approximately $103,000
compared to a loss of approximately $237,000 during fiscal 2002. The net income
before taxes and changes in accounting principle of $103,000 was the result of
an increase in the average price we received for natural gas sales from $2.78 in
fiscal 2002 to $4.23 in fiscal 2003, an increase of $1.45, or 52%. Production
for the period increased 3% on a barrels of oil equivalent ("BOE") basis when
comparing fiscal 2003 to 2002. We also increased our accounts payable and
accrued expenses by almost $262,000 and decreased our accounts receivable by
nearly $103,000 which had a positive impact on cash flow from operations. During
fiscal 2003 we also received cash of $239,095 from a split dollar life insurance
policy held jointly with our former president and now vice president R. V.
Bailey. At the end of 2002 we had working capital of approximately $845,000. We
used these funds to finance our use of cash used by investing activities
($1,280,000) resulting in working capital of approximately $343,000 at June 30,
2003.
We did not have sufficient cash available to assist us in financing our
operations in prior years, and we may not in future years, since our ability to
generate working capital depends almost entirely on the prices we receive for
16
our natural gas production. Because of our working capital surpluses through
2003, we did not need to borrow any funds for operations or investing
activities. We cannot now predict whether we will be required to borrow funds or
find alternative means of financing operations during the fiscal year ending
June 30, 2004.
June 30, 2003 as compared to June 30, 2002
-------------------------------------------
June 30, 2003 June 30, 2002
------------- -------------
Current Assets $ 1,093,131 $ 1,333,221
Current Liabilities $ 750,401 $ 488,622
Working Capital $ 342,730 $ 844,599
Investments in Oil & Gas
Properties/Drilling Activities $ 1,378,356 $ 1,195,535
Compared to fiscal 2002, there was a 59% decrease in working capital. Our
investment in drilling projects and the acquisition of producing properties of
approximately $1,380,000 accounted for much of the decline in current assets.
Fiscal 2003 was a successful drilling year for us, having participated in the
drilling of six wells in California, five of them successful, for a 83% success
ratio. During 2003 we also acquired various interests in producing properties
located in California as well as increasing our working interests in three wells
in the Denverton Creek field. We believe that the increased revenues derived
from the late year drilling activities and acquisitions will have a positive
effect on next year's working capital and contribute significantly to our cash
flow in the year ahead provided that the average prices we receive from our
natural gas production do not decrease materially. The average price we received
during fiscal 2003 for our oil and gas was $26.13 per barrel and $4.23 per MCF
compared to $20.20 per barrel and $2.78 per MCF for fiscal 2002. Given the
current downturn of our economy and estimates of a range of $4.00 to $5.00 per
MCF for gas in the coming 12 months, we do not see any significant improvement,
other than seasonal adjustments, to natural gas prices in the short term. The
price for oil has been stable to improving due to unrest in the Middle East, but
we derive only a small portion of our revenue from oil sales. Our capital
requirements can fluctuate over a twelve month period because our drilling
activities are usually carried out during California's dry season (from late
April until October) after which wet weather either precludes further activity
or makes it cost prohibitive.
Investments in Oil and Gas Properties/Drilling Activities
---------------------------------------------------------
We invested $1,378,356 and $1,195,535 in our oil and gas properties for the
fiscal years ended June 30, 2003 and 2002. While we have not finalized drilling
plans for fiscal 2004, we have committed to participate in the drilling of 2
wells through June 2004 with our share of drilling costs estimated to be
approximately $84,000, and we anticipate additional drilling will occur in
fiscal 2004. 3-D seismic studies and pipeline construction will add an
additional $170,000 to our projected costs for fiscal 2004. We believe that
internally generated funds will be sufficient to finance our drilling and
operating expenses for the next twelve months. We have eliminated our
outstanding loans in fiscal 2001 but may be required to again seek outside
funding to facilitate our fiscal 2004 drilling program.
Aspen Power Systems, LLC
------------------------
During fiscal 1999 and 2000, we dedicated certain cash resources to APS to
investigate the economic possibilities of the sale, design, construction and/or
operation of gas turbines to produce electricity. Through June 30, 2000, we
expended approximately $130,000 on this project, $45,657 of which was expensed
in the twelve months ended June 30, 2000. During fiscal 2001, we advanced a
further $20,000 to defray APS operating costs which were recorded as a
receivable at June 30, 2001. During fiscal 2002 an additional $5,500 was
advanced to APS to retire existing obligations of APS. Both the $20,000 and
$5,500 advances were expensed by us at June 30, 2002. The funding to APS came
from our operating funds derived from oil and gas production. As discussed
above, we did not assign a value to the $130,000 note receivable due from APS
and do not anticipate any significant future requirements to fund further
projects of APS, because APS ceased operations effective December 31, 2002.
17
Contractual Obligations
We had contractual and other obligations that will require use of our
working capital resources as of June 30, 2003. The following table lists our
significant obligations at June 30, 2003:
Payments Due By Period
--------------------------------------------------------------------
Less than
Contractual Obligations 1 year 2-3 years 4-5 years After 5 years Total
----------------------- ------ --------- --------- ------------- -----
Employment
Obligations $202,485 $373,300 $153,300 $60,300 $789,385
Operating leases 16,326 15,240 -0- -0- 31,566
--------- --------- --------- -------- ---------
Total contractual
cash obligations $218,811 $388,540 $153,300 $60,300 $820,951
======== ======== ======== ======= ========
At June 30, 2003, we were committed to the following drilling and
development projects in California:
Project Aspen Cost
------- ----------
Mengali-Durst #22-1 $ 40,000
Sac Outing Farms #31-3 44,000
West Grimes 3-D 100,000
Verona Pipeline 70,000
---------
Total $ 254,000
---------
We maintain office space in Denver, Colorado, our principal office, and
Bakersfield, California. The Denver office consists of approximately 1,108
square feet with an additional 750 square feet of basement storage. We entered
into a one-year lease agreement through December 31, 2003 for a lease rate of
$1,261 per month. We also subleased from R. V. Bailey, our vice president, a
portion of an office building owned by Mr. Bailey in Castle Rock, Colorado on a
month to month basis for $500 per month. This lease arrangement was terminated
on April 30, 2003. 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 years ended June 30, 2003
and 2002 were $28,536 and $26,663, respectively.
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.
18
Results of Operations:
We continued to focus our operations on the production of oil and gas and
the investigation for possible acquisition of producing oil and gas properties
during the twelve months ended June 30, 2003.
June 30, 2003 as compared to June 30, 2002
------------------------------------------
The following table sets forth, for the periods indicated, certain
statement of operations data. The table and the discussion below should be read
in conjunction with the audited financial statements and the notes thereto
appearing elsewhere in this report.
Year Ended
June 30
-------
2003 2002
---- ----
Oil and gas revenues (a) $1,313,821 $ 828,150
Oil and gas production expenses (159,948) (117,014)
Aspen Power Systems -0- (25,500)
Depreciation, depletion and amortization (428,964) (358,912)
Selling, general and administrative expense (632,035) (605,085)
---------- ----------
Income before other items and income taxes 92,874 278,361
Other income 9,852 41,372
---------- ----------
Operating income (loss) 102,726 (236,989)
Income tax (expense) recovery (42,100) 114,904
---------- ----------
Income (loss) before cumulative effect of change in
accounting principle 60,626 (122,085)
Cumulative effect of change in accounting principle,
net of income taxes (2,849) -0-
---------- ----------
Net income (loss) $ 57,777 $ (122,085)
========== ==========
(a) Oil and gas revenues includes income from management fees
Oil and Gas Revenues
--------------------
For the twelve months ended June 30, 2003, oil and gas revenues increased
approximately $486,000, a 59% increase. Revenue increases were primarily due to
an increase in gas prices from $2.78 per MMBTU in 2002 to $4.23 per MMBTU in
2003. The average price in fiscal 2003 was impacted positively by an improving
American economy and the continued high price of oil, which can be used as an
alternative fuel, due to global political uncertainties. Production of oil
declined 1287 barrels, or 42%, reflecting the sale of our final two producing
oil wells in the first quarter of fiscal 2003. Gas production increased by 9.3%
and was the result of the addition of five new exploratory wells during fiscal
2003 and the acquisition of fifteen producing gas wells in the current fiscal
year. These additions were partially offset by the abandonment of five gas wells
which proved to be at the end of their economic life during fiscal 2003.
Oil and Gas Production Expenses
-------------------------------
Oil and gas production expenses increased approximately $43,000, or 37%. We
had a larger number of producing wells in fiscal 2003 and our recompletion and
workover expenses increased because marginal gas wells were put on compressors
and the initial costs to put acquired wells on production were substantial.
Depletion, depreciation and amortization increased $70,052, or 19.5%, from
$358,912 in fiscal 2002 to $428,964 in fiscal 2003. The depletable assets in the
full cost pool increased by approximately $1,296,000 in fiscal 2003, the proved,
recoverable reserves of oil and gas increased from BOE 380,000 (barrel of oil
equivalent) in fiscal 2002 to BOE 416,000 in fiscal 2003, a 9.5% increase. Our
reserves increased 9.5% and our production rate increased by approximately 3%,
thus the depletion rate held fairly constant and the increase in depletion was
primarily due to an increase in the full cost pool.
Selling, general and administrative expenses increased $26,950, or 4.5%,
during fiscal 2003, due to higher salary, consulting, audit and temporary
services. We anticipate lower general and administrative expenses in fiscal 2004
19
due to the new employment agreement with our former president, now vice
president, R. V. Bailey. Salary, rent and insurance expense should decline in
the coming year. We continue our commitment to contain costs and increase cash
flow wherever possible.
As a result of our operations for the fiscal year ended June 30, 2003, we
ended the year with operating income of approximately $103,000 before income tax
expense of $42,000 and a change of accounting principle charge of approximately
$3,000, compared to an operating loss of approximately $237,000 before recovery
of income taxes of nearly $115,000 for the year ended June 30, 2002. The
improvement can be attributed, as discussed above, to a substantial increase in
prices received for our oil and gas, a modest increase in our rate of production
and an increase of $110,294, or 82%, in management fees received from well
operations.
Factors that may Affect Future Operating Results
------------------------------------------------
In evaluating our business, readers of this report should carefully
consider the following factors in addition to the other information presented in
this report and in our other reports filed with the SEC that attempt to advise
interested parties of the risks and factors that may affect our business. As
noted elsewhere herein, the future conduct of Aspen's business, non-oil and gas
exploration activities, participation in APS stock ownership, and discussions of
possible future activities is dependent upon a number of factors, and there can
be no assurance that Aspen will be able to conduct its operations as
contemplated herein. These risks include, but are not limited to:
(1) The possibility that the described operations, reserves, or
exploration or production activities will not be completed or
continued on economic terms, if at all.
(2) The exploration and development of oil and gas, and mineral properties
are enterprises attendant with high risk, including the risk of
fluctuating prices for oil, natural gas and other minerals being
sought.
(3) Imports of petroleum products from other countries.
(4) Not encountering adequate resources despite expending large sums of
money.
(5) Test results and reserve estimates may not be accurate,
notwithstanding best effort precautions.
(6) The possibility that the estimates on which we are relying are
inaccurate and that unknown or unexpected future events may occur that
will tend to reduce or increase our ability to operate successfully,
if at all.
