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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------------------
FORM 10-KSB
(Mark One)
[ ] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934.
For the fiscal year ended June 30, 2004
[ ] 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
--- ---
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
--- ---
Aspen's revenues for the fiscal year ended June 30, 2004 were $1,823,936.
At September 23, 2004, the aggregate market value of the shares held by
non-affiliates was approximately $4,632,009. The aggregate market value was
calculated by multiplying the mean of the closing bid and asked prices ($1.295)
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
(3,576,841).
At September 23, 2004, there were 5,958,979 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, regulation of the
Securities and Exchange Commission, and common law.
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 have an interest in two
inactive subsidiaries: a 25% interest in Aspen Power Systems, LLC (a company
that has not been engaged in business since 2002), and Aspen Gold Mining Co., a
company that has not been engaged in business since 1995.
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) which
expired on their own terms in April and May of 2004.
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
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
2
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 2004 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, 2004, crude oil and natural gas sales and revenues from operating
oil and gas properties accounted for $1,820,680, or 99.8% of our total revenues;
while $3,256, or .2%, 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.
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 2004 we obtained more
than 10% of our revenues from sales to Calpine Corporation and Enserco Energy,
3
Inc. and ConocoPhillips; in 2003 more than 10% of our revenues derived from
Calpine Corporation and Enserco Energy, Inc. 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. We are currently in the process of renewing the trademark
registration.
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, 2004, we employed two full-time and one part-time person. We
also employ independent contractors and other consultants, as needed.
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, 2004, we participated in the drilling
of 7 gross (1.38 net) wells, of which 5 gross (1.05 net) were completed as gas
wells and 2 were dry holes. Of the 7 wells drilled, 1 operated gas well was
drilled in the Grimes Field, 1 operated gas well was drilled in the Winters
Field, 2 operated gas wells were drilled in the West Grimes Field, 1 operated
gas well was drilled in the Denverton Creek Field and 2 dry holes were drilled
in the Kirk Buckeye Field.
In addition to the drilling activity, 3 operated gas wells and 1
non-operated gas well were acquired from an independent oil and gas company.
These wells are located in Glenn, Sutter and Yolo Counties, California.
4
West Grimes Field, Colusa County, California
--------------------------------------------
The WGU #15-8, located in the West Grimes Field, Colusa County, California,
was directionally drilled to a depth of 7,750 feet and encountered approximately
60 feet of potential net gas pay in the Forbes Formation. Production casing was
run based on very promising mud log and electric log responses. The well
commenced production in August 2004 at the prolific rate of 3,700 MCFPD.
Production in mid-September has declined to 1,750 MCFPD. The WGU #16-3 was
drilled to a depth of 7,929 feet and encountered potential gas pay in various
intervals in the Forbes formation. The well was completed and put on production
in early August and is currently flowing 130 MCFPD.
These wells were drilled based on a recently acquired 10.5 square mile 3-D
seismic program located over Aspen's 5,000 plus leased acres in this field.
Approximately 12 additional excellent drilling prospects have been identified.
The wells in this field produce from multiple Forbes intervals ranging in depth
from 6,000 feet to 8,500 feet and have produced over 80 BCF of gas to date.
Numerous wells in this immediate area have produced at very prolific flow rates
(4,000 MCFPD), have yielded excellent per well reserves (3 to 4 BCF per well),
and have long productive well lives. Several of the 10 producing wells that
Aspen acquired in this field last year have been producing for 40 years. Aspen
believes that several of these wells may have additional gas potential in
behind-pipe zones, which have not yet been perforated. Aspen has a 21% operated
working interest in this field.
The Morris #12-2, located in the West Grimes Field, Colusa County,
California, was drilled to a depth of 8,400 feet and encountered approximately
73 feet of net gas pay (100 feet gross) in the Forbes Formation. This zone was
perforated and tested at a prolific stabilized rate of 4,845 MCFPD of gas with a
flowing tubing pressure of 3,350 psig and a flowing casing pressure of 3,400
psig. The shut in tubing pressure was 3,475 psig. Aspen has a 21% operated
working interest in this field. We anticipate that drilling will commence on the
fourth well in this project, the WGU #15-9, in October 2004.
Momentum Farmout, Colusa, Yolo, Sutter and Solano Counties, California
----------------------------------------------------------------------
Aspen recently acquired a farmout package consisting of 6 quality drilling
prospects, which are leased and defined by 3-D seismic data and well control.
These prospects will be drilled during the 2004 - 2005 drilling seasons (4 wells
in 2004 and 2 wells in 2005). Aspen has a 28.75% operated working interest in
these wells. The first well drilled in this package, the Ettl #1-10, located in
the Grimes Gas Field, Sutter County, California, was drilled to a depth of 7,600
feet to test three potential Forbes targets. The Grimes Gas Field has produced
approximately 650 BCF (billion cubic feet) of gas and is currently producing
11,000 MCFPD. The well was successfully completed and commenced gas sales in
July 2004 at the rate of 500 MCFPD.
The second well drilled, the Chickohominy #1-12, located in the Winters Gas
Field, Yolo County, California, was drilled to a depth of 5,050 feet, and
encountered 25 feet of extremely permeable and porous potential gas pay in the
Winters Formation. The well was perforated on June 28th, and tested at a stable
gas rate of 2,540 MCFPD with a flowing tubing pressure of 1,725 psig. Gas sales
commenced in August 2004 at a stable rate of 1,000 MCFPD with a flowing tubing
pressure of 1,900 psig.
The Griffin #1-1, located in the Winters Gas Field, Yolo County,
California, was drilled to a depth of 5,000 feet, and encountered 15 net feet of
extremely permeable and porous gas pay in the McCune Sand. This zone was
perforated and tested at a stabilized rate of 1,385 MCFPD on a 12/64 inch choke.
There was very little pressure drawdown during the flow test. The shut in
pressure is approximately 2,000 psig. This was the third successful well drilled
on a recently acquired farmout package consisting of 6 quality drilling
prospects which are leased and defined by 3-D seismic data and well control.
We anticipate that drilling will commence on the fourth well in this
project, the Meckfessel #1-24, in October 2004. Aspen has a 28.75% operated
working interest in these wells.
Millar Field, Yolo County, California
-------------------------------------
Aspen successfully recompleted its Pope Bypass #1-5 well, located in the
Millar Field, Yolo County, California, approximately 50 miles southwest of
Sacramento. This well was drilled to a depth of 7,800 feet and we believe
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
5
interval (top of 6 foot sand) was perforated and gas sales commenced on June 20,
2003 at a rate of 1,000 MCFPD. This thin zone produced 252,000 MCF though
February 2004 when it watered out. The well was recompleted in March 2004 at the
top (7,282 feet to 7,285 feet) of a 25 foot thick zone and after five months of
production is still flowing 1,500 MCFPD with a flowing tubing pressure of 2,000
psig. Aspen currently has a 25.40% operated working interest in this well.
Feather River Prospect, Sutter County, California
-------------------------------------------------
Aspen 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 2004 at a rate of
500 MCFPD after pipeline construction is completed. 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 6 attempts in this field during the
last 3 fiscal years. These wells produce from multiple horizons in the Forbes
formation from depths ranging from 7,500 feet to 9,500 feet. Aspen has operated
working interests in these wells ranging from approximately 15% to 36%.
Sour Grass Prospect, Tehama County, California
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The Sour Grass prospect area is a 2,300 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 in addition to 2-D seismic survey
information. Several 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 will drill 1 additional well in this area this 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 drilled the Emigh #35-6 in this field this year to a depth of 11,200
feet. Production casing was run based on encouraging mud log and electric log
responses. The well was perforated in May 2004 and commenced gas sales in June
2004. Aspen has a 5.25% operated working interest in this well.
Aspen has now drilled 13 gas wells out of 16 attempts in this field and has
already produced approximately 10 BCF of gas. Aspen is the operator of all the
wells in this field and has working interests ranging from 5% to 32% (with 25%
working interest being the most common).
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
approximately 600 MCFPD of high quality natural gas (1085 BTU) with numerous
behind-pipe zones in many of the wells.
Sac Valley Acquisition
----------------------
Effective, October 1, 2003, Aspen acquired certain natural gas producing
wells located in the Sacramento Valley of northern California. The acquisition
consisted of 4 operated gas wells and 1 non-operated gas well located in various
fields in the vicinity of Aspen's existing operations. Aspen's net working
interests acquired in the operated wells range from 38% to 90%. These wells have
flat decline rates with long productive lives. Aspen believes that excellent
behind-pipe potential exists in one of the wells.
6
Drilling Activity:
The following table sets forth the results of our drilling activities
during the fiscal years ended June 30, 2002, 2003 and 2004:
Drilling Activity
-----------------
Gross Wells Net Wells
Year Total Producing Dry Total Producing Dry
---- ----- --------- --- ----- --------- ---
2002 Exploratory 6 4 2 1.32 .98 .34
2003 Exploratory 8 7 1 1.45 1.22 .23
2004 Exploratory 7 5 2 1.38 1.05 .33
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, 2004, 2003, and 2002, and the
average sales prices, average production costs and direct lifting costs per unit
of production.
Years Ended June 30,
--------------------
2004 2003 2002
---- ---- ----
Net Production
Oil (Bbls) 357 768 3,055
Gas (MMcf) 305 248 227
Average Sales Prices
Oil (per Bbl) $31.65 $26.13 $20.20
Gas (per Mcf) $ 5.17 $ 4.23 $ 2.78
Average Production Cost1
Per equivalent
Bbl of oil $15.73 $12.83 $11.21
Average Lifting Costs2
Per equivalent
Bbl of oil $ 4.73 $ 3.61 $ 2.86
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
---------------------------------------------------------------------------
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, 2004:
Producing and Shut-In Wells
Gross Net1
----- ----
Prospect Gas Gas
-------- --- ---
California:
Anderson Farms 1 0.20000
Anderson Unit 1-2 1 0.90000
Armstrong 17-4 1 0.36000
Balsdon 3-21 1 0.05983
Balsdon 6 1 0.04134
Chickohominy 1-12 1 0.28750
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 0.32550
Emigh 35-2 1 0.32800
Emigh 35-3 1 0.11900
Emigh 35-6 1 0.05514
Ettl 1-10 1 0.28750
Firestone 1-10 1 0.03850
Gay Unit 1 0.21000
Grey Wolf 1 1 0.18000
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
Malton Arbuckle 1 1 0.51667
Mapco-Kylling 1 1 0.37800
NL&F 26-1 1 0.23334
Noseco 1 1 0.67900
Parsons 1 1 0.45000
Pinheiro 1-10 1 0.01890
Pinheiro 2-10 1 0.01890
Pope Bypass 1-5 1 0.25400
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
South Sycamore 7 1 0.21000
South Sycamore 20 1 0.21000
Tiahrt 1-4 1 0.13617
Verona Farms 1 1 0.20000
West Grimes Unit 14 2 0.42000
West Grimes Unit 15 4 0.84000
West Grimes Unit 16 3 0.61000
Strain Ranches 16-3 1 0.21000
Strain Ranches 17-1 1 0.21000
Walter Trust 1 1 0.07291
Zimmerman 1-24 1 0.23334
TOTAL 58 12.2651
8
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.
