FORM 10-Q-SB
SECURITIES AND EXCHANGE COMMISSION
Washington D.C. 20549
MARK ONE
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2005
--------------
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ________ to ________
Commission File Number 0-9494
ASPEN EXPLORATION CORPORATION
-----------------------------------------------
(Exact Name of Aspen as Specified in its Charter)
Delaware 84-0811316
-------- ----------
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
Suite 208, 2050 S. Oneida St.,
Denver, Colorado 80224-2426
---------------- ----------
(Address of Principal Executive Offices) (Zip Code)
Issuer's telephone number: (303) 639-9860
Indicate by check mark whether Aspen (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that Aspen was required to file
such reports), and (2) has been subject to such filing requirements for the past
90 days.
Yes [ X ] No [ ]
Indicate the number of shares outstanding of each of the Issuer's classes of
common stock as of the latest practicable date.
Class Outstanding at May 10, 2005
Common stock, $.005 par value 6,719,308
Transitional small business disclosure format: Yes XX No
------- -------
Part One. FINANCIAL INFORMATION
Item 1. Financial Statements
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, June 30,
2005 2004
---- ----
Current Assets:
Cash and cash equivalents, including $905,620 and
$1,127,874 of invested cash at
March 31, 2005 and June 30, 2004 respectively ................... $ 1,109,628 $ 1,329,376
Precious metals ................................................. 18,823 18,823
Accounts receivables ............................................ 635,711 556,558
Receivable, related party ....................................... 20,705 12,742
Prepaid expenses ................................................ 17,333 16,737
----------- -----------
Total current assets ....................................... 1,802,200 1,934,236
----------- -----------
Investment in oil and gas properties, at cost (full cost
method of accounting) ........................................... 9,461,604 8,216,136
Less accumulated depletion and valuation allowance .............. (3,691,622) (3,235,171)
----------- -----------
5,769,982 4,980,965
----------- -----------
Property and equipment, at cost:
Furniture, fixtures and vehicles ................................ 145,593 112,562
Less accumulated depreciation ................................... (95,403) (81,958)
----------- -----------
50,190 30,604
----------- -----------
TOTAL ASSETS ............................................... $ 7,622,372 $ 6,945,805
=========== ===========
(Statement Continues)
See notes to Consolidated Financial Statements
2
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
March 31, June 30,
2005 2004
---- ----
Current liabilities:
Accounts payable and accrued expenses ........................... $ 172,659 $ 932,814
Accounts payable - related party (Note 2) ....................... 5,602 70,774
Advances from joint interest owners ............................. 35,051 621,015
Notes payable - current (Note 6), net of discount ............... 37,500 410,719
----------- -----------
Total current liabilities ....................................... 250,812 2,035,322
----------- -----------
Asset retirement obligation (Note 3) ............................ 87,582 79,582
Deferred income taxes (Note 9) .................................. 733,430 296,320
----------- -----------
Total long term liabilities ..................................... 821,012 375,902
----------- -----------
Total liabilities ............................................... 1,071,824 2,411,224
----------- -----------
Stockholders' equity:
(Notes 1 and 5):
Common stock, $.005 par value:
Authorized: 50,000,000 shares
Issued and outstanding: At March 31, 2005,
6,719,308 shares and June 30, 2004, 5,958,979 ............... 33,597 29,796
Capital in excess of par value .................................. 6,687,019 6,064,602
Accumulated deficit ............................................. (170,068) (1,556,225)
Deferred compensation and consulting fees ....................... -0- (3,592)
----------- -----------
Total stockholders' equity ...................................... 6,550,548 4,534,581
----------- -----------
Total liabilities and stockholders' equity ...................... $ 7,622,372 $ 6,945,805
=========== ===========
See Notes to Consolidated Financial Statements
3
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended Nine Months Ended
March 31, March 31,
--------- ---------
2005 2004 2005 2004
---- ---- ---- ----
Revenues:
Oil and gas ............................................. $ 1,103,687 $ 401,941 $ 2,933,599 $ 1,106,809
Management fees ......................................... 59,616 38,613 201,441 150,634
Interest and other, net ................................. 443 (427) 3,338 4,338
----------- ----------- ----------- -----------
Total Revenues ............................................ 1,163,746 440,127 3,138,378 1,261,781
----------- ----------- ----------- -----------
Costs and expenses:
Oil and gas production .................................. 107,035 85,912 270,891 188,301
Depreciation, depletion and amortization ................ 159,895 127,575 469,896 385,524