(7) Our ability to participate in these projects may be dependent on the
availability of adequate financing from third parties which may not be
available on commercially-reasonable terms, if at all.
(8) Although we currently do not have active operations in the mining
segment, mining exploration and mining have inherent risks including
the environment, low prices for commodities, competition from better
financed companies and the risk of failure in either exploration or
mining. There is no assurance we will be able to compete successfully
in the exploration and mining business should that course of action be
undertaken.
(9) We currently do not have active operations in the power generation
business. Risks involved in power generation include permitting,
availability of fuel and power lines on an economical basis, a market
for the product, availability of equipment, and competition from other
better financed companies. There is no assurance we will be able to
compete successfully in the power generation business should an
opportunity be found.
(10) Our stock price may be hurt by future sales of our shares or the
perception that such sales may occur. As of the date of this Form
10-KSB, approximately 2,849,367 shares of Common Stock held by
existing stockholders constitute "restricted shares" as defined in
Rule 144 under the Securities Act. These shares may only be sold if
they are registered under the Securities Act or sold under Rule 144 or
another exemption from registration under the Securities Act. Sales
under Rule 144 are subject to the satisfaction of certain holding
periods, volume limitations, manner of sale requirements, and the
availability of current public information about us.
20
ITEM 7. FINANCIAL STATEMENTS
-----------------------------
The information required by this item begins on page 35 of Part III of this
Report on Form 10-KSB and is incorporated into this part by reference.
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
------------------------------------------------------------------------
FINANCIAL DISCLOSURE
--------------------
Not applicable.
ITEM 8A. CONTROLS AND PROCEDURES
---------------------------------
(a) Evaluation of Disclosure Controls and Procedures.
As required by Rule 13a-15 under the Securities Exchange Act of 1934,
within the 90 days prior to the filing date of this report, we carried out an
evaluation of the effectiveness of the design and operation of its disclosure
controls and procedures. This evaluation was carried out under the supervision
and with the participation of our principal executive officer as well as our
principal financial officer, who concluded that the Company's disclosure
controls and procedures are effective.
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 the our principal
executive officer and our principal financial officer, as appropriate, to allow
timely decisions regarding required disclosure.
(b) Changes in Internal Controls.
There were no changes in our internal controls or in other factors that
could significantly affect these internal controls subsequent to the date of
their evaluation.
PART III
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS, COMPLIANCE
--------------------------------------------------------------------------------
WITH SECTION 16(A) OF THE EXCHANGE ACT
--------------------------------------
Identification of Directors and Executive Officers:
The following table sets forth the names and ages of all the Directors and
Executive Officers of Aspen, and the positions held by each such person. As
described below, the Board of Directors is divided into three classes which,
under Delaware law, must be as nearly equal in number as possible. The members
of each class are elected for three-year terms at each successive meeting of
stockholders serve until their successors are duly elected and qualified;
officers are appointed by, and serve at the pleasure of, the Board of Directors.
We have held no annual meetings since February 25, 1994. Therefore the terms of
each class of director expires at the next annual meeting of stockholders.
Director
Name Age Position Class Since
---- --- -------- ----- -----
Robert A. Cohan 47 President, Chief Executive I 1998
Officer,Chief Financial
Officer, Treasurer and Director
Robert F. Sheldon 80 Director II 1981
R. V. Bailey 71 Vice President, Secretary, and III 1980
Director
21
Each of the directors will be up for reelection at the next annual meeting
of stockholders and until his successor is elected and qualified or until his or
her earlier death, resignation, or removal. We do not expect to hold an annual
meeting during fiscal 2004.
Each officer is appointed annually and serves at the discretion of the
Board of Directors until his successor is duly elected and qualified. No
arrangement exists between any of the above officers and directors pursuant to
which any of those persons was elected to such office or position. None of the
directors are also directors of other companies filing reports under the
Securities Exchange Act of 1934.
Robert A. Cohan. Mr. Cohan obtained a Bachelor of Science degree in Geology
from the State University College at Oneonta, NY in 1979. He has approximately
24 years experience in oil and gas exploration and development, including
employment in Denver, CO with Western Geophysical, H. K. van Poollen & Assoc.,
Inc., as a Reservoir Engineer and Geologist, Universal Oil & Gas, and as a
principal of Rio Oil Co., Denver, CO. Mr. Cohan served as Manager, Oil & Gas
Operations, Aspen Exploration Corporation, Denver, CO from 1989 to 1992. He was
employed as Vice President, Oil & Gas Operations, for Tri-Valley Oil & Gas Co.,
Bakersfield, CA. from 1992 to April 1995, at which time Mr. Cohan rejoined Aspen
Exploration Corporation as Vice President (now President), West Coast Division,
opening an office in Bakersfield, CA. He is a member of the Society of Petroleum
Engineers (SPE) and the American Association of Petroleum Geologists (AAPG).
Robert F. Sheldon. Mr. Sheldon obtained a Bachelor of Science degree in
Geological Engineering from the University of British Columbia in 1948. He
served a total of approximately 40 years at various mining companies, with his
experience covering a wide range of mineral commodities including gold, silver,
copper, uranium, lead, zinc, nickel, mercury, molybdenum and tungsten. He is a
member of the Professional Engineers of British Columbia, the Society of Mining
Engineers, the Canadian Institute of Mining and Metallurgy, and the Yukon
Chamber of Mines (where he served as an officer for four years). Mr. Sheldon
joined Aspen's Board of Directors in April 1981.
R. V. Bailey. R. V. Bailey obtained a Bachelor of Science degree in Geology
from the University of Wyoming in 1956. He has approximately 41 years experience
in exploration and development of mineral deposits, primarily gold, uranium,
coal, and oil and gas. His experience includes basic conception and execution of
mineral exploration projects. Mr. Bailey is a member of several professional
societies, including the Society for Mining and Exploration, the Society of
Economic Geologists and the American Association of Petroleum Geologists, and
has written a number of papers concerning mineral deposits in the United States.
He is the co-author of a 542-page text, published in 1977, concerning applied
exploration for mineral deposits. Mr. Bailey is the founder of Aspen and has
been an officer and director since its inception.
Meetings of the Board and Committees:
The Board of directors held one formal meeting during the fiscal year ended
June 30, 2003. Each director attended all of the formal meetings either in
person or by telephone, without exception. In addition, regular communications
were maintained throughout the year among all of the officers and directors of
the Company and the directors acted by unanimous consent three times during
fiscal 2002 and four times subsequently through June 30, 2003.
Aspen does not have an audit committee or other committee of the board that
performs similar functions. Consequently Aspen has not designated an audit
committee financial expert. Aspen's board of directors has not adopted a code of
ethics.
Identification of Significant Employees:
There are no significant employees who are not also directors or executive
officers as described above. No arrangement exists between any of the above
officers and directors pursuant to which any one of those persons was elected to
such office or position.
22
Family Relationships:
As of June 30, 2003, and subsequently, there were no family relationships
between any director, executive officer, or person nominated or chosen by the
Company to become a director or executive officer.
Involvement in Legal Proceedings:
We are not subject to any pending or, to our knowledge, threatened, legal
proceedings.
Section 16(a) Beneficial Ownership Reporting Compliance:
Section 16(a) of the Securities Exchange Act of 1934 (the "Exchange Act")
requires Aspen's directors and officers and any persons who own more than ten
percent of Aspen's equity securities, to file reports of ownership and changes
in ownership with the Securities and Exchange Commission (the "SEC"). All
directors, officers and greater than ten-percent shareholders are required by
SEC regulation to furnish Aspen with copies of all Section 16(a) reports files.
Based solely on our review of the copies of the reports it received from persons
required to file, we believe that during the period from July 1, 1995 through
September 22, 2003, all filing requirements applicable to its officers,
directors and greater-than-ten-percent shareholders were complied with. However,
there was one untimely-filed filing (Form 4) for one director, Robert F.
Sheldon.
23
ITEM 10. EXECUTIVE COMPENSATION
--------------------------------
The following table sets forth information regarding compensation awarded,
paid to, or earned by the chief executive officer and the other principal
officers of Aspen for the three years ended June 30, 2001, 2002 and 2003. No
other person who is currently an executive officer of Aspen earned salary and
bonus compensation exceeding $100,000 during any of those years. This includes
all compensation paid to each by Aspen and any subsidiary.
---------------------------- -------------------------------- --------------------------------------
Annual compensation Long-term Compensation
Awards
------------------------------------------------------------- -------------------------- -----------
Awards Payout
------------------------------------------------------------- -------------------------- -----------
(a) (b) (c) (d) (e) (f) (g) (h) (i)
------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- -----------------
Securities
Name and ($) Underlying All Other
Principal Fiscal ($) ($) ($) Restricted Options & LTIP Compensation
Position Year Salary Bonus Other (1) Awards SARs (#) Payout (1)
------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- -----------------
R. A. Cohan 2001 101,250 0 146,400 0 0 0 0
President and 2002 123,300 0 34,850 0 0 0 200
CEO 2003 127,100 0 35,600 0 0 0 9,700
------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- -----------------
R. V. Bailey, 2001 100,000 0 143,600 0 0 0 12,663
Vice President 2002 122,900 0 34,850 0 0 0 11,565
and Chairman 2003 111,700 0 33,250 0 0 0 23,487
------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- -----------------
(1) We have an "Amended Royalty and Working Interest Plan" by which we, in
our discretion, are able to assign overriding royalty interests or
working interests in oil and gas properties or in mineral properties.
This plan is intended to provide additional compensation to Aspen's
personnel involved in the acquisition, exploration and development of
Aspen's oil or gas or mineral prospects.
We have a medical insurance plan for our employees and those of its
subsidiaries, and a life insurance plan for our chairman and vice
president, R. V. Bailey. This life insurance plan included a
split-dollar insurance plan for the benefit of Mr. Bailey, which is
described in Note 2 to the financial statements. In June 2003 the plan
was terminated.
No additional compensation has been recognized as reimbursement to the vice
president for income taxes for the years ended June 30, 2003, 2002 and 2001. Mr.
Bailey's taxable amount was $-0- for fiscal 2003, 2002 and 2001, equal to the
"economic benefit" attributed to the vice president as defined by the Internal
Revenue Code. The Company paid no premiums during fiscal 2003, 2002 and 2001.
We adopted a Profit-Sharing 401(k) Plan which took effect July 1, 1990. All
employees are immediately eligible to participate in this Plan. Aspen's
contribution (if any) to this plan is determined by the Board of Directors each
year. At June 30, 2002 and 2001, we contributed $-0- to the plan; during fiscal
2003 we contributed $7,388 to the plan. When amounts are contributed to Mr.
Bailey's and Mr. Cohan's accounts (which amounts are fully vested), these
amounts are also included in column (e) of the tables, above.
We have furnished a vehicle to Mr. Bailey, and the compensation allocable
to this vehicle, plus amounts paid for various travel and entertainment paid on
behalf of Mr. Bailey and Mr. Bailey's wife when she accompanied him for business
purposes, are also included in column (i) of the table. Aspen also purchased a
vehicle for Mr. Cohan. This vehicle is used substantially for business purposes;
therefore, no vehicle costs were charged to Mr. Cohan.
We have agreed to reimburse its officers and directors for out-of-pocket
costs and expenses incurred on behalf of Aspen.