Developed Acreage Table
Aspen's Developed Acres1
Prospect Gross2 Net3
-------- ----- ---
California:
Denverton Creek 1,431 216
Feather River 320 64
Firestone 1-10 160 6
Grey Wolf 1 120 22
Kirk Buckeye 800 241
Malton Black
Butte Field 2,003 279
McCullough 36-1 583 115
Momentum 296 85
Phillips Acquisition 1,120 79
Pope Bypass 1-5 120 30
Sac Valley Acquisition 1,324 555
Sour Grass 1,312 306
West Grimes 2,197 461
------- ------
TOTAL 11,786 2,459
====== ======
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, 2004:
Overriding Royalty Interests
Productive
Wells Gross
Prospect Interest(%) Gas Acreage1
-------- ----------- --- --------
California:
Denverton Creek 1.142816 1 80
Malton Black Butte 7.500000 1 645
Grimes Gas 0.101590 1 615
--- -----
TOTAL 3 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, 2004:
Undeveloped Acreage
-------------------
Gross Net
----- ---
California:
Denverton Creek 514 69
Echo 467 338
Feather River 320 64
Orion 750 150
Sacreiter 245 245
Sour Grass 1,028 224
West Grimes 2,869 586
------- ------
TOTAL 6,193 1,676
======= =====
Gas Delivery Commitments:
Effective June 1, 2004, we entered a contract to sell 750 MMBTU of gas per
day at a fixed price of $6.34 less transportation and other expenses. The
contract is for the term June 1 - August 31, 2004 and contains monetary
penalties for non-delivery of the gas. Subsequent to year-end, we completed the
contract with no penalties realized.
Drilling Commitments:
We have a proposed drilling budget for the period August through
December 2004. The budget includes drilling five wells in the
Sacramento gas province of northern California, the acquisition of one
gas well, and the completion of the Verona Pipeline. Our share of the
estimated costs to complete this program is set forth in the following
table:
Drilling Completion & Acquisition
Area Wells Costs Equipping Costs Costs Total
-------------------------- -------- ------------- -------------------- --------------- -----------
Momentum Farmout 2 $ 61,000 $191,000 $252,000
Various Counties, CA
West Grimes Field 2 189,000 147,000 336,000
Colusa County, CA
Sour Grass Prospect 1 72,000 60,000 132,000
Tehama County, CA
Lambie 3-4 1 82,500 82,500
Verona Pipeline - 70,000 70,000
-------- ------------- -------------------- --------------- -----------
Total Expenditure 6 $322,000 $468,000 $82,500 $872,500
======== ============= ==================== =============== ===========
Reserve Information - Oil and Gas Reserves:
Cecil Engineering, Inc. evaluated our oil and gas reserves attributable
to our properties at June 30, 2004. 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
10
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.
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, 2004 and 2003. See
Note 10 to the Consolidated Financial Statements and the above discussion.
Estimated Proved Reserves
Proved Reserves Oil (Bbls) Gas (Mcf)
--------------- ---------- ---------
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
Revisions of previous estimates (1,000) (411,000)
Discoveries 0 527,000
Production 0 (305,000)
Purchased 0 243,000
----------- ---------
Estimated quantity, June 30, 2004 2,000 2,534,000
=========== =========
Developed and Undeveloped Reserves
----------------------------------
Developed Undeveloped Total
--------- ----------- -----
Oil (Bbls)
June 30, 2004 - 2,000 2,000
June 30, 2003 - 3,000 3,000
Gas (Mcf)
June 30, 2004 1,236,000 1,298,000 2,534,000
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 10 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, 2004.
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
11
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.
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, 2004 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 entered an lease agreement for our Bakersfield, California office, which
consists of approximately 546 square feet. The Bakersfield, California lease
requires lease payments of ranging from $730 to $770 over the term of the lease
which 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, 2004, 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, 2003 and 2004, we believe that we were
in full compliance with these rules.
Quarter Ended
Sept., 2003 Dec., 2003 March, 2004 June 30, 2004
----------- ---------- ----------- -------------
Common Stock ("ASPN")
High $.85 $.97 $.95 $1.23
Low $.56 $.55 $.58 $0.65
Quarter Ended
Sept., 2002 Dec., 2002 March, 2003 June 30, 2003
----------- ---------- ----------- -------------
Common Stock ("ASPN")
High $.58 $.38 $.52 $.86
Low $.21 $.31 $.34 $.40
12
Holders:
As of June 30, 2003 and 2004, there were approximately 1,182 and 1,158
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.'
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, 2004, 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, 2004.
-----------------------------------------------------------------------------------------------
Equity Compensation Plan Information (1)
-----------------------------------------------------------------------------------------------
Plan Category and Number of Weighted-average Number of securities remaining
Description Securities to be exercise price of available for future issuance
issued upon outstanding under equity compensation
exercise of options, warrants, plans (excluding securities
outstanding and rights reflected in column (a))
options,
warrants, and
rights
(a) (b) (c)
--------------------- ------------------ --------------------- --------------------------------
Equity compensation
plans approved by
security holders -0- $-0- -0-
--------------------- ------------------ --------------------- --------------------------------
Equity compensation
plans not approved
by security holders 484,000 $0.57 NA
--------------------- ------------------ --------------------- --------------------------------
Total 484,000 $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.
13
Recent Sales of Unregistered Securities -- Item 701 Disclosure.
The following sets forth information regarding sales of unregistered securities
during the June 30, 2004 fiscal year and subsequently as required by Item 701 of
Regulation S-B.
Tri-Power Resources, Inc.
On June 28, 2004, Tri-Power Resources, Inc., a privately-held California
corporation, purchased a $300,000 convertible debenture from Aspen Exploration
Corporation. Aspen also issued to Tri-Power warrants to purchase 300,000 shares
of its common stock which, if exercised before March 31, 2005, will result in
the purchaser acquiring warrants to purchase an additional 300,000 shares.
Shares potentially issuable to Tri-Power total 900,000.
(a) The transaction was completed effective June 28, 2004. We issued the
following securities to one accredited investor in exchange for the investor's
payment to Aspen of $300,000:
a convertible debenture with a principal amount of $300,000, bearing
interest at 4% per annum and
300,000 common stock warrants exercisable as described in paragraph (c)
below.
(b) There was no placement agent or underwriter for the transaction and Aspen
did not publicly offer any securities.
(c) The total offering price was $300,000. No underwriting discounts or
commissions were paid.
If the holder exercises the warrant before June 30, 2005, Aspen will
receive an additional $330,000 ($1.10 per share); if the holder exercises the
warrant before June 30, 2006 but after June 30, 2005, Aspen will receive an
additional $360,000 ($1.20 per share).
If the holder exercises the warrant before March 31, 2005, the holder will
receive an additional warrant exercisable to purchase 300,000 shares at $1.25
per share.
In any case, the warrant (and any additional warrant) will expire unless
exercised by June 30, 2006.
(d) We relied on the exemption from registration provided by Sections 4(2) and
4(6) under the Securities Act of 1933 for this transaction and Regulation D. We
did not engage in any public advertising or general solicitation in connection
with this transaction which was in negotiation for more than several weeks. We
provided the accredited investor with disclosure of all aspects of our business,
including providing the accredited investor with our reports filed with the
Securities and Exchange Commission, our press releases, access to our auditors,
and other financial, business, and corporate information. Based on our
investigation, we believe that the accredited investor obtained all information
regarding Aspen it requested, received answers to all questions it (and its
advisors) posed, and otherwise understood the risks of accepting our securities
for investment purposes.
(e) The convertible debenture convertible into common stock at the effective
price of $1.00 per share (subject to dilution adjustment in the event of stock
splits, stock dividends, and similar transactions, the "Conversion Price"). The
convertible debenture will automatically convert into common stock at the
Conversion Price if the market price for Aspen's common stock as reported by the
OTC Bulletin Board remains above $1.00 per share for ten consecutive trading
days.
Each common stock warrant is exercisable to purchase one share of common
stock through June 30, 2006. The warrants may only be exercised to the extent
that there is an exemption available for the exercise at the time of exercise.
If exercised before March 31, 2005, the exercise price is $1.10 per share,
and the holder will receive one share of common stock and one additional warrant
(exercisable through June 30, 2006 at $1.25 per share) for each warrant
exercised.
If exercised before June 30, 2005, the exercise price is $1.10 per share,
and the holder will receive one share of common stock for each warrant
exercised.
14
If exercised after June 30, 2005 but before the expiration date (June 30,
2006), the exercise price is $1.20 per share, and the holder will receive one
share of common stock for each warrant exercised.
Aspen has the right to redeem the common stock purchase warrants issued at
any time for the payment of $0.10 per warrant provided there is an effective
registration statement for the resale of the shares underlying the warrant at
the time of the redemption, and provided further that the market price of
Aspen's common stock has exceeded $2.50 per share for twenty of the thirty
trading days preceding the date Aspen gives notice of its intention to redeem
the warrants. There are no other registration rights associated with the
securities issued to the accredited investor.
(f) We will use the proceeds for expenses of drilling and (if warranted)
completing oil and gas wells.
Conversion of Convertible Debenture
On July 15, 2004, Aspen gave the holder notice that the conditions for the
automatic conversion of the convertible debenture had been met, and issued
300,500 shares of common stock upon such conversion.
(a) The conversion was completed effective July 15, 2004. We issued the 300,500
shares of our restricted common stock to one accredited investor in conversion
of and outstanding convertible debenture and accrued interest.
(b) There was no placement agent or underwriter for the transaction and Aspen
did not publicly offer any securities.
(c) Aspen received no proceeds as a result of the conversion of the debenture.
(d) We relied on the exemption from registration provided by Sections 3(a)(9),
4(2) and 4(6) under the Securities Act of 1933 for this transaction and
Regulation D. We did not engage in any public advertising or general
solicitation in connection with this conversion. We provided the accredited
investor with disclosure of all aspects of our business, including providing the
accredited investor with our reports filed with the Securities and Exchange
Commission, our press releases, access to our auditors, and other financial,
business, and corporate information. Based on our investigation, we believe that
the accredited investor obtained all information regarding Aspen it requested,
received answers to all questions it (and its advisors) posed, and otherwise
understood the risks of accepting our securities for investment purposes.
(e) We issued common stock to the holder upon conversion of the convertible
debenture.
(f) We received no proceeds from the conversion of the debenture.
15
Stock Issuances pursuant to exercise of options
On May 14, 2004, three directors and one executive officer of Aspen, and
one staff member, exercised common stock purchase options they held and acquired
shares of Aspen's common stock as described below. In each case, the persons
exercising the options paid the exercise price by returning common stock to
Aspen.
----------------------- ------------- ------------- ------------ -----------
Name and Principal Date Number of Exercise Option
Position Common Price paid Exercise
Shares Sold ($) Price Per
(#) Share ($)
----------------------- ------------- ------------- ------------ -----------
R. A. Cohan, 5/14/2004 50,000 28,500 .57
director and
president, options
exercised
----------------------- ------------- ------------- ------------ -----------
R. V. Bailey, 5/14/2004 50,000 28,500 .57
director and vice
president, options
exercised
----------------------- ------------- ------------- ------------ -----------
R. F. Sheldon, 5/14/2004 50,000 28,500 .57
director, options
exercised
----------------------- ------------- ------------- ------------ -----------
J. L. Shelton, 5/14/2004 17,000 9,690 .57
office manager,
options exercised
----------------------- ------------- ------------- ------------ -----------
R. K. Davis, 5/14/2004 25,000 14,250 .57
consultant, options
exercised
----------------------- ------------- ------------- ------------ -----------
Total 192,000 109,440 .57
----------------------- ------------- ------------- ------------ -----------
(a) The transactions were each effective May 14, 2004. In the aggregate, Aspen
issued 192,000 shares of its common stock upon the exercise of options at a
price of $0.57 per share. The option holders surrendered a total of 96,850
shares of Aspen's common stock in payment of the exercise price.
(b) There was no underwriter involved in this transaction, and Aspen did not
publicly offer any securities. Each of the persons who acquired shares has had
prior relationships with Aspen extending over a period of many years.
(c) No securities were sold for cash. Aspen accepted shares of its common stock
at its market price as payment of the exercise price for the options.
(d) We relied on the exemption from registration provided by Sections 3(a)(9)
and 4(2) under the Securities Act of 1933 for this transaction and Regulation D.
Each of the persons receiving our common stock was and remains a shareholder of
Aspen, and no person paid any consideration other than the exchange of
securities with Aspen. Furthermore, we did not engage in any public advertising
or general solicitation in connection with this transaction which was in
negotiation for more than several weeks. We provided the investors with
disclosure of all aspects of our business, including providing the accredited
investor with our reports filed with the Securities and Exchange Commission, our
press releases, access to our auditors, and other financial, business, and
corporate information. Based on our investigation, we believe that the investors
obtained all information regarding Aspen it requested, received answers to all
questions it (and its advisors) posed, and otherwise understood the risks of
accepting our securities for investment purposes.
(e) Not applicable, since the securities issued are neither convertible nor
exchangeable.
16
(f) Not applicable, inasmuch as Aspen did not receive any cash from the issuance
of the securities.
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION OR PLAN OF
------------------------------------------------------------------------------
OPERATION
---------
The management discussion and analysis and other portions of this report
contain forward-looking statements (as such term is defined in Section 21E of
the Securities Exchange Act of 1934, as amended). These statements reflect our
current expectations regarding our possible future results of operations,
performance, and achievements. These forward-looking statements are made
pursuant to the safe harbor provisions of the Private Securities Litigation
Reform Act of 1995.
Wherever possible, we have tried to identify these forward-looking
statements by using words such as "anticipate," "believe," "estimate," "expect,"
"plan," "intend," and similar expressions. These statements reflect our current
beliefs and are based on information currently available to us. Accordingly,
these statements are subject to certain risks, uncertainties, and contingencies,
which could cause our actual results, performance, or achievements to differ
materially from those expressed in, or implied by, such statements. These risks,
uncertainties and contingencies include, without limitation, the factors set
forth in our Form 10-KSB under "Item 6. Management's Discussion and Analysis of
Financial Conditions or Plan of Operation - Factors that may affect future
operating results."
Overview
--------
Aspen Exploration Corporation was organized in 1980 for the purpose of
acquiring, exploring and developing oil and gas and other mineral properties.
Since 1996, we have focused our efforts on the exploration, development and
operation of natural gas properties in the Sacramento Valley of northern
California. We are currently the operator of 46 gas wells and have a
non-operated interest in 16 additional gas wells.
We currently have offices in Bakersfield, California and Denver, Colorado
and have 2 full time and one part time employees as well as the Chairman of the
Board who allocates a portion of his time to the Company. We also make extensive
use of consultants for the conduct of our business, ranging from financial,
engineering, land, legal, and geological and geophysical specialists.
We will typically review 20 to 25 prospects for every well we participate
in, using 3-D seismic and well control geology to evaluate each prospect. Our
goal is to identify low to moderate risk wells with good gas reserve potential.
Where possible, we attempt to be the operator of each property we invest
in. Our knowledge of drilling and operating wells in the Sacramento Valley
allows us to maximize the potential return of each property. Administrative
charges to the properties help cover approximately 37% of our selling, general
and administrative expenses.
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
17
vary substantially. Any significant variance in the assumptions could materially
affect the estimated quantity and value of the reserves, which could affect the
carrying value of our oil and gas properties and/or the rate of depletion of the
oil and gas properties. Actual production, revenues and expenditures with
respect to our reserves will likely vary from estimates, and such variances may
be material.
Many factors will affect actual future net cash flows, including:
- the amount and timing of actual production;
- supply and demand for natural gas;
- curtailments or increases in consumption by natural gas purchasers;
and
- changes in governmental regulations or taxation.
Property, Equipment and Depreciation:
-------------------------------------
We follow the full-cost method of accounting for oil and gas properties.
Under this method, all productive and nonproductive costs incurred in connection
with the exploration for and development of oil and gas reserves are
capitalized. Such capitalized costs include lease acquisition, geological and
geophysical work, delay rentals, drilling, completing and equipping oil and gas
wells, including salaries, benefits and other internal salary related costs
directly attributable to these activities. Costs associated with production and
general corporate activities are expensed in the period incurred. Interest costs
related to unproved properties and properties under development are also
capitalized to oil and gas properties. If the net investment in oil and gas
properties exceeds an amount equal to the sum of (1) the standardized measure of
discounted future net cash flows from proved reserves, and (2) the lower of cost
or fair market value of properties in process of development and unexplored
acreage, the excess is charged to expense as additional depletion. Normal
dispositions of oil and gas properties are accounted for as adjustments of
capitalized costs, with no gain or loss recognized.
We apply SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets." Under SFAS No. 144, long-lived assets and certain
intangibles are reported at the lower of the carrying amount or their estimated
recoverable amounts. Long-lived assets subject to the requirements of SFAS No.
144 are evaluated for possible impairment through review of undiscounted
expected future cash flows. If the sum of undiscounted expected future cash
flows is less than the carrying amount of the asset or if changes in facts and
circumstances indicate, an impairment loss is recognized.
Asset retirement obligations:
-----------------------------
We recognize the future cost to plug and abandon gas wells over the
estimated useful life of the wells in accordance with the provision of SFAS No.
143. SFAS No. 143 requires that we record a liability for the present value of
the asset retirement obligation with a corresponding increase to the carrying
value of the related long-lived asset. We amortize the amount added to the oil
and gas properties and recognize accretion expense in connection with the
discounted liability over the remaining lives of the respective gas wells. Our
liability estimate is based on our historical experience in plugging and
abandoning gas wells, estimated well lives based on engineering studies,
external estimates as to the cost to plug and abandon wells in the future and
federal and state regulatory requirements. The liability is discounted using a
credit-adjusted risk-free rate of 6.25%. 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.
Outlook and Trends
------------------
We expect our natural gas production to increase substantially during
fiscal 2005 due to recent drilling successes. Total production for the year will
depend on the number of wells successfully completed, the date they are put on
line, their initial rate of production, and their production decline rates. We
also anticipate that the average price for our product will be in the range of
$4.75 to $6.25 per MMBTU for the fiscal year ended June 30, 2005.
Over the past five years we have been able to replace our produced reserves
and increase our yearly natural gas production. We have also benefited from a
general increase in natural gas prices over the past two years, from a low of
$2.78 per MMBTU average during the first quarter of fiscal 2003 to $5.97 per
MMBTU for the quarter ended June 30, 2004.
18
Quantitative and Qualitative Disclosure About Risk
--------------------------------------------------
Our ability to replace reserves, dissipated through production or
recalculation, will depend largely on how successful our drilling and
acquisition efforts will be in the future. While we cannot predict the future,
our historic success ratio over the past 3 1/2 years has been 86%. With the use
of 3-D seismic and well control data, interpreted by our geological and
geophysical consultants, we feel we can manage our dry hole risk as well as
anyone in the industry.
Commodity prices are impacted by many factors that are outside of our
control. Historically, commodity prices have been volatile and we expect them to
remain volatile. Commodity prices are affected by changes in market demands,
overall economic activity, weather, pipeline capacity constraints, inventory
storage levels, basis differentials and other factors. As a result, we cannot
accurately predict future natural gas and NGL (natural gas liquids) prices, and
therefore, we cannot determine what effect increases or decreases in production
volumes will have on future revenues.
On regulatory and operational matters, we actively manage our exploration
and production activities. We value sound stewardship and strong relationships
with all stakeholders in conducting our business. We attempt to stay abreast of
emerging issues to effectively anticipate and manage potential impacts to our
operations.
To manage commercial risk, we may use financial tools to hedge the price we
will receive for our product. The primary purpose of hedging is to provide
adequate return on our investments, grow our reserves while leaving as much
commodity price upside as possible.
We are exposed to interest rate risk to the extent we have borrowed funds.
During December 2003, we borrowed $225,000 from a bank for a modest acquisition.
We currently pay 2% over the bank's prime rate for that facility. At June 30,
2004, the effective interest rate was 6.5%. In June 2004, we issued a
convertible debenture for $300,000 with interest at 4% per annum.