24
During fiscal 2003, we assigned to employees royalties, which accumulated
during the fiscal year ended June 30, 2003, on certain wells drilled during the
year. The value assigned to these overrides is considered nominal, as the
assignments were made before the leases were proved. The overriding royalty
interests in these California properties granted to our employees were as
follows:
R. V. R. A. J. L.
Bailey Cohan Shelton
------ ----- -------
McCullough 36-1 1.683938% 1.683937% 0.641500%
Pope Bypass 1-5 1.065339% 1.566676% 0.501336%
Stock Options and Stock Appreciation Rights Granted during the Last Fiscal Year:
No stock options were granted to executive officers and directors during
the fiscal year ended June 30, 2003. No stock options were exercised during the
fiscal year ended June 30, 2003.
Aggregated Option Exercises in Last Fiscal Year and Fiscal Year End Option
Values:
One of our directors exercised stock options during the fiscal year ended
June 30, 2002:
The following table sets forth information regarding the year-end value of
options being held by the Chief Executive Officer and the other such named
officers and persons on June 30, 2003.
Number of securities
underlying unexercised Value of unexercised
Shares options/SARs in-the-money options/SARs
acquired on Value at June 30, 2003 at June 30, 2002
Name and Principal Position exercise (#) realized Exercisable/Unexercisable Exercisable/Unexercisable
--------------------------- ------------ -------- ------------------------- -------------------------
R. V. Bailey
Vice President & Chairman... -0- -0- 0 /150,000 $-0-
Robert A. Cohan
President & CEO............. -0- -0- 0 /250,000 $-0-
Robert F. Sheldon
Director....................... 80,000 $20,800 0 /150,000 $-0-
Long Term Incentive Plans/Awards in Last Fiscal Year:
We do not have a long-term incentive plan nor have we made any awards
during the fiscal year ended June 30, 2003.
Employment contracts and termination of employment and change in control
arrangements:
Mr. Bailey: Effective May 1, 2003 we entered into a new employment
agreement with Chairman of the Board, R. V. Bailey. Some of the pertinent
provisions include an employment period ending May 1, 2009, the title of Vice
President subject to the general direction of the President, Robert A. Cohan,
and the Board of Directors of Aspen. Mr. Bailey's salary will be $45,000 per
year from May 1, 2003 to December 31, 2006 and $60,000 per year from January 1,
2007, ending May 1, 2009. Mr. Bailey will also participate in Aspen's stock
options and royalty interest programs. During the term of the agreement, we have
agreed to pay Mr. Bailey a monthly $1,700 allowance to cover such items as
prescriptions, medical and dental coverage for himself and his dependents and
other expenses not covered in the agreement.
Mr. Bailey's keyman life insurance policy terminated in August of this year
and will result in an annual savings of approximately $6,500. The stock purchase
agreement with Mr. Bailey was cancelled and replaced by his current employment
agreement. The agreement had provided that we apply 75% of the $1,000,000 keyman
life insurance to purchase up to 75% of the common shares owned by him at the
time of his death. Mr. Bailey will continue to use the Company vehicle and may
trade the current vehicle for a similar vehicle of his choice prior to June 30,
2006. During 2007 or thereafter, Mr. Bailey may purchase the vehicle for $500.
25
We may terminate this agreement upon Mr. Bailey's death by paying his
estate all compensation that had or will accrue to the end of the year of his
death plus $75,000. Should Mr. Bailey become totally and permanently disabled,
we will pay Mr. Bailey one half of the salary and benefits set forth in our
agreement with him for the remainder of the term of the agreement.
Mr. Cohan: On April 16, 1998, we entered into an employment agreement with
Robert A. Cohan, which provides for the payment of $90,000 for the first year of
employment, plus reimbursement of expenses, including health insurance. We have
renewed the agreement effective April 15, 1999 to April 15, 2002 at the rate of
$95,000 per year for the year commencing April 15, 1999, $100,000 for the year
commencing April 15, 2000 and $105,000 for the year commencing April 15, 2001.
On August 1, 2001 Mr. Cohan's salary was increased to $125,000 per year. Mr.
Cohan's employment agreement expired by its own terms on April 15, 2002 and was
replaced by an employment agreement dated January 1, 2003. Some of the pertinent
provisions include an employment period ending December 31, 2005, salary
increases from $125,000 per year to $135,000 per year effective April 15, 2003,
and a further salary increase to $145,000 per year from April 15, 2004 through
the end of the contract. Other benefits and duties will remain the same as the
previous employment contract. Prior to February 2000, we and Mr. Cohan agreed to
utilize a portion of Mr. Cohan's home in Bakersfield, California from which to
conduct Aspen's business. Mr. Cohan did not charge Aspen any rent for the use of
his home as a business office. Aspen agreed to pay for all office supplies,
communication and copy equipment used by Mr. Cohan in his office, as well as the
monthly telephone expense incurred by Mr. Cohan on behalf of Aspen. On February
7, 2000, we entered into a three-year lease of office space in Bakersfield,
California thereby alleviating the necessity of home office reimbursement to Mr.
Cohan.
Effective May 1, 2003 our Board of Directors appointed Mr. Robert A. Cohan
President of Aspen Exploration Corporation, replacing Mr. Bailey.
During fiscal 2002 we entered into a rental agreement with R. V. Bailey to
rent office space in Castle Rock, Colorado in an office building owned by Mr.
Bailey. The rental amount was $6,000 per year on a month to month basis. This
agreement was terminated effective May 1, 2003.
See also Item 12(a) Transactions with Management and Others.
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
-------------------------------------------------------------------------
The following table sets forth as of September 22, 2003 the number and
percentage of Aspen's shares of $.005 par value common stock owned of record and
beneficially owned by each person owning more than five percent of such common
stock, and by each Director, and by all Officers and Directors as a group.
Beneficial Ownership Percent
-------------------- -------
Beneficial Owner Number of Shares of Total
---------------- ---------------- --------
R. V. Bailey 1,444,403i 24.63%
Robert A. Cohan 790,619ii 13.48%
Robert F. Sheldon 284,783iii 4.86%
All Officers and Directors as a Group 2,519,805 42.97%
(3 persons)
The address for all of the above directors and
executive officers is:
2050 S. Oneida St., Suite 208, Denver, CO 80224
(i) This number includes 1,146,083 shares of stock held of record in the
name of R. V. Bailey and 16,320 shares of record in the name of Mieko Nakamura
Bailey, his wife. In addition, the number of shares owned includes 100,000
shares of common stock granted in a property exchange; stock options to purchase
150,000 shares of restricted common stock; and 200,000 shares of restricted
common stock that were exercised on June 11, 2001. Additionally, Aspen issued
32,000 shares of common stock to the Aspen Exploration Profit Sharing Plan for
the benefit of R. V. Bailey as a corporation contribution to Mr. Bailey's 401(k)
account.
26
(ii) This number includes 300,000 shares of common stock granted; stock
options to purchase 250,000 shares of restricted common stock; and stock options
to purchase 200,000 shares of restricted common stock that were exercised on
February 27, 2001. Additionally, Aspen issued 30,733 shares of common stock to
the Aspen Exploration Profit Sharing Plan for the benefit of Robert A. Cohan as
a corporation contribution to Mr. Cohan's 401(k) account.
(iii) This number includes 20,000 shares of common stock granted December
13, 1996, 20,000 shares of common stock granted November 1, 1997; stock options
to purchase 150,000 shares of restricted common stock; and stock options granted
for 80,000 shares of common stock that were exercised on December 17, 2001.
Except with respect to the employment agreement between Aspen and R. V.
Bailey, we know of no arrangement, the operation of which may, at a subsequent
date, result in change in control of Aspen.
See Item 5, above, for information regarding securities authorized for
issuance under equity compensation plans in the form required by Item 201(d) of
Regulation S-B.
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
--------------------------------------------------------
The following sets out information regarding transactions between officers,
directors and significant shareholders of Aspen during the most recent two
fiscal years and during the subsequent fiscal year.
Working Interest Participation:
Some of the directors and officers of Aspen are engaged in various aspects
of oil and gas and mineral exploration and development for their own account.
Aspen has no policy prohibiting, nor does its Certificate of Incorporation
prohibit, transactions between Aspen and its officers and directors. We plan to
enter into cost-sharing arrangements with respect to the drilling of its oil and
gas properties. Directors and officers may participate, from time to time, in
these arrangements and such transactions may be on a non-promoted basis (actual
costs), although they have participated mainly on a promoted basis, but must be
approved by a majority of the disinterested directors of our Board of Directors.
R. V. Bailey, vice president and director of Aspen, Robert A. Cohan,
president and director of Aspen, and Ray K. Davis, consultant to Aspen, each
have working and royalty interests in certain of the California oil and gas
properties operated by Aspen. The affiliates paid for their proportionate share
of all costs to acquire, develop and operate these properties. As of June 30,
2003, working interests of the Company and its affiliates in certain producing
California properties are set forth below:
GROSS WELLS NET WELLS
GAS GAS
--- ---
Aspen Exploration 52 7.07
R. V. Bailey 39 .87
R. A. Cohan 40 .60
R. K. Davis 46 .65
J. L. Shelton 24 .05
Amended Royalty and Working Interest Plan:
The allocations for royalty under Aspen's "Royalty and Working Interest
Plan" for employees are based on a determination of whether there is any "room"
for royalties in a particular transaction. In some specific cases an oil or gas
property or project is sufficiently burdened with existing royalties so that no
additional royalty burden can be allocated to our employees for that property or
project. In other situations a determination may be made that there are royalty
interests available for assignment to our employees. The determination of
whether royalty interests are available and how much to assign to employees
(usually less than 3%) is made on a case by case basis by Robert A. Cohan,
president, and R. V. Bailey, vice president, both of whom may benefit from
royalty interests assigned. During fiscal 2002, assignments to Mr. Cohan and Mr.
Bailey have been on an equal basis, while Ms. Judy Shelton, the corporate office
manager, was assigned a lesser amount. For fiscal 2003 Mr. Bailey and Ms.
Shelton shared a proportionately lesser amount. A discussion of specific
royalties assigned is included in Item 10 "Executive Compensation" above.
27
Aspen Power Systems, LLC:
In order to provide an opportunity for Aspen to participate in the growing
demand for electrical power generated by turbines, our management established an
85% owned subsidiary named Aspen Power Systems, LLC ("APS"), a Colorado limited
liability company. On March 1, 2000 our interest in APS was reduced to 25%. The
transaction is more fully described in Item 1 "Aspen Power Systems, LLC".
APS organized Solano Power, LLC on December 27, 1999 for the purpose of
carrying out The Solano Project. Solano Power plans to find a joint venture
partner to develop a 50 MW natural gas powered electric generation plant in
Solano County, California. We own a 25% interest in Solano Power, the managers;
Larry Baccari, R. V. Bailey and Ray K. Davis each contributed $5,000 to fund
Solano operations and own a 25% interest each in the project. The managers are
seeking an industry partner in order to financially assist Solano Power to build
and operate the plant. At June 30, 2000 APS had expended approximately $28,400
on behalf of Solano Power as well as accruing expenses for consulting fees of R.