Liquidity and Capital Resources
-------------------------------
We have historically financed our operations with internally generated
funds and limited borrowings from banks and third parties, and farmout
arrangements, which permit third parties (including some related parties) to
participate in our drilling prospects. Our principal uses of cash are for
operating expenses, the acquisition, drilling and production of prospects, the
acquisition of producing properties, working capital, servicing debt and the
payment of income taxes.
Cash of $1,536,500 and $901,100 was provided by our operations for the
twelve months ended June 30, 2004 and 2003. The cash flow from operations
increase of $635,400, or 71%, was because of:
Increased oil and gas sales ($1,588,250 in 2004 as compared to $1,068,800
in 2003);
A $100,650 decrease in accounts receivable during 2003 (which provided
cash) compared to a decrease in accounts receivable during 2004 of
$288,300; and
A $874,200 increase in accounts payable and accrued expenses in 2004 (which
conserved cash) compared to a $261,780 increase in accounts payable and
accrued expenses in 2003.
Investing activities used cash to increase capitalized oil and gas costs of
$1,448,100 and $1,378,400 in the twelve months ended June 30, 2004 and 2003.
Cash in the current twelve month period ended June 30, 2004 was used for lease
acquisition and seismic work ($886,800), intangible drilling and well workovers
($615,400), and the purchase of oil and gas well equipment ($130,000). These
expenditures were offset by the sale of interests in wells to be drilled charged
to third party investors.
At June 30, 2004, our balance sheet also reflected short-term debt in the
form of a convertible debenture in the amount of $300,000. This debt converted
into common stock during July 2004 and is no longer a liability.
19
Contractual Obligations
-----------------------
We had six contractual obligations as of June 30, 2004 (not including the
convertible debenture that converted to common stock in July 2004 and,
therefore, is no longer outstanding). The following table lists our significant
liabilities at June 30, 2004:
Payments Due By Period
------------------------------------------------------------------------------------------
Less than After
Contractual Obligations 1 year 2-3 years 4-5 years 5 years Total
---------------------------------- --------------- -------------- -------------- --------------- ---------------
Employment Obligations $210,400 $240,800 $147,400 -0- $ 598,600
Bank Loans 150,000 260,719 -0- -0- 410,719
Operating Leases 16,686 6,160 -0- -0- 22,846
--------------- -------------- -------------- --------------- ---------------
Total contractual
cash obligations $377,086 $507,679 $147,400 $-0- $1,032,165
=============== ============== ============== =============== ===============
Future Commitments
------------------
We have a proposed drilling, completion and construction budget for the
period July through December 2004. The budget includes drilling six wells in the
Sacramento gas province of northern California, the acquisition of one gas well,
and the completion of the Verona Pipeline. Our share of the estimated costs to
complete this program over the next six months is set forth in the following
table:
Drilling Completion & Acquisition
Area Wells Costs Equipping Costs Costs Total
------------------------------- ---------- ----------- ------------------- -------------- -----------
Momentum Farmout 2 $61,000 $191,000 $252,000
Various Counties, CA
West Grimes Field 2 189,000 147,000 336,000
Colusa County, CA
Sour Grass Prospect 1 72,000 60,000 132,000
Tehama County, CA
Lambie 3-4 1 82,500 82,500
Verona Pipeline - 70,000 70,000
---------- ----------- ------------------- -------------- -----------
Total Expenditure 6 $322,000 $468,000 $82,500 $872,500
========== =========== =================== ============== ===========
We maintain office space in Denver, Colorado, our principal office, and
Bakersfield, California. The Denver office consists of approximately 1,108
square feet with an additional 750 square feet of basement storage. We entered
into a one-year lease agreement through December 31, 2004 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, 2004
and 2003 were $24,370 and $28,536, 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 $57,700 per year.
Our working capital deficit (current assets less current liabilities) at
June 30, 2004, was $101,086. We anticipate that our working capital and
anticipated cash flow from operations and future successful drilling will be
20
sufficient to pay our current liabilities as long as our gas production
continues to provide us with sufficient cash flow. As discussed below, this is
dependent, in part, on maintaining or increasing our level of production and the
national and world market maintaining its current prices for our gas production.
Our capital requirements can fluctuate over a twelve month period because
our drilling program is usually carried out in California's dry season, from
late April until November, after which wet weather either precludes further
activity or makes it cost prohibitive.
We believe that internally generated funds will be sufficient to finance
our drilling and operating expenses for the next twelve months. However, during
December 2003, we borrowed $225,000 from a bank in California and used the
proceeds to acquire various working interests in producing gas wells located in
several counties in the Sacramento Valley, California. We also issued a
convertible debenture for $300,000 in June 2004 (which converted to common stock
in July 2004 and was reclassified from a current liability to equity) to finance
our share of additional wells drilled in July and August of 2004 (which was
converted to common stock in July 2004 and was reclassified from a current
liability to equity). If our drilling efforts are successful, the anticipated
increased cash flow from the new gas discoveries, in addition to our existing
cash flow, should be sufficient to fund our share of any future completion and
pipeline costs.
21
Results of Operations
June 30, 2004 Compared to June 30, 2003
---------------------------------------
For the twelve months ended June 30, 2004, our operations continued to be
focused on the production of oil and gas, and the investigation for possible
acquisition of producing oil and gas properties in California. During the 2004
period, our revenues increased by more than $500,000 as compared to the
comparable period of our 2003 fiscal year because of:
Increased production (305,000 MMBTU sold as compared to 248,000 MMBTU
sold during our 2003 fiscal year, a 23% increase); and
Increased price received for our production (an average of $5.17 per
MMBTU during our 2004 fiscal year as compared to $4.23 per MMBTU
received during that period in 2003).
The foregoing increases were offset in part by decreased management
fees received ($232,430 during 2004 as compared to $245,023 during 2003).
Although we were operators of more wells during 2004 (46 wells compared to 38
wells in 2003), our management fees were impacted by a lesser amount of
promotional drilling costs charged to third parties in 2004.
The following table sets forth certain items from our Consolidated Statements of
Operations as expressed as a percentage of total revenues, shown by year for
fiscal 2004, 2003 and 2002:
For the Year Ended
-----------------------------------------
6/30/2004 6/30/2003 6/30/2002
------------ -------------- -------------
Total revenues 100.0% 100.0% 100.0%
Oil & gas production costs 13.3 12.1 13.5
------------ -------------- -------------
Income from operations 86.7 87.9 86.5
------------ -------------- -------------
Costs and expenses
Depreciation and depletion 31.9 32.4 41.3
Selling, general and administrative 34.4 47.7 69.5
Interest expense .3 .0 .5
Aspen Power System - - 2.9
------------ -------------- -------------
Total costs and expenses 66.6 80.1 114.2
------------ -------------- -------------
Income before income taxes 20.0 7.8 (27.7)
Provision for income taxes 9.0 3.2 13.2
Cumulative effect of accounting charge - .2 -
------------ -------------- -------------
Net income (loss) 11.0 4.4 (14.5)
============ ============== =============
22
To facilitate discussion of our operating results for the years ended June 30,
2004 and 2003, we have included the following selected data from our
Consolidated Statements of Operations:
Comparison of the Fiscal
Twelve Months Ended June 30, Increase (Decrease)
-------------------------------------- ----------------------------------
2004 2003 Amount Percentage
----------------- -------------------- ----------------- ----------------
Revenues:
Oil and gas sales $1,588,250 $1,068,798 $ 519,452 48.6%
Management fees 232,430 245,023 (12,593) (5.1)
Interest and other 3,256 9,852 (6,596) (67.0)
----------------- -------------------- ----------------- ----------------
Total revenues 1,823,936 1,323,673 500,263 37.8
----------------- -------------------- ----------------- ----------------
Cost and expenses:
Oil and gas production 242,472 159,948 82,524 51.6
Depreciation and depletion 581,402 428,964 152,438 35.5
Selling, general and administrative 628,265 632,035 (3,770) (.6)
Interest expense 6,152 - 6,152 NMF
----------------- -------------------- ----------------- ----------------
Total costs and expenses 1,458,291 1,220,947 237,344 19.4%
----------------- -------------------- ----------------- ----------------
Net operating income $ 365,645 $ 102,726 $ 262,919 255.9%
================= ==================== ================= ================
Central to the issue of success of the twelve months operations ended June 30,
2004 is the discussion of changes in oil and gas sales, volumes of natural gas
sold and the price received for those sales. We present them here in tabular
form:
Oil & Gas MMBTU (1)
Sales Sold Price/MMBTU
-------------- --------------- ------------------
2004
---------------------------
lst Quarter $ 341,926 72,600 $ 4.75
2nd Quarter 362,942 79,900 4.64
3rd Quarter 401,941 71,900 5.28
4th Quarter 481,441 80,600 5.97
-------------- --------------- ------------------
Year to date 1,588,250 305,000 5.17
-------------- --------------- ------------------
2003
---------------------------
lst Quarter 198,431 65,800 2.78
2nd Quarter 241,700 63,700 3.76
3rd Quarter 314,222 57,900 5.47
4th Quarter 314,445 60,600 5.19
-------------- --------------- ------------------
Year to date 1,068,798 248,000 4.23
-------------- --------------- ------------------
Year to date change
Amount $519,452 57,000 $.94
Percentage 48.6% 23% 22.2%
(1) Price per MMBTU may not agree with oil and gas sales because of the
inclusion of oil and NGL sales.
Oil and gas revenue, volumes sold and price received for our product have shown
a steady improvement over the past twelve months of fiscal 2004 and the twelve
months of fiscal 2003. As the table above notes, revenue has increased
approximately 49% when comparing the two twelve month periods ended June 30,
2004 and 2003. Volumes sold increased approximately 23%, while the price
received for our product increased 22%.
Total revenue increased $519,452, or 49% when comparing the two periods, while
operating and production costs increased $82,500, or 52%. As set out in the
previous paragraph, revenue from gas sales increased because the volumes sold
from new and existing wells increased and natural gas prices increased
substantially. Production costs increased due to the addition of newly
productive wells.
23
A significant ratio presented is the percentage of management fees charged to
operated wells versus our general and administrative costs. This coverage of
general and administrative costs remained fairly constant at approximately 39%
for the twelve months ended June 30, 2003 to approximately 37% at June 30, 2004.