V. Bailey and Ray K. Davis of $31,050 and $7,462, respectively. At June 30, 2002
Solano had no outstanding obligations and was inactive for most of the year. APS
has assumed the responsibilities of finding partners to fund the power plant. At
June 30, 2001 Solano transferred its operations to Aspen Power Systems and APS
has assumed the responsibility for pursuing this project.
On September 17, 2001, we were advised by the State of California that our
25% owned project in Solano County, California has not been selected by the
California Power Commission for further negotiations. Effective December 31,
2002 APS ceased operations and went out of business.
Aspen Borrowings:
During the fiscal years ending June 30, 2002 and 2003, we had no
outstanding loans or borrowing obligations.
Other Arrangements:
During the fiscal years 2003 and 2002 Aspen paid for various hospitality
functions and for travel, lodging and hospitality expenses for spouses who
occasionally accompanied directors when they were traveling on company business.
Our president has also supplied Aspen with certain promotional items. The net
effect of these items has been a cost to Aspen of less than $5,000 for the
fiscal years ended June 30, 2003 and 2002, respectively. Management believes
that the expenditures were to Aspen's benefit. During the years ended June 30,
2003 and 2002, Aspen provided one vehicle each to Aspen's president and vice
president.
We also have entered into an employment agreement, which has expired, and a
Stock Purchase Agreement, which also expired, with our vice president, as
discussed in "Item 10 - Employee Compensation" and "Item 11 - Security
Ownership."
We subleased a portion of our vice president's office in a building owned
by him in Castle Rock, Colorado on a month to month basis for a monthly fee of
$500. This sublease terminated on April 30, 2003 per the revised employment
agreement with Mr. Bailey. See Item 10, R. V. Bailey Employment Contract.
Certain Business Relationships:
None.
(1)-(5) Indebtedness of Management:
None.
Transactions with Promoters:
Not applicable.
28
Compensation Agreements:
Please refer to the prior section, Item 10. Executive Compensation,
describing the employment agreements between the Company and Messrs. Bailey and
Cohan.
29
ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K.
Exhibits Pursuant to Item 601 of Regulation S-B:
Exhibit No. Title
----------- ------------------------------------------------------------
3.01 Certificate of Incorporation (1)
3.02 Registrant's Bylaws. (1)
3.03 Bylaws - Subsidiary (1)
3.20* Registrant's Amended and Restated Bylaws
4.01 Specimen Common Stock Certificate. (1)
10.01 Royalty and Working Interest Plan (1)
10.02* Employment Agreement between Aspen Exploration Corporation
and Robert A. Cohan dated January 1, 2003 (10)
10.03* Employment Agreement between Aspen Exploration Corporation
and R.V. Bailey dated May 1, 2003 (10)
10.08 Stock Purchase Agreement between Aspen Exploration
Corporation and R.V. Bailey dated January, 1983 (7)
10.11 Employment Agreement between Aspen Exploration Corporation
and R.V. Bailey dated November 8, 1991 (8)
10.13 Split-Dollar Life Insurance Plan for R.V. Bailey (8)
10.15 Stock Purchase Agreement between Aspen Exploration
Corporation and R.V. Bailey dated June, 1993 (9)
22.1 Subsidiaries of Aspen Exploration Corporation
Aspen Gold Mining Company, a Colorado corporation
Aspen Power Systems, LLC, a Colorado limited liability
company
31* Certification pursuant to Rule 13a-14
32* Certification pursuant to 18 U.S.C.ss.1350
* Filed herewith.
1 Incorporated by reference from Commission File No. 2-69324.
7 Incorporated by reference from Annual Report on Form 10-K dated June 30, 1991
(filed on September 27, 1991).
8 Incorporated by reference from Annual Report on Form 10-K dated June 30, 1992
(filed on October 3, 1992).
9 Incorporated by reference from Annual Report on Form 10-KSB dated June 30,
1993 (filed on September 27, 1993).
10 Incorporated by reference from Annual Report on form 10-KSB dated June 30,
2003 (filed on September 22, 2003).
Reports on Form 8-K.
No Report on Form 8-K was filed by the Company during the fiscal year
ending June 30, 2003 or subsequently.
ITEM 14. PRINCIPAL ACCOUNTANT'S FEES AND SERVICES.
---------------------------------------------------
(a) Audit Fees.
Our principal accountant, Gordon Hughes & Banks LLP, billed us aggregate
fees in the amount of approximately $15,200 for the fiscal year ended June 30,
2003 and approximately $15,500 for the fiscal year ended June 30, 2002. These
amounts were billed for professional services that Gordon Hughes & Banks LLP
provided for the audit of our annual financial statements, review of the
financial statements included in our report on 10-QSB and other services
typically provided by an accountant in connection with statutory and regulatory
filings or engagements for those fiscal years.
30
(b) Audit-Related Fees.
Gordon Hughes & Banks LLP billed us aggregate fees in the amount of $1,800
for the fiscal years ended June 30, 2003 and 2002 for assurance and related
services that were reasonably related to the performance of the audit or review
of our financial statements.
(c) Tax Fees
Gordon Hughes & Banks LLP billed us aggregate fees in the amount of
approximately $4,600 for the fiscal year ended June 30, 2003 and approximately
$4,400 for the fiscal year ended June 30, 2002, for tax compliance, tax advice,
and tax planning.
(d) All Other Fees
Gordon Hughes & Banks LLP billed us aggregate fees in the amount of $-0-
for the fiscal years ended June 30, 2003 and 2002 for other fees.
(e) Audit Committee's Pre-Approval Practice
Inasmuch as Aspen does not have an audit committee, Aspen's board of
directors performs the functions of its audit committee. Section 10A(i) of the
Securities Exchange Act of 1934 prohibits our auditors from performing audit
services for us as well as any services not considered to be "audit services"
unless such services are pre-approved by the board of directors (in lieu of the
audit committee) or unless the services meet certain de minimis standards.
The board of directors has adopted resolutions that provide that the board
must:
Preapprove all audit services that the auditor may provide to us or any
subsidiary (including, without limitation, providing comfort letters in
connection with securities underwritings or statutory audits) as required
by Section 10A(i)(1)(A) of the Securities Exchange Act of 1934 (as amended
by the Sarbanes-Oxley Act of 2002).
Preapprove all non-audit services (other than certain de minimis services
described in Section 10A(i)(1)(B) of the Securities Exchange Act of 1934
(as amended by the Sarbanes-Oxley Act of 2002) that the auditors propose to
provide to us or any of its subsidiaries.
The board of directors considers at each of its meetings whether to approve
any audit services or non-audit services. In some cases, management may present
the request; in other cases, the auditors may present the request. The board of
directors has approved Gordon Hughes & Banks LLP performing our audit for the
2003 and 2004 fiscal years, as well as tax services for the 2003 and 2004 fiscal
years.
The percentage of the fees for audit, audit-related, tax and other services
were as set forth in the following table:
------------------ ----------------------------------------------------------
Percentage of total fees paid to Gordon Hughes & Banks LLP
------------------ ----------------------------------------------------------
Fiscal Year 2003 Fiscal Year 2002
------------------ -------------------------------- -------------------------
Audit fees 70% 71%
------------------ -------------------------------- -------------------------
Audit-related fees 8% 8%
------------------ -------------------------------- -------------------------
Tax fees 22% 21%
------------------ -------------------------------- -------------------------
All other fees 0% 0%
------------------ -------------------------------- -------------------------
31
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the Registrant
has duly caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
September 22, 2003
ASPEN EXPLORATION CORPORATION,
a Delaware Corporation
By: /s/ Robert A. Cohan
------------------------------
Robert A. Cohan
President, Chief Executive Officer, and
Chief Financial Officer
Pursuant to the requirement of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated:
Date Name and Title Signature
September 22, 2003 Robert A. Cohan /s/ Robert A. Cohan
Principal Executive Officer, ----------------------
Principal Financial Officer Robert A. Cohan
Director
September 22, 2003 R. V. Bailey /s/ R. V. Bailey
Chairman of the Board ----------------------
Director R. V. Bailey
September 22, 2003 Robert F. Sheldon /s/ Robert F. Sheldon
Director ----------------------
Robert F. Shelton
32
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----
Report of Independent Auditors' Report................................... 33
Financial Statements as of June 30, 2003 and June 30, 2002:
Consolidated Balance Sheets.............................................. 34-35
Consolidated Statements of Operations.................................... 36
Consolidated Statement of Stockholders' Equity........................... 37
Consolidated Statements of Cash Flows.................................... 38
Notes to Consolidated Financial Statements............................... 39-61
INDEPENDENT AUDITORS' REPORT
Board of Directors
Aspen Exploration Corporation and Subsidiary
Denver, Colorado
We have audited the consolidated balance sheets of Aspen Exploration
Corporation and Subsidiary as of June 30, 2003 and 2002 and the related
consolidated statements of operations, stockholders' equity, and cash
flows for the years ended June 30, 2003 and 2002. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that
we plan and perform the audits to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and significant
estimates made by management as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the consolidated financial position
of Aspen Exploration Corporation and Subsidiary as of June 30, 2003 and
2002, and the results of their consolidated operations and cash flows
for the years ended June 30, 2003 and 2002 in conformity with
accounting principles generally accepted in the United States of
America.