When comparing general and administrative expense for 2004 and 2003, costs
declined slightly by $3,770, or .6%. Results of operations and net income (loss)
before income taxes are presented in the following table:
Quarterly Financial Information (unaudited)
(1) Net Income Net Income (loss)
Total Operating (Loss) Before Per Share
2004 Revenues Income Income Taxes Basic Diluted
------------------------ --------------- -------------- ----------------- ----------- -------------
lst Quarter $ 388,337 $ 348,739 $ 50,197 $.014 $ .014
2nd Quarter 433,317 365,761 93,022 .016 .016
3rd Quarter 440,127 354,642 76,762 .010 .010
4th Quarter 558,899 509,066 145,664 .025 .024
--------------- -------------- ----------------- ----------- -------------
Total 1,820,680 1,578,208 365,645 0.06 0.06
--------------- -------------- ----------------- ----------- -------------
2003
------------------------
lst Quarter 264,896 232,246 (44,238) (.008) (.007)
2nd Quarter 279,080 237,155 (15,660) (.003) (.003)
3rd Quarter 337,476 271,845 28,748 .005 .005
4th Quarter 432,369 272,421 133,876 .023 .022
--------------- -------------- ----------------- ----------- -------------
Total $ 1,313,821 $ 1,103,667 $102,726 $ .02 $ .02
--------------- -------------- ----------------- ----------- -------------
(1) Operating income is oil and gas sales plus management fees less direct
operating costs.
As can be seen in the table, revenues and operating income have improved
significantly when comparing the twelve month periods ended June 30, 2004 and
2003. We believe this is due to the steady increase in production volumes sold
in each subsequent quarter and the fact that we have enjoyed an appreciating
price received for our product. Operating income has increased because
production costs have increased at a lesser rate than production and prices.
Our future success in the oil and gas industry will depend on the cost of
finding oil or gas reserves to replace our production, the volume of our
production and the prices we receive for sale of our production. These factors
are subject to all of the risks associated with operations in the oil and gas
industry, many of which are beyond our control.
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, 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.
24
(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) Our ability to compete with other companies (many of whom may be
better financed than are we) for the purchase of properties, hiring of
drilling rigs for exploration and development work, and completing
wells for production. Many of these considerations are
price-sensitive, and the cost will depend on many factors associated
with the oil and gas industry regionally, nationally, and
internationally, and over which we have no control.
(9) 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 2,473,867 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.
Off Balance Sheet Arrangements
------------------------------
We do not have any off balance sheet accounting arrangements except in
connection with joint ventures and operating agreements for the ownership and
drilling of wells. Aspen's balance sheet only reflects its own interest in these
arrangements, however, and has no interest in any ownership by third parties
(some of whom are related parties).
25
ITEM 7. FINANCIAL STATEMENTS
The information required by this item begins on page 41 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.
ITEM 8B. OTHER INFORMATION
Not applicable. All required information has been reported herein.
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.
26
Director
Name Age Position Class Since
---- --- -------- ----- -----
Robert A. Cohan 48 President, Chief Executive
Officer, Chief Financial I 1998
Officer, Treasurer
and Director
Robert F. Sheldon 81 Director II 1981
R. V. Bailey 72 Vice President, Secretary, III 1980
and III Director
Each of the directors will be up for reelection at the next annual meeting
of stockholders and will continue to serve 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 2005.
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 and he works for Aspen
on a full-time basis. He has approximately 25 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. Mr. Sheldon is currently
retired and only devotes a small portion of his time to Aspen's business.
R. V. Bailey. R. V. Bailey obtained a Bachelor of Science degree in Geology
from the University of Wyoming in 1956. He has approximately 42 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, but currently devotes only a
small portion of his time to Aspen's business.
Meetings of the Board and Committees:
The Board of directors held one formal meeting during the fiscal year ended
June 30, 2004. 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 four times during
fiscal 2003 and six times subsequently through June 30, 2004.
27
No Audit Committee or Code of Ethics
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 because the
board does not believe that, given the small size of Aspen and the limited
transactions, a code of ethics is warranted.
Procedures by which security holders may recommend nominees to the board of
directors; communications with members of the Board of Directors
The board of directors has not adopted procedures by which security holders
may recommend nominees to the board of directors.
Any shareholder desiring to communicate directly with any officer or
director of Aspen may address correspondence to that person at our offices in
Denver, Colorado. Our office staff will forward such communications to the
addressee.
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.
Family Relationships:
As of June 30, 2004, 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 23, 2004, all filing requirements applicable to its officers,
directors and greater-than-ten-percent shareholders were complied with except as
set forth in the following paragraphs.
1. Robert F. Sheldon, a director, filed one Form 4 late. The Form 4 reported a
single transaction.
2. Tri-Power Resources, Inc., beneficial owner of more than 10% of our common
stock, filed its Form 3 reporting one transaction (its acquisition of more than
10% of our common stock) late. Tri-Power Resources has also filed Form 4
reporting the conversion of its debenture into common stock (a report required
by SEC Rule 16a-3(g)(1) even though the transaction is exempt from the
application of Section 16(b)) late.
28
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, 2002, 2003 and
2004. No other person who is currently an executive officer of Aspen earned
salary and bonus compensation exceeding $100,000 during any of those years. This
includes all compensation paid to each by Aspen and any subsidiary.
---------------------------- -------------------------------- --------------------------------------
Annual compensation Long-term Compensation
Awards
------------------------------------------------------------- -------------------------- -----------
Awards Payout
------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- -----------------
(a) (b) (c) (d) (e) (f) (g) (h) (i)
------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- -----------------
Securities
($) Underlying All Other
Name and Fiscal ($) ($) ($) Restricted Options & LTIP Compensation
Principal Position Year Salary Bonus Other (1) Awards SARs (#) Payout (1)
------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- -----------------
R. A. Cohan 2002 123,300 0 34,850 0 0 0 200
President and CEO 2003 127,100 0 35,600 0 0 0 9,700
2004 137,100 0 54,800 0 0 0 7,300
------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- -----------------
R. V. Bailey, 2002 122,900 0 34,850 0 0 0 11,565
Vice President 2003 111,700 0 33,250 0 0 0 23,487
and Chairman 2004 45,000 0 59,100 0 0 0 25,250
------------------- -------- ----------- --------- ---------- ------------ ------------- ----------- -----------------
(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, 2004, 2003 and 2002. Mr.
Bailey's taxable amount was $-0- for fiscal 2004, 2003 and 2002, equal to the
"economic benefit" attributed to the vice president as defined by the Internal
Revenue Code. The Company paid no premiums during fiscal 2004, 2003 and 2002.
We adopted a Profit-Sharing 401(k) Plan which took effect July 1, 1990. All
employees are eligible to participate in this Plan immediately upon being hired
to work at least 1,000 hours per year and attained age 21. Aspen's contribution
(if any) to this plan is determined by the Board of Directors each year. At June
30, 2002, we contributed $-0- to the plan; during fiscal 2003 we contributed
$7,388 to the plan. During fiscal 2004, we contributed $8,550 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 our officers and directors for out-of-pocket
costs and expenses incurred on behalf of Aspen.
29
During fiscal 2004, we assigned to employees royalties, which accumulated
during the fiscal year ended June 30, 2004, 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
------ ----- -------
Anderson Farms 1 1.360000% 2.000000% 0.640000%
Chickohominy 1-12 0.850000% 1.250000% 0.400000%
Emigh 35-6 0.144121% 0.211943% 0.067822%
Ettl 1-10 1.020000% 1.500000% 0.480000%
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, 2004. A director and two officers exercised
options to acquire 50,000 shares each of our common stock during the fiscal year
ended June 30, 2004.
Aggregated Option Exercises in Last Fiscal Year and Fiscal Year End Option Values:
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, 2004.
Number of securities
underlying unexercised Value of unexercised
Shares options/SARs in-the-money options/SARs
acquired on Value at June 30, 2004 at June 30, 2004
Name and Principal Position exercise (#) realized Exercisable/Unexercisable Exercisable/Unexercisable
--------------------------- ------------ -------- ------------------------- -------------------------
R. V. Bailey
Vice President & Chairman... 50,000 $28,500 0 /100,000 $-0-
Robert A. Cohan
President & CEO............. 50,000 $28,500 0 /200,000 $-0-
Robert F. Sheldon
Director.................... 50,000 $28,500 0 /100,000 $-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, 2004.
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 2003 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.
30
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, Certain Relationships and Related Party Transactions.
Report on Repricing of Options/SARs
We did not reprice any options or stock appreciation rights during the
fiscal year ended June 30, 2004, or subsequently.
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
-------------------------------------------------------------------------
The following table sets forth as of September 23, 2004 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 1,319,182i 22.14%
Robert A. Cohan 742,377ii 12.46%
Robert F. Sheldon 259,562iii 4.36%
All Officers and Directors as a Group 2,321,121 38.95%
(3 persons)
31
The address for all of the above
directors and executive officers is:
2050 S. Oneida St., Suite 208,
Denver, CO 80224
Tri-Power Resources, Inc. 900,500iv 13.7%
P.O. Box 849
Ardmore, OK 73402
(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, which includes 50,000 shares of
restricted common stock that were exercised on May 14, 2004; 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.
(ii) This number includes 300,000 shares of common stock granted; stock
options to purchase 250,000 shares of restricted common stock, which includes
50,000 shares of restricted common stock that were exercised on May 14, 2004 and
50,000 shares of restricted common stock that were exercised on August 16, 2004;
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, which includes 50,000
shares of restricted common stock that were exercised on May 14, 2004; and stock
options granted for 80,000 shares of common stock that were exercised on
December 17, 2001.
(iv) This includes warrants to purchase 300,000 shares of our common stock
with an exercise price of $1.10 per share through June 30, 2006 ($1.20 per share
if exercised after June 30, 2005). If the holder exercises the warrant before
March 31, 2005, the holder will receive an additional warrant exercisable to
purchase 300,000 shares at $1.25 per share (also through June 30, 2006), which
is also included in the foregoing calculation.
Except with respect to the employment agreement between Aspen and R. V.
Bailey and between Aspen and Robert Cohan, 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
32
of all costs to acquire, develop and operate these properties. As of June 30,
2004, 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 58 11.11
R. V. Bailey 39 1.04
R. A. Cohan 39 .66
R. K. Davis 46 .87
J. L. Shelton 28 .07
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.
Aspen Power Systems, LLC:
When we operated Aspen Power Systems, LLC, certain affiliates also became
members. This business has not been operating for more than the past two years,
and there are no plans to recommence its operations.
Employment Agreements
See Item 10, Executive Compensation -- Employment contracts and termination
of employment and change in control arrangements, for a discussion of the
current employment contracts between Aspen and Messrs. Cohan and Bailey.
As part of our employment agreement with our former president (Mr. Bailey,
currently vice president), in 1991 we purchased a split dollar life insurance
policy for his benefit. We paid total premiums of $360,000 on his behalf, of
which a portion (the "split") constituted compensation to him. At each
anniversary we paid Mr. Bailey an amount as a bonus to reimburse him for
personal income tax on his split. No additional compensation has been recognized
as reimbursement to him for income taxes for the years ended June 30, 2004 and
2003. We paid no premiums during fiscal 2004 and 2003.
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.
Other Arrangements:
During the fiscal years 2004 and 2003, 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, 2004 and 2003, respectively. Management believes
that the expenditures were to Aspen's benefit. During the years ended June 30,
2004 and 2003, Aspen provided one vehicle each to Aspen's president and vice
president.
We also have entered into a Stock Purchase Agreement, which also expired,
with our vice president, as discussed in "Item 10 - Employee Compensation" and
"Item 11 - Security Ownership."
33
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.
34
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(10)
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, as amended
10.08 Stock Purchase Agreement between Aspen Exploration
Corporation and R.V. Bailey dated January, 1983 (7)
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).
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 $23,000 for the fiscal year ended June 30,
2004 and approximately $21,500 for the fiscal year ended June 30, 2003. 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.
(b) Audit-Related Fees.
Gordon Hughes & Banks LLP billed us aggregate fees in the amount of $18,300
and $16,900 for the fiscal years ended June 30, 2004 and 2003 for assurance and
related services that were reasonably related to the performance of the audit or
review of our financial statements.
35
(c) Tax Fees
Gordon Hughes & Banks LLP billed us aggregate fees in the amount of
approximately $4,750 for the fiscal year ended June 30, 2004 and approximately
$4,600 for the fiscal year ended June 30, 2003, 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, 2004 and 2003 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 ss.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 ss.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
2004 and 2003 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 2004 Fiscal Year 2003
------------------- ---------------- ----------------
Audit fees 67% 70%
------------------- ---------------- ----------------
Audit-related fees 14% 8%
------------------- ---------------- ----------------
Tax fees 19% 22%
------------------- ---------------- ----------------
All other fees 0% 0%
------------------- ---------------- ----------------
36
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 23, 2004
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 23, 2004 Robert A. Cohan /s/ Robert A. Cohan
Principal Executive Officer, ----------------------
Principal Financial Officer
Director
September 23, 2004 R. V. Bailey /s/ R. V. Bailey
Chairman of the Board ----------------------
Director
September 23, 2004 Robert F. Sheldon /s/ Robert F. Sheldon
Director ----------------------
37
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Report of Independent Auditors ............................................40
Financial Statements as of June 30, 2004 and June 30, 2003:
Consolidated Balance Sheets................................................41-42
Consolidated Statements of Operations......................................43
Consolidated Statement of Stockholders' Equity.............................44
Consolidated Statements of Cash Flows......................................45
Notes to Consolidated Financial Statements.................................46-67
39
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, 2004 and 2003 and the related
consolidated statements of operations, stockholders' equity, and cash
flows for the years ended June 30, 2004 and 2003. 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 standards of the Public
Company Accounting Oversight Board (United States). 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, 2004 and
2003, and the results of their consolidated operations and cash flows
for the years ended June 30, 2004 and 2003 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 13, 2004
40
Item 7. Financial Statements and Supplementary Data
------- -------------------------------------------
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
ASSETS
June 30,
2004 2003
----------- -----------
Current Assets:
Cash and cash equivalents, including $1,127,874 and
$516,365 of invested cash in 2004 & 2003, respectively
(Note 1) ................................................ $ 1,329,376 $ 776,566
Precious metals (Note 1) .................................. 18,823 18,823
Accounts & trade receivables .............................. 556,558 269,259
Accounts receivable - related party (Notes 1 and 7) ....... 12,742 6,302
Prepaid expenses .......................................... 16,737 22,181
----------- -----------
Total current assets ...................................... 1,934,236 1,093,131
----------- -----------
Investment in oil & gas properties, at cost (full cost method
of accounting) (Note 9) ................................. 8,216,136 6,723,579
Less accumulated depletion and valuation allowance ...... (3,235,171) (2,674,469)
----------- -----------
4,980,965 4,049,110
----------- -----------
Property and equipment, at cost:
Furniture, fixtures & vehicles ............................ 112,562 112,562
Less accumulated depreciation ........................... ( 81,958) ( 64,178)
----------- -----------
30,604 48,384
----------- -----------
Total assets ................................................ $ 6,945,805 $ 5,190,625
=========== ===========
(Statement Continues)
See Summary of Accounting Policies and Notes
to Consolidated Financial Statements
41
Item 7. Financial Statements and Supplementary Data
------- -------------------------------------------
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS (Continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
June 30,
2004 2003
----------- -----------
Current liabilities:
Accounts payable and accrued expenses ........... $ 932,814 $ 581,895
Accounts payable - related party (Note 7) ....... 70,774 17,685
Advances from joint interest owners ............. 621,015 150,821
Notes payable - current (Note 6), net of discount 410,719 -0-
----------- -----------
Total current liabilities ....................... 2,035,322 750,401
----------- -----------
Asset retirement obligation (Note 15) ........... 79,582 17,841
Deferred income taxes (Note 5) .................. 296,320 131,350
----------- -----------
Total long term liabilities ..................... 375,902 149,191
----------- -----------
Total liabilities ............................. 2,411,224 899,592
----------- -----------
Stockholders' equity:
(Notes 1 and 4):
Common stock, $.005 par value:
Authorized: 50,000,000 shares
Issued and outstanding: At June 30, 2004,
5,958,979 shares and June 30, 2003, 5,863,828
shares ........................................ 29,796 29,320
Capital in excess of par value .................. 6,064,602 6,025,797
Accumulated deficit ............................ (1,556,225) (1,756,900)
Deferred compensation ........................... (3,592) (7,184)
----------- -----------
Total stockholders' equity ...................... 4,534,581 4,291,033
----------- -----------
Total liabilities and stockholders' equity ...... $ 6,945,805 $ 5,190,625
=========== ===========
See Summary of Accounting Policies and Notes
to Consolidated Financial Statements
42
Item 7. Financial Statements and Supplementary Data
------- -------------------------------------------
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
Year ended June 30,
-------------------
2004 2003
----------- -----------
Revenues:
Oil and gas (Note 9) ...................................... $ 1,588,250 $ 1,068,798
Management fees (Note 9) .................................. 232,430 245,023
Interest and other income ................................. 3,256 9,852
----------- -----------
Total revenues .............................................. 1,823,936 1,323,673
----------- -----------
Costs and expenses:
Oil and gas production .................................... 242,472 159,948
Depreciation, depletion and amortization .................. 581,402 428,964
Interest expense .......................................... 6,152 -0-
Selling, general and administrative ....................... 628,265 632,035
----------- -----------
Total costs and expenses .................................... 1,458,291 1,220,947
----------- -----------
Operating income ............................................ 365,645 102,726
Provision for income taxes .................................. (164,970) (42,100)
----------- -----------
Income before cumulative effect of change in accounting
principle .................................................. 200,675 60,626
----------- -----------
Cumulative effect of change in accounting principle, net of
income taxes ............................................... -0- (2,849)
----------- -----------
Net income .................................................. $ 200,675 $ 57,777
=========== ===========
Basic earnings per common share
Income before cumulative effect of change in
accounting principle ...................................... $ .03 $ .01
Cumulative effect of change in accounting principle, net of
income taxes ............................................ -- --
----------- -----------
Net income ................................................ $ .03 $ .01
=========== ===========
Diluted earnings per common share
Income before cumulative effect of change in
accounting principle ...................................... $ .03 $ .01
Cumulative effect of change in accounting principle, net of
income taxes ............................................. -- --
----------- -----------
Net income ................................................ $ .03 $ .01
=========== ===========
Basic weighted average number of common shares
outstanding .............................................. 5,876,081 5,863,828
=========== ===========
Diluted weighted average number of common shares
outstanding .............................................. 6,686,932 6,083,528
=========== ===========
See Summary of Accounting Policies and Notes
to Consolidated Financial Statements
43
Item 7. Financial Statements and Supplementary Data
------- -------------------------------------------
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
Common Stock (par $.005)
----------------------- Accumulated Deferred Total
Shares Par Value APIC Deficit Compensation Equity
----------- ----------- ----------- ----------- ----------- -----------
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
Options exercised by directors
and officers 74,337 $ 372 $ (372) -- -- --
Options exercised by consultant 12,389 62 (62) -- -- --
Options exercised by employee 8,425 42 (42) -- -- --
Amortization of deferred
compensation -- -- -- -- 3,592 3,592
Warrants issued and debt discounted -- -- 39,281 -- -- 39,281
Net income -- -- -- 200,675 -- 200,675
----------------------------------------------------------------------------------
Balance, June 30, 2004 5,958,979 $ 29,796 $ 6,064,602 $(1,556,225) $ (3,592) $4,534,581
==================================================================================
See Summary of Accounting Policies and Notes
to Consolidated Financial Statements
44
Item 7. Financial Statements and Supplementary Data
------- -------------------------------------------
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended June 30,
2004 2003
---- ----
Cash flows from operating activities:
-------------------------------------
Net income ..................................................... $ 200,675 $ 57,777
Adjustments to reconcile net income to net cash
provided by operating activities:
Amortization of deferred compensation ..................... 3,592 6,968
Depreciation, depletion, and amortization ................. 581,402 431,813
Deferred income tax provision ............................. 164,970 42,100
Changes in assets and liabilities:
Decrease (increase) in receivable and prepaid expenses .... (288,295) 100,655
Increase in accounts payable, accrued expenses and advances
from joint owners ....................................... 874,202 261,779
----------- -----------
Net cash provided by operating activities ........................ 1,536,546 901,092
Cash flows from investing activities:
-------------------------------------
Additions to oil and gas properties ............................ (1,026,531) (1,378,356)
Producing oil and gas properties purchased ..................... (421,583) -0-
Sale of oil and gas equipment .................................. 14,378 28,865
Sale of oil and gas properties ................................. -0- 69,869
----------- -----------
Net cash (used) by investing activities .......................... (1,433,736) (1,279,622)
Cash flows from financing activities:
-------------------------------------
Proceeds from split dollar life insurance ...................... -0- 239,095
Proceeds from notes payable .................................... 525,000 -0-
Payment of notes payable ....................................... (75,000) -0-
----------- -----------
Net cash provided by financing activities ........................ 450,000 239,095
----------- -----------
Net increase (decrease) in cash and cash equivalents ............. 552,810 (139,435)
Cash and cash equivalents, beginning of year ..................... 776,566 916,001
----------- -----------
Cash and cash equivalents, end of year ........................... $ 1,329,376 $ 776,566
=========== ===========
Other information:
Interest paid .................................................... $ 6,152 $ -0-
=========== ===========
Income taxes paid ................................................ $ 800 $ -0-
=========== ===========
Non-cash investing and financing activities:
Asset retirement obligation .................................... $ (66,454) $ (16,223)
=========== ============
See Summary of Accounting Policies and Notes
to Consolidated Financial Statements
45
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.