/s/ GORDON, HUGHES & BANKS, LLP
--------------------------------
GORDON, HUGHES & BANKS, LLP
Greenwood Village, Colorado
August 14, 2003
33
Item 7. Financial Statements and Supplementary Data
------- -------------------------------------------
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
ASSETS
June 30,
2003 2002
----------- -----------
Current Assets:
Cash and cash equivalents, including $516,365 and
$822,060 of invested cash in 2003 & 2002, respectively
(Note 1) ................................................ $ 776,566 $ 916,001
Precious metals (Note 1) .................................. 18,823 18,823
Accounts & trade receivables .............................. 269,259 365,705
Accounts receivable - related party (Notes 1 and 7) ....... 6,302 12,872
Prepaid expenses .......................................... 22,181 19,820
----------- -----------
Total current assets ...................................... 1,093,131 1,333,221
----------- -----------
Investment in oil & gas properties, at cost (full cost method
of accounting) (Note 9) ................................. 6,723,579 5,427,741
Less accumulated depletion and valuation allowance ...... (2,674,469) (2,262,649)
----------- -----------
4,049,110 3,165,092
----------- -----------
Property and equipment, at cost:
Furniture, fixtures & vehicles ........................... 112,562 112,562
Less accumulated depreciation ........................... ( 64,178) ( 45,810)
----------- -----------
48,384 66,752
----------- -----------
Cash surrender value, life insurance (Note 2) ............... -0- 239,095
----------- -----------
Total assets ................................................ $ 5,190,625 $ 4,804,160
=========== ===========
(Statement Continues)
See Summary of Accounting Policies and Notes to Consolidated Financial Statements
34
Item 7. Financial Statements and Supplementary Data
------- -------------------------------------------
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS (Continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
June 30,
2003 2002
----------- -----------
Current liabilities:
Accounts payable and accrued expenses ................................ $ 581,895 $ 236,587
Accounts payable - related party (Note 7) ............................ 17,685 21,260
Advances from joint interest owners .................................. 150,021 230,775
----------- -----------
Total current liabilities ......................................... 750,401 488,622
----------- -----------
Asset retirement obligation (Note 15) ................................ 17,841 -0-
Deferred income taxes (Note5) ........................................ 131,350 89,250
----------- -----------
Total long term liabilities .......................................... 149,191 89,250
----------- -----------
Total liabilities .................................................. 899,592 577,872
----------- -----------
Stockholders' equity:
(Notes 1 and 4):
Common stock, $.005 par value:
Authorized: 50,000,000 shares
Issued and outstanding: At June 30, 2003 and June 30, 2002:
5,863,828 ....................................................... 29,320 29,320
Capital in excess of par value ....................................... 6,025,797 6,025,797
Accumulated deficit .................................................. (1,756,900) (1,814,677)
Deferred compensation................................................ (7,184) (14,152)
----------- -----------
Total stockholders' equity ........................................... 4,291,033 4,226,288
----------- -----------
Total liabilities and stockholders' equity ........................... $ 5,190,625 $ 4,804,160
=========== ===========
See Summary of Accounting Policies and Notes to Consolidated Financial Statements
35
Item 7. Financial Statements and Supplementary Data
------- -------------------------------------------
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
Year ended June 30,
2003 2002
----------- -----------
Revenues:
Oil and gas (Note 9) ...................................... $ 1,068,798 $ 693,421
Management fees (Note 9) .................................. 245,023 134,729
Interest and other income ................................. 9,852 41,372
----------- -----------
Total revenues .............................................. 1,323,673 869,522
----------- -----------
Costs and expenses:
Oil and gas production .................................... 159,948 117,014
Aspen Power Systems expense (Note 14) ..................... -0- 25,500
Depreciation, depletion and amortization .................. 428,964 358,912
Interest expense .......................................... -0- 479
Selling, general and administrative ...................... 632,035 604,606
----------- -----------
Total costs and expenses .................................... 1,220,947 1,106,511
----------- -----------
Operating income (loss) ..................................... 102,726 (236,989)
(Provision for) recovery of income taxes .................... (42,100) 114,904
----------- -----------
Income (loss) before cumulative effect of change in
accounting principle ...................................... 60,626 (122,085)
----------- -----------
Cumulative effect of change in accounting principle, net of
income taxes .............................................. (2,849) -0-
----------- -----------
Net income (loss) ........................................... $ 57,777 $ (122,085)
=========== ===========
Basic earnings (loss) per common share
Income (loss) before cumulative effect of change in
accounting principle ...................................... $ .01 $ (.02)
Cumulative effect of change in accounting principle, net of
income taxes ............................................. $ -- $ --
----------- -----------
Net income (loss) ......................................... $ .01 $ (.02)
=========== ===========
Diluted earnings (loss) per common share.....................
Income (loss) before cumulative effect of change in
accounting principle ...................................... $ .01 $ (.02)
Cumulative effect of change in accounting principle, net of
income taxes ............................................. $ -- $ --
----------- -----------
Net income (loss) ......................................... $ .01 $ (.02)
=========== ===========
Basic weighted average number of common shares
outstanding .............................................. 5,863,828 5,863,828
=========== ===========
Diluted weighted average number of common shares
outstanding .............................................. 6,083,528 5,863,828
=========== ===========
See Summary of Accounting Policies and Notes to Consolidated Financial Statements
36
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
Common Stock (par $.005)
Shares ------------------------ Retained Deferred Total
outstanding Par Value APIC Earnings Compensation Equity
----------- ----------- ----------- ----------- ----------- -----------
Balance, June 30, 2001 .............. 5,812,205 $ 29,060 $ 6,015,279 $(1,692,592) $ (17,208) $ 4,334,539
Options exercised by director ....... 51,623 260 (260) -- -- --
Amortization of deferred compensation -- -- -- -- 13,834 13,834
Options granted to consultant ....... -- -- 10,778 -- (10,778) --
Net loss ............................ -- -- -- (122,085) -- (122,085)
----------- ----------- ----------- ----------- ----------- -----------
Balance, June 30, 2002 .............. 5,863,828 $ 29,320 $ 6,025,797 $(1,814,677) $ (14,152) $ 4,226,288
Amortization of deferred compensation -- -- -- -- 6,968 6,968
Net income .......................... -- -- -- 57,777 -- 57,777
----------- ----------- ----------- ----------- ----------- -----------
Balance, June 30, 2003 .............. 5,863,828 $ 29,320 $ 6,025,797 $(1,756,900) $ (7,184) $ 4,291,033
=========== =========== =========== =========== =========== ===========
See Summary of Accounting Policies and Notes to Consolidated Financial Statements
37
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended June 30,
2003 2002
----------- -----------
Cash flows from operating activities:
-------------------------------------
Net income (loss) ........................................................... $ 57,777 $ (122,085)
Adjustments to reconcile net income to net cash
provided (used) by operating activities:
Amortization of deferred compensation .................................. 6,968 13,834
Depreciation, depletion, and amortization .............................. 431,813 358,912
Changes in assets and liabilities:
Decrease in receivable and prepaid expenses ............................ 100,655 190,660
Increase (decrease) in accounts payable, accrued expenses and
advances from joint owners ........................................... 261,779 (993,025)
Increase (decrease) in deferred income taxes payable ................... 42,100 (89,250)
----------- -----------
Net cash provided (used) by operating activities .............................. 901,092 (640,954)
Cash flows from investing activities:
-------------------------------------
Additions to oil and gas properties ......................................... (1,378,356) (1,122,906)
Producing oil and gas properties purchased .................................. -0- (72,629)
Office equipment purchased .................................................. -0- (8,194)
Sale of oil and gas equipment ............................................... 28,865 26,998
Sale of oil and gas properties .............................................. 69,869 38,103
----------- -----------
Net cash (used) by investing activities ....................................... (1,279,622) (1,138,628)
Cash flows from financing activities:
-------------------------------------
Proceeds from Split dollar life insurance ................................... 239,095 -0-
----------- -----------
Net increase (decrease) in cash and cash equivalents .......................... (139,435) (1,779,582)
Cash and cash equivalents, beginning of year .................................. 916,001 2,695,583
----------- -----------
Cash and cash equivalents, end of year ........................................ $ 776,566 $ 916,001
=========== ===========
Other information:
------------------
Interest paid ................................................................. $ -0- $ 479
=========== ===========
Income taxes paid (refunded).................................................. $ -0- $ (24,954)
=========== ===========
Non-cash investing and financing activities:
--------------------------------------------
Asset retirement obligation ................................................. $ (16,223) $ -0-
=========== ===========
Exercise of stock options ................................................... $ -0- $ 260
=========== ===========
See Summary of Accounting Policies and Notes to Consolidated Financial Statements
38
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business
------------------
We were incorporated under the laws of the State of Delaware on
February 28, 1980 for the primary purpose of acquiring, exploring and
developing oil and gas and other mineral properties. Our principal
executive offices are located at 2050 S. Oneida St., Suite 208,
Denver, Colorado 80224. Our telephone number is (303) 639-9860, and
our facsimile number is 303-639-9863. We are currently engaged
primarily in the exploration and development of oil and gas properties
in California, although we have a significant amount of geologic data
regarding uranium prospects in Wyoming and precious mineral prospects
in Alaska. We also have a 25% interest in Aspen Power Systems, LLC, a
company we incorporated to investigate, finance, and construct
electrical power generation projects.
Oil and Gas Exploration and Development. Our major emphasis has been
our participation in the oil and gas segment acquiring interests in
producing oil or gas properties and participating in drilling
operations. We engage in a broad range of activities associated with
the oil and gas business in an effort to develop oil and gas reserves.
With the assistance of our management, independent contractors
retained from time to time by Aspen, and, to a lesser extent,
unsolicited submissions, we have identified and will continue to
identify prospects that we believe are suitable for drilling and
acquisition. Currently, our primary area of interest is in the state
of California. We have acquired a number of interests in oil and gas
properties in California, as described below in more detail. In
addition, we also act as operator for a number of our producing wells
and receive management fee revenues for these services.
Power Generation. In 1999, we formed a subsidiary named Aspen Power
Systems, LLC ("APS"), a Colorado limited liability company to provide
an opportunity for Aspen to participate in the growing demand for
electrical power generated by turbines. Our objectives for APS were to
seek opportunities or situations where our analysis indicated that a
gas turbine generation plant could be constructed and operate
profitably. Any plant construction would require a significant amount
of capital for property acquisition, permitting, engineering and
design, and construction. Neither Aspen nor the other owners of APS
were able to provide this required capital. Consequently, any such
activities would have required the availability of funds from third
parties, and we could not offer any assurance that such funding would
be available when needed on commercially-reasonable terms.
Accordingly, APS ceased operations effective December 31, 2002.
A summary of our Company's significant accounting policies follows:
Consolidated Financial Statements
---------------------------------
The consolidated financial statements include our Company and its
wholly-owned subsidiary, Aspen Gold Mining Company. Significant
intercompany accounts and transactions, if any, have been eliminated.
The subsidiary is currently inactive.
The equity method was used to account for our Company's 25% interest
in APS. Using the equity method, an investment in a company is
recorded at acquisition cost which is subsequently adjusted for the
Company's share of dividends, earnings, or losses. Effective December
31, 2002 APS ceased operations.
Statement of Cash Flows
-----------------------
For statement of cash flows purposes, we consider short-term
investments with original maturities of three months or less to be
cash equivalents. Cash restricted from use in operations beyond three
months is not considered a cash equivalent.
39
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Management's Use of Estimates
-----------------------------
Accounting principles generally accepted in the United States of
America require us to make certain estimates and assumptions that
affect the reported amounts of assets and liabilities and the
disclosure of contingent liabilities at the date of the financial
statements and reported amounts of revenues and expenses. Actual
results could differ from those estimates.
The mining and oil and gas industries are subject, by their nature, to
environmental hazards and cleanup costs for which we carry catastrophe
insurance. At this time, we know of no substantial costs from
environmental accidents or events for which we may be currently
liable. In addition, our oil and gas business makes it vulnerable to
changes in wellhead prices of crude oil and natural gas. Such prices
have been volatile in the past and can be expected to be volatile in
the future. By definition, proved reserves are based on current oil
and gas prices and estimated reserves. Price declines reduce the
estimated quantity of proved reserves and increase annual depletion
expense (which is based on proved reserves).
Investment in Unconsolidated Companies
--------------------------------------
The equity method of accounting is used for all investments in which
our interest is 20% or more. Under the equity method, we record our
share of the investee's net income or (loss) as an increase or
(decrease) of its investment less its share of dividends or
distributions from the investee. Investments in business entities in
which we own less than 20% of the company are recorded using the cost
basis of the investment. Under the cost method, our share of net
income or loss is not recorded. Our share of the investee's dividends
or distributions is recorded as income on the accrual basis.
Impairment of Long-lived Assets
-------------------------------
Long-lived assets and identifiable intangibles are reviewed for
impairment whenever events or changes in circumstances indicate that
the carrying amount may not be recoverable. If the expected
undiscounted future cash flow from the use of the assets and their
eventual disposition is less than the carrying amount of the assets,
an impairment loss is recognized and measured using the asset's fair
value or discounted cash flows.
Financial Instruments
---------------------
The carrying value of current assets and liabilities reasonably
approximates their fair value due to their short maturity periods. The
carrying value of our debt obligations reasonably approximates their
fair value as the stated interest rate approximates current market
interest rates of debt with similar terms.