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.
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.
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.
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).
46
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. There were no sales
of gold from inventory for the years ended June 30, 2004 and 2003.
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
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, 2004 and 2003 (Note 9). Depletion and amortization expense
was $560,701 and $410,596 for the years ended June 30, 2004 and 2003,
respectively.
47
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 $17,780 and $18,368
for the years ended June 30, 2004 and 2003, 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, 2004 and 2003, we expensed $3,592 and
$6,968, respectively, in stock bonuses.
Allowance for Bad Debts
-----------------------
We consider accounts receivable to be fully collectible as recorded as
of June 30, 2004 and 2003; 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.
The following is a reconciliation of the numerators and denominators
used in the calculations of basic and diluted earnings per share.
2004 2003
------------------------- ------------------------
Per Per
Net Share Net Share
Income Shares Amount Income Shares Amount
------ ------ ------ ------ ------ ------
Basic earnings per share:
Net income and
share amounts $200,675 5,876,081 $ .03 $57,777 5,863,828 $ .01
Dilutive securities
stock options 484,000 776,000
Convertible debt and
warrants 600,000 --
Repurchased shares (273,149) (556,300)
--------------------------------------------------------------
Diluted earnings per share:
Net income and assumed
share conversion $200,675 6,686,932 $.03 $57,777 6,083,528 $.01
======== ========= ==== ======= ========= =====
48
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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.
Options were granted but not vested to directors and employees
during the fiscal year 2002. An adjustment to net income for
compensation expense to recognize annual vesting would be recorded
under SFAS No. 123, on a pro forma basis, as reflected in the
following table:
49
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2004 2003
------- --------
Net Income (loss): As Reported $200,675 $57,777
Pro Forma 176,414 33,516
Basic Earnings
Per Share: As Reported .03 .01
Pro Forma .03 .01
Diluted Earnings
Per Share: As Reported .03 .01
Pro Forma .03 .01
Reclassification
----------------
Certain 2003 amounts have been reclassified to conform to 2004
presentation.
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 14.95% of their pre-tax earnings (not to
exceed $13,000) to the plan. Under the plan, we may make discretionary
contributions to the plan. We made contributions for fiscal 2004 and
2003 in the amount of $8,550 and $8,722, respectively.
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, 2004
and 2003. The former President's taxable amount was $-0- for fiscal
2004 and 2003, equal to the "economic benefit" attributed to the
former President as defined by the Internal Revenue Code. We paid no
premiums during fiscal 2004 and 2003.
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, 2004 and 2003, we had a policy of
reimbursing employees for medical expenses incurred but not covered by
our paid medical insurance plan. Expenses reimbursed for fiscal 2004
and fiscal 2003 were $8,939 and $19,358, respectively. Under the terms
of a revised employment agreement (see Note 11) 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 revenue from our major customers as
follows:
50
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Company
-------
A B C
----- ----- -----
Year ended:
June 30, 2004 21% 52% 15%
June 30, 2003 26% 51% *
* Less than 10% for fiscal 2003.
Note 4 STOCKHOLDERS' EQUITY
Common Stock
------------
During 2004, we issued a convertible debenture and detachable warrants
to one accredited investor in exchange for the investor's payment to
us of $300,000. Subsequent to year end, the debt was converted to
300,500 share of common stock as consideration for payment of
principal and interest. See Note 6.
The convertible debenture included a potential 600,000 common stock
warrants exercisable as follows:
If the holder exercises the first warrant before June 30, 2005, we
will receive an additional $330,000 ($1.10 per share) and issue
300,000 shares of stock; if the holder exercises the warrant before
June 30, 2006 but after June 30, 2005, we receive an additional
$360,000 ($1.20 per share) instead of $330,000.
If the holder exercises the warrant before March 31, 2005, the holder
will receive an additional warrant exercisable to purchase another
300,000 shares at $1.25 per share.
In any case, the warrant (and any additional warrant) will expire
unless exercised by June 30, 2006.
The warrants were valued using the Black-Scholes valuation method at
$39,281 and have been recorded as a discount to the debt. The discount
will be amortized over the life of the note.
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, and they have expired by their own terms.
During fiscal 2004, two officers, one director, a consultant and an
employee exercised their options for 192,000 shares of our common
stock granted March 14, 2002 at an average price of $0.57 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 and held longer than 6 months. 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
96,849. The effect of the transaction is a net increase to the common
stock par value of $476 and a corresponding decrease to additional
paid in capital of $476.
Total compensation expense in the statement of operations includes
amortization of prior stock awards of $3,592 and $6,968 for the years
ended June 30, 2004 and 2003, respectively.
As of June 30, 2004, we had an aggregate of 484,000 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.
51
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following information summarizes information with respect to
options granted under our equity plans:
Number of Weighted Average Exercise
Shares Price of Shares Under Plans
------ ---------------------------
Outstanding balance June 30, 2002 776,000 $ .58
=======
Granted -0- -
=======
Exercised -0- -
=======
Forfeited or expensed -0- -
------- =======
Outstanding balance June 30, 2003 776,000 .58
=======
Granted -0- -
=======
Exercised (192,000) .57
=======
Forfeited or expensed (100,000) .625
------- =======
Outstanding balance June 30, 2004 484,000 $ .57
======== =======
The following table summarizes information concerning outstanding and
exercisable options as of June 30, 2004:
Outstanding Exercisable
---------------------------- -------------------------
Weighted
Average Weighted Weighted
Remaining Average Average
Exercise Number Contractual Exercisable Number Exercise
Price Outstanding Life In Years Price Exercisable Price
-------- ----------- ------------- ----------- ----------- --------
$.57 284,000 08/15/2005(1) $.57 -0- $.57
.57 200,000 08/15/2007(1) .57 -0- .57
-------
484,000
=======
(1) The term of the option will be the earlier of the contractual life
of the options or 90 days after the date the optionee is no longer an
employee, consultant or director of the Company.
We account for the two stock option plans using APB No. 25 for
directors and employees and SFAS No. 123 for consultants. There were
676,000 options granted in 2002. Directors and employees were granted
601,000 and consultants were granted 75,000. The consultant options
were valued using the fair value method of SFAS No. 123 as calculated
by the Black-Scholes option-pricing model. The fair value of each
option grant, as opposed to its exercisable price, is estimated on the
date of grant using the Black-Scholes option-pricing model with the
following weighted average assumptions: no dividend yield, expected
volatility of 14.9%, 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.
52
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 5 INCOME TAXES
We recorded a deferred income tax liability of $296,320 and $131,350
as of June 30, 2004 and 2003, respectively. We paid $800 in California
state income taxes in fiscal 2004. During 2004, we used approximately
$189,000 in net operating loss carryforwards leaving approximately
$1,684,000 in available federal net operating loss carryforwards as of
June 30, 2004. During 2003, we added approximately $159,000 in net
operating loss carryforwards for a total of approximately $1,873,000.
At June 30, 2004 and 2003, no net operating loss carryforwards
expired.
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. Primarily, our proved oil and gas reserves substantially
exceed our expected future costs and hence, we believe it more likely
than not that the benefit will be realized.
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:
2004 2003
---------- -----------
Deferred tax assets:
Federal tax loss
carryforwards $ 669,929 $ 699,646
Asset retirement
obligations 4,727 --
--------- ---------
674,656 699,646
--------- ---------
Deferred tax (liabilities):
Property, plant and
equipment (2,684) (3,324)
Oil and gas properties (968,292) (827,672)
--------- ---------
(970,976) (830,996)
---------- ---------
$ (296,320) $(131,350)
========== =========
53
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:
2004 2003
--------- ---------
Statutory federal income
tax rate 34% 34%
Statutory state income tax
rate, net of federal benefit 9% 9%
Other 2% (2%)
--------- ---------
Effective rate 45% 41%
========= =========
The provision for income taxes consists of the following components:
2004 2003
--------- ---------
Current tax expense (refund),
state $ -0- $ -0-
Deferred tax expense 164,970 42,100
--------- ---------
Total income tax
provision $ 164,970 $ 42,100
========= =========
We have available federal net operating loss carryforwards of
approximately $1,684,000 (net operating losses expire beginning June
30, 2011 through the year ending June 30, 2023).
54
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6 NOTES PAYABLE
The Company incurred the following debt:
June 30, June 30,
2004 2003
-------------------------
Note payable to a bank $ 150,000 $ -0-
Convertible debenture issued to a
privately held corporation 300,000 -0-
---------- ----------
450,000 -0-
---------- ----------
Less discount (39,281) -0-
---------- ----------
$ 410,719 $ -0-
========== ==========
Proceeds from the note payable to a bank was used for the acquisition
of producing gas properties located in several counties in the
Sacramento Valley, California. The note matures in June 2005,
principal payments are $12,500 per month plus interest at the bank's
prime rate plus 2%. The rate was 6.5% at June 30, 2004. The loan is
collateralized by accounts receivable, other rights to payments and
all inventory.
On June 28, 2004, a privately-held Oklahoma corporation purchased a
$300,000 convertible debenture from Aspen Exploration Corporation. We
also issued warrants to purchase 300,000 shares of our common stock
which, if exercised before March 31, 2005, will result in the
purchaser acquiring warrants to purchase an additional 300,000 shares.
The transaction was completed effective June 28, 2004. We issued the
convertible debenture to the accredited investor in exchange for the
investor's payment to us of $300,000. The convertible debenture with a
principal amount of $300,000, bears interest at 4% per annum and
300,000 common stock warrants. See Note 4. Another 300,000 shares are
potentially issuable under certain circumstances.
On July 15, 2004 the debenture was automatically converted into shares
of our restricted common stock after our shares traded at prices
greater than $1.00 per share for ten trading days. We issued 300,500
shares of our restricted common stock in satisfaction of the principal
and interest due the investor.
As of June 30, 2004 and 2003, the weighted average interest rate on
the above outstanding borrowings is 4.85% and $-0-, respectively.