Precious Metals and Revenues
----------------------------
Precious metals inventories are valued at the lower of cost (specific
identification method) or market. There is no allowance for unrealized
losses against inventories due to market decline at June 30, 2003.
There were no sales of gold from inventory for the years ended June
30, 2003 and 2002.
Oil and Gas Properties
----------------------
We follow the "full-cost" method of accounting for our oil and gas
properties. Under this method, all costs associated with property
acquisition, exploration and development activities, including
40
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
internal costs that can be directly identified with those activities,
are capitalized within one cost center. No gains or losses are
recognized on the receipt of prospect fees or on the sale or
abandonment of oil and gas properties, unless the disposition of
significant reserves is involved.
Depletion and amortization of our full-cost pool is computed using the
units-of-production method based on proved reserves as determined
annually by us and independent engineers. An additional depletion
provision in the form of a valuation allowance is made if the costs
incurred on our oil and gas properties, or revisions in reserve
estimates, cause the total capitalized costs of our oil and gas
properties in the cost center to exceed the capitalization ceiling.
The capitalization ceiling is the sum of (1) the present value of our
future net revenues from estimated production of proved oil and gas
reserves applicable to the cost center plus (2) the lower of cost or
estimated fair value of our cost center's unproved properties less (3)
applicable income tax effects. The valuation allowance was $281,719 at
June 30, 2003 and 2002 (Note 9). Depletion and amortization expense
was $410,596 and $341,236 for the years ended June 30, 2003 and 2002,
respectively.
Property and Equipment
----------------------
Depreciation and amortization of our property and equipment are
expensed in amounts sufficient to relate the expiring costs of
depreciable assets to operations over estimated service lives,
principally using the straight-line method. Estimated service lives
range from three to eight years. When assets are sold or otherwise
disposed of, the cost and accumulated depreciation are removed from
the accounts and any resulting gain or loss is reflected in operations
in the period realized. Depreciation expense was $18,368 and $17,676
for the years ended June 30, 2003 and 2002, respectively.
Deferred Compensation Costs
---------------------------
We record the fair value of stock bonuses to employees and consultants
as an expense and an increase to paid-in capital in the year of grant
unless the bonus vests over future years. Bonuses that vest are
deferred and expensed ratably over the vesting period. During the
fiscal year ended June 30, 2003 and 2002, we expensed $6,968 and
$13,834, respectively, in stock bonuses.
Allowance for Bad Debts
-----------------------
We consider accounts receivable to be fully collectible as recorded as
of June 30, 2003 and 2002; accordingly, no allowance for doubtful
accounts is required.
Revenue Recognition
-------------------
Sales of oil and gas production are recognized at the time of delivery
of the product to the purchaser.
Management fees from outside parties are recognized at the time the
services are rendered.
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.
41
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 $57,777 for the year ended June 30, 2003 and a net
loss of $122,085 for the year ended June 30, 2002. Because of the net
loss for the year ended June 30, 2002, the basic and diluted average
outstanding shares are considered the same, since including the shares
would have an antidilutive effect on loss per share calculation.
2003
-----------------------------
Per
Net Share
Income Shares Amount
------ ------ ------
Basic earnings per share:
Net income and
share amounts $57,777 5,863,828 $ .01
Dilutive securities
stock options 776,000
Repurchased shares (556,300)
-------------------------------
Diluted earnings per share:
Net income and assumed
share conversion $57,777 6,083,528 $ .01
========= ========= =====
Segment Reporting
-----------------
We follow SFAS No. 131, "Disclosure about Segments of an Enterprise
and Related Information", which amended the requirements for a public
enterprise to report financial and descriptive information about its
reportable operating segments. Operating segments, as defined in the
pronouncement, are components of an enterprise about which separate
financial information is available that is evaluated regularly by us
in deciding how to allocate resources and in assessing performance.
The financial information is required to be reported on the basis that
is used internally for evaluating segment performance and deciding how
to allocate resources to segments.
Income Taxes
------------
We account for income taxes under SFAS No. 109, "Accounting for Income
Taxes". Temporary differences are differences between the tax basis of
assets and liabilities and their reported amounts in the financial
statements that will result in taxable or deductible amounts in future
years.
Stock Award and Stock Option Plans
----------------------------------
We grant common stock and stock options to employees and non-employees
and apply Accounting Principles Board (APB) Opinion No. 25 (APB 25),
"Accounting for Stock Issued to Employees", and related
Interpretations in accounting for all stock award and stock option
plans for employees and directors.
42
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Following the guidance of APB 25, compensation cost has been
recognized for stock options issued to employees and directors as the
excess of the market price of the underlying common stock on the date
of the grant over the exercise price of the Company's stock options on
the date of the grant.
SFAS No. 123, "Accounting for Stock-Based Compensation", requires us
to provide pro forma information regarding net income as if
compensation cost for the Company's stock option plans had been
determined in accordance with the fair value based method prescribed
in SFAS No. 123. To provide the required pro forma information, we
estimate the fair value of each stock option at the grant date by
using the Black-Scholes option-pricing model.
In certain circumstances, we issue common stock for invoiced services,
to pay creditors and in other similar situations. In accordance with
SFAS No. 123, payments in equity instruments to non-employees for
goods or services are accounted for by the fair value method, which
relies on the valuation of the service at the date of the transaction,
or public stock sales price, whichever is more reliable as a
measurement.
Recent Accounting Pronouncements
--------------------------------
In June 2002, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities". SFAS No. 146 addresses financial accounting and reporting
for costs associated with exit or disposal activities and nullifies
Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for
Certain Employee Termination Benefits and Other Costs to Exit an
Activity". SFAS No. 146 generally requires a liability for a cost
associated with an exit or disposal activity to be recognized and
measured initially at its fair value in the period in which the
liability is incurred. The pronouncement is effective for exit or
disposal activities initiated after December 31, 2002. The adoption of
SFAS No. 146 has had no impact on its financial position or results of
operations.
SFAS No. 147, "Acquisitions of Certain Financial Institutions," was
issued in December 2002 and is not expected to apply to the Company's
current or planned activities.
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.
43
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 2 EMPLOYEE BENEFIT PLANS
Defined Contribution Plan
-------------------------
We have a 401(k) defined contribution plan that covers all employees.
Under the amended terms of the plan, an employee is eligible to
participate in the plan immediately upon being hired to work at least
1,000 hours per year and having attained age 21. Participants may
contribute up to a maximum of 11.75% of their pre-tax earnings (not to
exceed $12,000) to the plan. Under the plan, we may make discretionary
contributions to the plan. We made a contribution for fiscal 2003 in
the amount of $8,722 and no contribution for fiscal 2002.
Split Dollar Life Insurance Plan
--------------------------------
As part of the former President's (current Vice President's)
employment agreement, we purchased a split dollar life insurance
policy for the former President's benefit. We paid total premiums of
$360,000 on behalf of the former President, of which a portion
("split") constituted compensation for the former President. At each
anniversary we paid the former President an amount as a bonus to
reimburse the former President for personal income tax on his split.
No additional compensation has been recognized as reimbursement to the
former President for income taxes for the years ended June 30, 2003
and 2002. The former President's taxable amount was $-0- for fiscal
2003 and 2002, equal to the "economic benefit" attributed to the
former President as defined by the Internal Revenue Code. We paid no
premiums during fiscal 2003 and 2002.
In June 2003, the plan was terminated and we received a payment of
$239,095, the accumulated corporate premium payments due us. We have
fulfilled our obligations under this plan and no further action is
required of us.
Medical Benefit Plan
--------------------
For the fiscal years ended June 30, 2003 and 2002, we had a policy of
reimbursing employees for medical expenses incurred but not covered by
our paid medical insurance plan. Expenses reimbursed for fiscal 2003
and fiscal 2002 were $19,358 and $7,786, respectively. Under the terms
of a revised employment agreement (see Note 10) with Mr. Bailey,
effective May 1, 2003 he will be responsible for his own medical
insurance premiums and will no longer be reimbursed excess medical
expenses.
Note 3 MAJOR CUSTOMERS
We derived in excess of 10% of our revenue from various sources (oil
and gas sales and mineral royalties) as follows:
The Company
-------------
A B C D
----- ----- ----- -----
Year ended:
June 30, 2003 * 26% 51% *
June 30, 2002 30% * 33% 13%
* Less than 10% for fiscal 2003 and 2002.
44
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 4 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 have
been exercised.
During fiscal 2002 one director exercised his option for 80,000 shares
of our common stock granted November 1, 1997 at an average price of
$0.26 per share. As consideration for the option shares purchased, the
individuals 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 the transaction is a net increase to the common stock par value of
$260 and a corresponding decrease to additional paid in capital of
$260.
Total compensation expense in the statement of operations includes
amortization of prior stock awards of $6,968 and $13,834 for the years
ended June 30, 2003 and 2002, respectively.
As of June 30, 2003, we had an aggregate of 776,000 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.
45
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following information summarizes information with respect to options
granted under our equity plans:
Weighted Average
Number of Exercise Price of
Shares Shares Under Plans
------ ------------------
Outstanding balance June 30, 2001 180,000 $ .46
=====
Granted 676,000 .57
=====
Exercised (80,000) .57
=====
Forfeited or expensed -0- -
======= =====
Outstanding balance June 30, 2002 776,000 .58
=====
Granted -0- -
=====
Exercised -0- -
=====
Forfeited or expensed -0- -
======= =====
Outstanding balance June 30, 2003 776,000 $ .58
======= =====
The following table summarizes information concerning outstanding and
exercisable options as of June 30, 2003:
Outstanding Exercisable
---------------------------- -------------------------
Weighted
Average Weighted Weighted
Remaining Average Average
Exercise Number Contractual Exercisable Number Exercise
Price Outstanding Life In Years Price Exercisable Price
-------- ----------- ------------- ----------- ----------- --------
$.625 100,000 03/15/2004(1) $.625 100,000 $.625
.57 426,000 08/15/2005(1) .57 -0- .57
.57 250,000 08/15/2007(1) .57 -0- .57
-------
776,000
=======
(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
46
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
assumptions: no dividend yield, expected volatility of 14.9%, 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.
Options were granted but not exercisable to directors and employees during
the fiscal year 2002. An adjustment to net income for compensation expense
would be recorded under SFAS No. 123, on a pro forma basis, as reflected in
the following table:
2003 2002
------- -------
Net Income (loss): As Reported $57,777 $(122,085)
Pro Forma 33,516 (128,150)
Basic Earnings
Per Share: As Reported .01 (.02)
Pro Forma .01 (.02)
Diluted Earnings
Per Share: As Reported .01 (.02)
Pro Forma .01 (.02)
47
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 5 INCOME TAXES
We recorded deferred income taxes of $131,350 and $89,250 as of June
30, 2003 and 2002, respectively. We paid $800 in California state
income taxes in fiscal 2002. During 2003, we added approximately
$82,000 in net operating loss carryforwards for a total of
approximately $1,796,000 in available federal net operating loss
carryforwards. During 2002, we added approximately $1,100,000 in net
operating loss carryforwards for a total of approximately $1,714,000.
At June 30, 2003 and 2002, no net operating loss carryforwards
expired; but $1,200 in general business credits expired in fiscal
2002.