Note 7 SEGMENT INFORMATION
We operate in one industry segment within the United States: oil and
gas exploration.
Identified assets by industry are those assets that are used in our
operations in each industry. Corporate assets are principally cash,
furniture, fixtures and vehicles.
We have adopted SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information". 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.
55
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
During the years ended June 30, 2004 and 2003, there were no
intersegment revenues. The accounting policies applied by each segment
are the same as those used by us in general.
Net sales in the oil and gas segment to three customers were
approximately $831,000 and $332,000 and $232,000, or 52%, 21% and 15%,
respectively, for fiscal 2004. Net sales to two customers were
approximately $544,000 and $277,000, or 51% and 26%, respectively, for
fiscal 2003.
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 $1,448,000 for the development and
acquisition of oil and gas properties in fiscal 2004 and approximately
$1,378,000 for the development of oil and gas properties in fiscal
2003.
56
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Segment information consists of the following:
Oil and Gas Corporate Consolidated
----------- --------- ------------
Revenues:
2004 $1,820,680 $ 3,256 $1,823,936
2003 1,313,821 9,852 1,323,673
Income (loss) from
operations:
2004 $1,008,434 $ (642,789) $ 365,645
2003 743,277 (640,551) 102,726
Identifiable assets:
2004 $5,550,265 $1,395,540 $6,945,805
2003 4,324,671 865,954 5,190,625
Income tax expense:
2004 $ 164,970 $ -0- $ 164,970
2003 42,100 -0- 42,100
Depreciation, depletion and valuation charged to identifiable assets:
2004 $ 563,622 $ 17,780 $ 581,402
2003 410,596 18,368 428,964
Capital expenditures:
2004 $ 1,448,114 $ -0- $1,448,114
2003 1,378,356 -0- 1,378,356
Note 8 RELATED PARTY TRANSACTIONS
During the years ended June 30, 2004 and 2003, 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, 2004 and 2003. 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 $-0- and $6,970 for each of the fiscal years ended June 30, 2004
and 2003, respectively. 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.
57
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 2004, we assigned the following overrides at no cost to
employees:
R. V. R. A. J. L.
Bailey Cohan Shelton
------ ----- -------
Anderson Farms 1 1.360000% 2.000000% 0.640000%
Chickohominy 1-12 0.850000% 1.250000% 0.400000%
Emigh 35-6 0.144121% 0.211943% 0.067822%
Ettl 1-10 1.020000% 1.500000% 0.480000%
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 $166,005 and $77,325, respectively, for the year
ended June 30, 2004, and $82,013 and $77,752, respectively, for the
year ended June 30, 2003. Mr. Bailey and Mr. Cohan also received
royalty interest payments totaling $55,840 and $51,022, respectively,
for the year ended June 30, 2004, and $31,919 and $31,919,
respectively, for the year ended June 30, 2003. As of June 30, 2004,
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 58 11.11
R. V. Bailey 39 1.04
R. A. Cohan 39 .66
R. K. Davis 46 .87
J. L. Shelton 28 .07
We have received advances from Messrs. Bailey, Cohan and Davis for
working interests in uncompleted wells of $27,410, $18,269 and
$16,573, respectively, as of June 30, 2004 and $5,895, $5,895 and
$5,895 as of June 30, 2003, respectively. Additionally, we owed Mr.
Bailey and Mr. Cohan $6,062 and $2,460 for reimbursement of expenses
made on our behalf as of June 30, 2004 and we owe Mr. Bailey $928 for
reimbursed expenses on our behalf in 2003. Messrs. Bailey, Cohan and
Davis owed us $8,252, $1,694 and $2,796, respectively, as of June 30,
2004 and $3,474, $1,944 and $987, respectively, as of June 30, 2003
for their portion of well operating expenses.
See Note 11 for additional related party disclosure.
Note 9 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, 2004 we have approximately $2,117,352 in excess
of the Federal Deposit Insurance Corporation $100,000 limit at one
58
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 distributed
across unrelated businesses and individuals, with the exception of two
major gas purchasers and one investor in our wells, who normally
settle within 25 days of the previous month's gas purchases. 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 10 OIL AND GAS ACTIVITIES
Capitalized costs
-----------------
Capitalized costs associated with oil and gas producing activities are
as follows:
June 30,
2004 2003
---------- ----------
Proved properties $8,216,136 $6,723,579
---------- ----------
Accumulated depreciation,
depletion and
amortization (2,953,452) (2,392,750)
Valuation allowance (281,719) (281,719)
---------- ----------
(3,235,171) (2,674,469)
---------- ----------
Net capitalized costs $4,980,965 $4,049,110
========== ==========
59
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,
-------------------
2004 2003
------- --------
Revenues* $1,820,680 $1,313,821
Production costs (242,472) (159,948)
Depreciation, depletion
and accretion (563,622) (412,214)
Interest expense (6,152) -0-
---------- ----------
Results of operations
(excluding corporate overhead) $1,008,434 $ 741,659
========== ==========
*Includes oil and gas related fees and management fees.
Fees charged by us to operate the properties totaled approximately
$19,370 per month in 2004 and $20,420 per month in 2003.
Unaudited oil and gas reserve quantities
----------------------------------------
The following unaudited reserve estimates presented as of June 30,
2004 and 2003 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.
60
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 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
Revisions of previous estimates ( 1) (411)
Discoveries - 527
Purchased - 243
Production - (305)
----- -----
Estimated quantity, June 30, 2004 2 2,534
===== =====
Developed
Proved reserves Developed Non-Producing Total
--------- ------------- -----
at year end (In Thousands)
---------------
Oil (Bbls)
June 30, 2004 - 2 2
June 30, 2003 - 3 3
Gas (MCF)
June 30, 2004 1,236 1,298 2,534
June 30, 2003 655 1,825 2,480
61
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,
--------
2004 2003
---- ----
(in thousands)
Future cash inflows $ 14,800 $ 12,967
Future production and development costs (1,568) (1,281)
Future income tax expense (4,679) (4,027)
-------- --------
Future net cash flows 8,553 7,659
10% annual discount for estimated timing
of cash flows (2,609) (2,826)
-------- --------
Standardized measure of discounted future
net cash flows $ 5,944 $ 4,833
======== ========
62
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,
--------------------
2004 2003
---- ----
(in thousands)
Standardized measure of discounted
future net cash flows, beginning of year $ 4,833 $ 2,603
-------- --------
Sales and transfers of oil and gas produced,
net of production costs (1,346) (909)
Net changes in prices and production costs
and other 638 5,153
Net change due to discoveries 1,544 981
Acquisition of reserves 711 451
Revisions of previous quantity estimates (15) 481
Development costs incurred 60 18
Accretion of discount 721 376
Sale of existing reserves - (74)
Net change in income taxes (755) (1,156)
Other (447) (3,091)
-------- --------
1,111 2,230
-------- --------
Standardized measure of discounted future
cash flows, end of year $ 5,944 $ 4,833
======== ========
Net changes in prices and production costs of $651 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 2004 than in 2003. The revision of
previous estimates of $15 was the result of assigning approximately
1,062 fewer barrels of recoverable oil and reducing recoverable
reserves of gas by approximately 411,000 MCF, while the volumes were
reduced, the price applied to the remaining recoverable reserves
increased substantially, resulting in a modest decrease. All
adjustments were based on performance reviews of individual wells. A
successful drilling program and the acquisition of proven reserves
from third parties added $1,544 and $711, or $2.25 million to our
future net cash flow. These additions represent approximately 770,000
MCF of recoverable reserves.
63
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 11 COMMITMENTS AND CONTINGENCIES
Drilling Completion & Acquisition
Area Wells Costs Equipping Costs Costs Total
------------------------------- ---------- ----------- ------------------- -------------- -----------
Momentum Farmout 2 $61,000 $191,000 $252,000
Various Counties, CA
West Grimes Field 2 189,000 147,000 336,000
Colusa County, CA
Sour Grass Prospect 1 72,000 60,000 132,000
Tehama County, CA
Lambie 3-4 1 82,500 82,500
Verona Pipeline - 70,000 70,000
---------- ----------- ------------------- -------------- -----------
Total Expenditure 6 $322,000 $468,000 $82,500 $872,500
========== =========== =================== ============== ===========
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 2003
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
64
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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.
Gas sales contract
Effective June 1, 2004, we entered a contract to sell 750 MMBTU of gas
per day at a fixed price of $6.34 less transportation and other
expenses. The contract is for the term June 1 - August 31, 2004 and
contains monetary penalties for non-delivery of the gas. Subsequent to
year-end, we completed the contract with no penalties realized.
Note 12 INTERIM FINANCIAL DATA
The year-end adjustment that is material to the results of the fourth
quarter ending June 30, 2004 and June 30, 2003 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 increase depletion expense for the fiscal year 2004
from an estimated $496,000 based on prior years' reserve studies to an
actual depletion expense of approximately $564,000, an increase of
$68,000 or 13.7% for fiscal 2004 and approximately $464,000 to
approximately $411,000, a decrease of $53,000, or 11.4% for fiscal
2003.
65
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 13 CONTRACTUAL OBLIGATIONS
We had six contractual obligations as of June 30, 2004. The following
table lists our significant liabilities at June 30, 2004:
Payments Due By Period
------------------------------------------------------------------------------------------
Less than After
Contractual Obligations 1 year 2-3 years 4-5 years 5 years Total
---------------------------------- --------------- -------------- -------------- --------------- ---------------
Employment Obligations $210,400 $240,800 $147,400 -0- $598,600
Bank Loans 150,000 260,719 -0- -0- 410,719
Operating Leases 16,686 6,160 -0- -0- 22,846
--------------- -------------- -------------- --------------- ---------------
Total contractual
cash obligations $377,086 $507,679 $147,400 $-0- $1,032,165
=============== ============== ============== =============== ===============
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 to
December 31, 2004 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, 2004 and 2003 were $24,370 and
$28,536, respectively.
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
66
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2004 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
----------
Liabilities incurred 66,454
Liabilities settled (7,634)
Accretion expense 2,921
Revision to estimate -0-
----------
Asset retirement obligation as of
June 30, 2004 $ 79,582
==========
Note 15 SUBSEQUENT EVENTS (Unaudited)
On August 16, 2004, one officer/director, a consultant and an employee
exercised their options for 92,000 shares of our common stock granted
March 14, 2002 at an average price of $0.57 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 moving average bid price immediately prior to the
exercise date. Total shares surrendered were 42,359. The effect of the
transaction is a net increase to the common stock par value of $248
and a corresponding decrease to additional paid in capital of $248.
67