The deferred tax consequences of temporary differences in reporting
items for financial statement and income tax purposes are recognized,
if appropriate. Realization of future tax benefits related to the
deferred tax assets is dependent on many factors, including our
ability to generate taxable income within the net operating loss
carryforward period. We have considered these factors in reaching our
conclusion as to the valuation allowance for financial reporting
purposes.
The income tax effect of temporary differences comprising the deferred
tax assets and deferred tax liabilities on the accompanying balance
sheet is the result of the following:
2003 2002
--------- ---------
Deferred tax assets:
Federal tax loss
carryforwards $ 699,646 $ 490,862
--------- ---------
699,646 490,862
--------- ---------
Deferred tax (liabilities):
Property, plant and
equipment (3,324) (6,241)
Oil and gas properties (827,672) (573,871)
--------- ---------
(830,996) (580,112)
--------- ---------
$(131,350) $( 89,250)
========= =========
48
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A reconciliation between the statutory federal income tax rate (34%)
and the effective rate of income tax expense for the two years ended
June 30 is as follows:
2003 2002
--------- ---------
Statutory federal income
tax rate 34% 34%
Statutory state income tax
rate, net of federal benefit 9% 9%
Utilization of net operating
loss carryforwards and other (2%) 5.5%
--------- --------
Effective rate 41% 48.5%
========= ========
The provision for income taxes consists of the following components:
2003 2002
--------- ---------
Current tax expense (refund),
state $ -0- $ (25,654)
Deferred tax expense
(recovery) 42,100 (89,250)
--------- ---------
Total income tax
provision (recovery) $ 42,100 $(114,904)
========= =========
We have available federal net operating loss carryforwards of
approximately $1,796,000 (net operating losses expire beginning June
30, 2011 through the year ending June 30, 2023).
49
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6 SEGMENT INFORMATION
We operate in two industry segments within the United States: oil and
gas exploration and development electrical generation construction.
Identified assets by industry are those assets that are used in our
operations in each industry. Corporate assets are principally cash,
cash surrender value of life insurance, and furniture, fixtures and
vehicles.
We have adopted SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information". The adoption of SFAS No. 131
requires the presentation of descriptive information about reportable
segments which is consistent with that made available to our
management to assess performance.
The oil and gas segment derives its revenues from the sale of oil and
gas and prospect generation and management fees charged to
participants in our oil and gas ventures.
The electrical generation construction segment would have received its
revenues from the sale, design, construction and/or operation of gas
turbine or other electrical generation projects. As of June 30, 2002,
we were in the planning stage of this segment and no revenues have
been received. However, we did advance APS $5,500 for operating
expenses. As of December 31, 2002, APS ceased operations and no
further business activity is anticipated in this segment.
During the years ended June 30, 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.
Net sales in the oil and gas segment to two customers were
approximately $544,000 and $277,000, or 51% and 26%, respectively, for
fiscal 2003. Net sales to three customers were approximately $229,000,
$205,000 and $91,000, or 33%, 30% and 13%, respectively, for fiscal
2002.
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 $1,378,000 for the development of oil and
gas properties in fiscal 2003 and approximately $1,196,000 for the
development and acquisition of producing properties in fiscal 2002.
50
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Segment information consists of the following:
Oil and Gas Power Plant Corporate Consolidated
----------- ----------- --------- ------------
Revenues:
2003 $1,313,821 $ -0- $ 9,852 $1,323,673
2002 828,150 -0- 41,372 869,522
Income (loss) from
operations:
2003 $ 743,277 $ -0- $ (640,551) $ 102,726
2002 369,900 (25,500) (581,389) (236,989)
Identifiable assets:
2003 $4,324,671 $ -0- $ 865,954 $5,190,625
2002 3,543,669 -0- 1,260,491 4,804,160
Income tax expense
(recovery):
2003 $ 42,100 -0- $ -0- $ 42,100
2002 (114,904) -0- -0- (114,904)
Depreciation, depletion
and valuation charged to
identifiable assets:
2003 $ 410,596 $ -0- $ 18,368 $ 428,964
2002 341,236 -0- 17,676 358,912
Capital expenditures:
2003 $1,378,356 $ -0- $ -0- $1,378,356
2002 1,195,535 -0- 8,194 1,203,729
Note 7 RELATED PARTY TRANSACTIONS
During the years ended June 30, 2003 and 2002, we provided one vehicle
each to our president and vice president. We also paid travel, lodging
and meal expenses for spouses who, from time to time, accompanied
directors or officers when they were traveling or entertaining on
company business. The cost of these items to us totaled less than
$5,000 in each of the years ended June 30, 2003 and 2002. We believe
that the expenditures were to our benefit.
In January 1983, we entered into a Stock Purchase Agreement with our
former president, R. V. Bailey, whereby Mr. Bailey granted us an
option to purchase up to 75% of our common stock owned by him at his
death. The agreement was replaced by a Stock Purchase Agreement dated
June 4, 1993 which required us to apply 75% of any key man insurance
proceeds it received upon Mr. Bailey's death towards the purchase of
up to 75% of the common shares owned by him at the time of his death.
Mr. Bailey's estate was obligated to sell such shares to us. The
purchase price of the shares acquired under the Agreement was the fair
market value of the shares on the date of death. We and Mr. Bailey
agreed that the fair market value of the shares on the date of death
would not necessarily be the market price of the stock on the date of
death as quoted on the OTC Bulletin Board, or as reported by another
NASDAQ quotation service or any exchange on which our common stock was
quoted. The 1993 Agreement further required that we maintain one or
more life insurance policies on Mr. Bailey's life in the amount of
$1,000,000 for the purpose of this Agreement. Premiums for this policy
were $6,970 for each of the fiscal years ended June 30, 2003 and 2002.
In June 2003 the stock purchase agreement expired by its own terms and
was not renewed or replaced. On August 22, 2003 Mr. Bailey's life
insurance policy expired and was not renewed.
51
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
During fiscal 2002 we entered into a rental agreement with R. V.
Bailey to rent office space in Castle Rock, Colorado in an office
building owned by Mr. Bailey. The rental amount was $6,000 per year on
a month to month basis. This lease was terminated on April 30, 2003.
During fiscal 2003, we assigned the following overrides at no cost to
employees:
R. V. R. A. J. L.
Bailey Cohan Shelton
------ ----- -------
McCullough 36-1 1.683938% 1.683937% 0.641500%
Pope Bypass 1-5 1.065339% 1.566676% 0.501336%
R. V. Bailey, Vice President and former President and director of the
Company, Robert A. Cohan, President and director of the Company, have
working and royalty interests in certain of the California oil and gas
properties operated by us. The related parties paid for their
proportionate working interest share of all costs to acquire, develop
and operate these properties on the same terms as other unaffiliated
participants. Mr. Bailey and Mr. Cohan purchased working interests
amounts totaling $82,013 and $77,752, respectively, for the year ended
June 30, 2003, and $31,180 and $27,896, respectively, for the year
ended June 30, 2002. Mr. Bailey and Mr. Cohan also received royalty
interest amounts totaling $31,919 and $31,919, respectively, for the
year ended June 30, 2003, and $34,849 and $34,844, respectively, for
the year ended June 30, 2002. As of June 30, 2003, working interests
of us and related parties in certain producing California properties
are as set forth below:
GROSS WELLS NET WELLS
GAS GAS
--- ---
Aspen Exploration 52 7.07
R. V. Bailey 39 .87
R. A. Cohan 40 .60
R. K. Davis 46 .65
J. L. Shelton 24 .05
We have received advances from Messrs. Bailey, Cohan and Davis for
working interests in uncompleted wells of $5,895, $5,895 and $5,895,
respectively, as of June 30, 2003 and $5,306, $4,676 and $6,017 as of
June 30, 2002, respectively. Additionally, we owed Mr. Bailey $928 and
$5,171 for reimbursement of expenses made on our behalf as of June 30,
2003 and 2002, respectively. Messrs. Bailey, Cohan and Davis owed us
$3,474, $1,944 and $987, respectively, as of June 30, 2003 and $4,638,
$3,060 and $5,174, respectively, as of June 30, 2002 for their portion
of well operating expenses.
See Note 11 for additional related party disclosure.
Note 8 CONCENTRATION OF CREDIT RISK
Financial instruments, which potentially subject us to concentrations
of credit risk, consist principally of cash and cash equivalents,
accounts receivable and the cash surrender value of life insurance.
While as of June 30, 2003 we have approximately $823,208 in excess of
the Federal Deposit Insurance Corporation $100,000 limit at one bank,
we place our cash and cash equivalents with high quality financial
institutions in order to limit credit risk. Concentrations of credit
risk with respect to accounts receivable are limited since relatively
52
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
small amounts are due from each account, and the accounts are
distributed across unrelated businesses and individuals, with the
exception of two major gas purchasers, who normally settle within 25
days of the previous month's gas purchases. An international insurance
company held the cash surrender value of the split dollar life
insurance contract. During June 2003 we surrendered the insurance
contract for its cash value. We believe our exposure to credit risk is
minimal.
Cash equivalents are invested through a quality national brokerage
firm and a major regional bank. The cash equivalents consists of
liquid short-term investments. The Securities Investor Protection
Corporation insures the Fund's accounts at this brokerage firm and a
commercial insurer up to the total amount held in the account.
Note 9 OIL AND GAS ACTIVITIES
Capitalized costs
Capitalized costs associated with oil and gas producing activities are
as follows:
June 30,
2003 2002
---------- ----------
Proved properties $6,723,579 $5,427,741
---------- ----------
Accumulated depreciation,
depletion and
amortization (2,392,750) (1,980,930)
Valuation allowance (281,719) (281,719)
---------- ----------
(2,674,469) (2,262,649)
---------- ----------
Net capitalized costs $4,049,110 $3,165,092
========== ==========
53
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Results of operations
Results of operations for oil and gas producing activities are as
follows:
Year ended June 30,
2003 2002
------- --------
Revenues* $1,313,821 $ 828,150
Production costs (159,948) (117,014)
Depreciation and depletion (410,596) (341,236)
---------- ----------
Results of operations
(excluding corporate overhead) $ 743,277 $ 369,900
========== ==========
*Includes oil and gas related fees and management fees.
Fees charged by us to operate the properties totaled approximately
$20,420 per month in 2003 and $11,230 per month in 2002.
Unaudited oil and gas reserve quantities
----------------------------------------
The following unaudited reserve estimates presented as of June 30,
2003 and 2002 were prepared by an independent petroleum engineer.
There are many uncertainties inherent in estimating proved reserve
quantities and in projecting future production rates and the timing of
development expenditures. In addition, reserve estimates of new
discoveries that have little production history are more imprecise
than those of properties with more production history. Accordingly,
these estimates are expected to change as future information becomes
available.
Proved oil and gas reserves are the estimated quantities of crude oil,
condensate, natural gas and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions.
Proved developed oil and gas reserves are those reserves expected to
be recovered through existing wells with existing equipment and
operating methods.
54
Unaudited net quantities of proved and proved developed reserves of
crude oil (including condensate) and natural gas (all located within
the United States) are as follows:
Changes in proved reserves (Bbls) (MCF)
-------------------------- ----- -----
(in thousands)
Estimated quantity, June 30, 2001 13 2,243
Revisions of previous estimates 2 (115)
Discoveries - 258
Purchased - 51
Production ( 3) (227)
Sold ( 1) -
----- -----
Estimated quantity, June 30, 2002 11 2,210
Revisions of previous estimates ( 1) (184)
Discoveries - 481
Purchased - 221
Production ( 1) (248)
Sold ( 6) -
----- -----
Estimated quantity, June 30, 2003 3 2,480
===== =====
Proved reserves Developed
at year end Developed Non-Producing Total
--------------- --------- ------------- -----
(In Thousands)
Oil (Bbls)
June 30, 2003 - 3 3
June 30, 2002 7 4 11
Gas (MCF)
June 30, 2003 655 1,825 2,480
June 30, 2002 482 1,728 2,210
55
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unaudited standardized measure
------------------------------
The following table presents a standardized measure of the discounted
future net cash flows attributable to our proved oil and gas reserves.
Future cash inflows were computed by applying year-end prices of oil
and gas to the estimated future production of proved oil and gas
reserves. The future production and development costs represent the
estimated future expenditures (based on current costs) to be incurred
in developing and producing the proved reserves, assuming continuation
of existing economic conditions. Future income tax expenses were
computed by applying statutory income tax rates to the difference
between pre-tax net cash flows relating to our proved oil and gas
reserves and the tax basis of proved oil and gas properties and
available net operating loss carryforwards. Discounting the future net
cash inflows at 10% is a method to measure the impact of the time
value of money.
June 30,
2003 2002
---- ----
(in thousands)
Future cash inflows $ 12,967 $ 6,352
Future production and development costs (1,281) (772)
Future income tax expense (4,027) (1,779)
-------- -------
Future net cash flows 7,659 3,801
10% annual discount for estimated timing
of cash flows (2,826) (1,198)
-------- -------
Standardized measure of discounted future
net cash flows $ 4,833 $ 2,603
======== =======
56
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following presents the principal sources of the changes in the
standardized measure of discounted future net cash flows:
Years ended June 30,
2003 2002
---- ----
(in thousands)
Standardized measure of discounted
future net cash flows, beginning of year $ 2,603 $ 8,458
-------- --------
Sales and transfers of oil and gas produced,
net of production costs (909) (576)
Net changes in prices and production costs
and other 5,153 (9,368)
Net change due to discoveries 981 394
Acquisition of reserves 451 78
Revisions of previous quantity estimates 481 (468)
Development costs incurred 18 459
Accretion of discount 376 1,406
Sale of existing reserves (74) (6)
Net change in income taxes (1,156) 4,198
Other (3,091) (1,972)
-------- --------
2,230 (5,855)
-------- --------
Standardized measure of discounted future
cash flows, end of year $ 4,833 $ 2,603
======== ========
Net changes in prices and production costs of $5,153 were the result
of an increase in the price received for oil and gas at year end which
was offset slightly by an increase in operating costs associated with
more producing gas wells in 2003 than in 2002 and no oil wells. The
revision of previous estimates of $481 was the result of assigning
approximately 400 fewer barrels of recoverable oil and reducing
recoverable reserves of gas by approximately 180,000 MCF, while the
volumes were reduced, the price applied to the remaining recoverable
reserves increased substantially, resulting in the increase. All
adjustments were based on performance reviews of individual wells.
57
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 10 COMMITMENTS AND CONTINGENCIES
At June 30, 2003, we were committed to the following drilling and
development projects in California:
Project Aspen Cost
------- ----------
Mengali-Durst #22-1 $ 40,000
Sac Outing Farms #31-3 44,000
West Grimes 3-D 100,000
Verona Pipeline 70,000
---------
Total $ 254,000
---------
Employment contracts and termination of employment and change in control
arrangements:
Mr. Bailey: Effective May 1, 2003 we entered into a new employment
agreement with Chairman of the Board, R. V. Bailey. Some of the
pertinent provisions include an employment period ending May 1, 2009,
the title of Vice President subject to the general direction of the
President, Robert A. Cohan, and the Board of Directors of Aspen. Mr.
Bailey's salary will be $45,000 per year from May 1, 2003 to December
31, 2006 and $60,000 per year from January 1, 2007, ending May 1,
2009. Mr. Bailey will also participate in Aspen's stock options and
royalty interest programs. During the term of the agreement, we have
agreed to pay Mr. Bailey a monthly $1,700 allowance to cover such
items as prescriptions, medical and dental coverage for himself and
his dependents and other expenses not covered in the agreement.
Mr. Bailey's keyman life insurance policy terminated in August of this
year and will result in an annual savings of approximately $6,500. The
stock purchase agreement with Mr. Bailey was cancelled and replaced by
his current employment agreement. The agreement had provided that we
apply 75% of the $1,000,000 keyman life insurance to purchase up to
75% of the common shares owned by him at the time of his death. Mr.
Bailey will continue to use the Company vehicle and may trade the
current vehicle for a similar vehicle of his choice prior to June 30,
2006. During 2007 or thereafter, Mr. Bailey may purchase the vehicle
for $500.
We may terminate this agreement upon Mr. Bailey's death by paying his
estate all compensation that had or will accrue to the end of the year
of his death plus $75,000. Should Mr. Bailey become totally and
permanently disabled, we will pay Mr. Bailey one half of the salary
and benefits set forth in our agreement with him for the remainder of
the term of the agreement.
Mr. Cohan: On April 16, 1998, we entered into an employment agreement
with Robert A. Cohan, which provides for the payment of $90,000 for
the first year of employment, plus reimbursement of expenses,
including health insurance. We have renewed the agreement effective
April 15, 1999 to April 15, 2002 at the rate of $95,000 per year for
the year commencing April 15, 1999, $100,000 for the year commencing
April 15, 2000 and $105,000 for the year commencing April 15, 2001. On
August 1, 2001 Mr. Cohan's salary was increased to $125,000 per year.
Mr. Cohan's employment agreement expired by its own terms on April 15,
2002 and was replaced by an employment agreement dated January 1,
2003. Some of the pertinent provisions include an employment period
ending December 31, 2005, salary increases from $125,000 per year to
$135,000 per year effective April 15, 2003, and a further salary
increase to $145,000 per year from April 15, 2004 through the end of
the contract. Other benefits and duties will remain the same as the
previous employment contract. Prior to February 2000, we and Mr. Cohan
agreed to utilize a portion of Mr. Cohan's home in Bakersfield,
California from which to conduct Aspen's business. Mr. Cohan did not
charge Aspen any rent for the use of his home as a business office.
Aspen agreed to pay for all office supplies, communication and copy
58
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
equipment used by Mr. Cohan in his office, as well as the monthly
telephone expense incurred by Mr. Cohan on behalf of Aspen. On
February 7, 2000, we entered into a three-year lease of office space
in Bakersfield, California thereby alleviating the necessity of home
office reimbursement to Mr. Cohan.
Effective May 1, 2003, our Board of Directors appointed Robert A.
Cohan, President of Aspen Exploration Corporation, replacing Mr.
Bailey.
During fiscal 2002, we entered into a rental agreement with R. V.
Bailey to rent office space in Castle Rock, Colorado in an office
building owned by Mr. Bailey. The rental amount was $6,000 per year on
a month to month basis. This agreement was terminated effective May 1,
2003.
Note 11 INTERIM FINANCIAL DATA
The year-end adjustment that is material to the results of the fourth
quarter ending June 30, 2003 and June 30, 2002 is the adjustment to
depreciation, depletion and amortization as a result of receiving the
reserve study from an independent reservoir engineer. The aggregate
effect of this year-end adjustment to the results of the fourth
quarter was to decrease depletion expense for the fiscal year 2003
from an estimated $464,000 based on prior years' reserve studies to an
actual depletion expense of approximately $411,000, a decrease of
$53,000 or 11.4% for fiscal 2003 and approximately $447,000 to
approximately $341,000, a decrease of $106,000, or 24% for fiscal
2002.
Note 12 CONTRACTUAL OBLIGATIONS
We had five contractual obligations as of June 30, 2003. The following
table lists our significant liabilities at June 30, 2003:
Payments Due By Period
-------------------------------------------------------------------------------------
Less than
Contractual Obligations 1 year 2-3 years 4-5 years After 5 years Total
----------------------- ------ --------- --------- ------------- -----
Employment
Obligations $202,485 $373,300 $153,300 $60,300 $789,385
Operating leases 16,326 15,240 -0- -0- 31,566
-------- -------- -------- ------- --------
Total contractual
cash obligations $218,811 $388,540 $153,300 $60,300 $820,951
======== ======== ======== ======= ========
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 to December 31, 2003 for a lease rate of $1,261 per month.
We also subleased from R. V. Bailey, our vice president, a portion of
an office building owned by Mr. Bailey in Castle Rock, Colorado on a
month to month basis for $500 per month. This lease arrangement was
terminated on April 30, 2003. 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 years ended June 30, 2003 and 2002 were $28,536 and
$26,663, respectively.
59
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 13 ASPEN POWER SYSTEMS, LLC
During fiscal 1999 and 2000, we dedicated certain cash resources to
APS to investigate the economic possibilities of the sale, design,
construction and/or operation of gas turbines to produce electricity.
Through June 30, 2000, we expended approximately $130,000 on this
project, $45,657 of which was expensed in the twelve months ended June
30, 2000. During fiscal 2001, we advanced a further $20,000 to defray
APS operating costs which were recorded as a receivable at June 30,
2001. During fiscal 2002, an additional $5,500 was advanced to APS to
retire existing obligations of APS. Both the $20,000 and $5,500
advances were expensed by us at June 30, 2002. The funding to APS came
from our operating funds derived from oil and gas production. As
discussed above, we did not assign a value to the $130,000 note
receivable due from APS and do not anticipate any significant future
requirements to fund further projects of APS because APS ceased
operations effective December 31, 2002.
Note 14 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. As of June 30, 2003, we
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 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 5%. Revisions to the liability could occur due to changes in
plugging and abandonment costs, well useful lives or if federal or
state regulators enact new guidance on the plugging and abandonment of
wells.
Upon adoption of SFAS No. 143, we recorded a liability of $9,132,
increased net oil and gas property by $6,283 and recognized a one-time
cumulative effect of change in accounting principle of $2,849. We will
amortize the amount added to oil and gas properties and recognize
accretion expense in connection with the discounted liability over the
remaining useful lives of the respective wells. A reconciliation of
our liability for the year ended June 30, 2003 is as follows:
Upon adoption at July 1, 2002 $ 9,132
Liabilities incurred 7,091
Liabilities settled -0-
Accretion expense 1,618
Revision to estimate -0-
--------
Asset retirement obligation as of
June 30, 2003 $ 17,841
========
60
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following unaudited pro forma information has been prepared to
give effect to the adoption of SFAS No. 143 as if it had been adopted
on July 1, 2002. The effect on fiscal year 2001 is considered
immaterial.
Year Ended
----------
June 30,
2002
----
Net (loss) income
As reported $ (122,085)
Accretion of retirement
obligation (net of tax) (2,849)
----------
Pro forma $ (124,934)
==========
Basic net income (loss) per
common share:
As reported $ (.02)
Pro forma $ (.02)
Diluted net income (loss) per
common share:
As reported $ (.02)
Pro forma $ (.02)
61