General and administrative .............................. 192,025 146,800 568,493 464,026
Interest expense ........................................ 1,053 3,078 5,831 3,949
----------- ----------- ----------- -----------
Total Costs and Expenses .................................. 460,008 363,365 1,315,111 1,041,800
----------- ----------- ----------- -----------
Income before taxes ....................................... 703,738 76,762 1,823,267 219,981
----------- ----------- ----------- -----------
Provision for income taxes ................................ 1,273 -0- 437,110 -0-
----------- ----------- ----------- -----------
Net income ................................................ $ 702,465 $ 76,762 $ 1,386,157 $ 219,981
=========== =========== =========== ===========
Basic income per common share ............................. $ .11 $ .01 $ .22 $ .04
=========== =========== =========== ===========
Diluted income per common share ........................... $ .11 $ .01 $ .21 $ .04
=========== =========== =========== ===========
Basic weighted average number of common shares
outstanding ............................................... 6,406,510 5,863,828 6,406,510 5,863,828
=========== =========== =========== ===========
Diluted weighted average number of common shares
outstanding ............................................... 6,640,818 5,951,553 6,640,818 5,951,553
=========== =========== =========== ===========
The accompanying notes are an integral
part of these statements.
4
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine months ended March 31,
2005 2004
------------------------------------
Cash flows from operating activities:
-------------------------------------
Net income ...................................................... $ 1,386,157 $ 219,981
Adjustments to reconcile net income to net cash
provided (used) by operating activities:
Depreciation, depletion and amortization ...................... 469,896 385,524
Stock issued for interest expense and consulting fees ......... 39,091 -0-
Deferred income tax provision ................................. 437,110 -0-
Changes in assets and liabilities:
Increase in receivable ........................................ (87,116) (38,445)
Decrease (increase) in prepaid expenses ....................... (596) 12,656
Decrease in accounts payable and accrued expense .............. (1,411,291) (111,494)
----------- -----------
Net cash provided by operating activities ..................... 833,251 468,222
----------- -----------
Cash flows from investing activities:
-------------------------------------
Proceeds - sale of oil and gas properties ..................... -0- 134,750
Additions to oil and gas properties ........................... (1,229,772) (1,033,040)
Purchase of producing properties .............................. (19,248) -0-
Purchase of furniture, fixtures & equipment inventory ......... (21,479) -0-
----------- -----------
Net cash (used) by investing activities ....................... (1,270,499) (898,290)
----------- -----------
Cash flow from financing activities:
------------------------------------
Proceeds from issuance of common stock ........................ 330,000 -0-
Payment of notes payable ...................................... (112,500) (37,500)
Proceeds of notes payable ..................................... -0- 225,000
----------- -----------
217,500 187,500
----------- -----------
Net decrease in cash and cash equivalents ..................... (219,748) (242,568)
Cash and cash equivalents, beginning of year .................. 1,329,376 776,566
----------- -----------
Cash and cash equivalents, end of year ........................ $ 1,109,628 $ 533,998
=========== ===========
Other information:
Interest paid ................................................. $ 5,831 $ 3,949
=========== ===========
Non-cash investing activities
Asset retirement obligation additions ......................... $ 8,000 $ 28,491
=========== ===========
The accompanying notes are an integral
part of these statements.
5
ASPEN EXPLORATION CORPORATION
Notes to Condensed Consolidated Financial Statements
(Unaudited)
March 31, 2005
Note 1 BASIS OF PRESENTATION
The accompanying financial statements are unaudited. However, in our
opinion, the accompanying financial statements reflect all adjustments,
consisting of only normal recurring adjustments, necessary for fair
presentation. Interim results of operations are not necessarily indicative
of results for subsequent interim periods or the remainder of the year.
These financial statements should be read in conjunction with our Annual
Report on Form 10-KSB for the year ended June 30, 2004.
Except for the historical information contained in this Form 10-QSB, this
Form contains forward-looking statements that involve risks and
uncertainties. Our actual results could differ materially from those
discussed in this Report. Factors that could cause or contribute to such
differences include, but are not limited to, those discussed in this Report
and any documents incorporated herein by reference, as well as the Annual
Report on Form 10-KSB for the year ended June 30, 2004.
Note 2 RECEIVABLE - RELATED PARTIES, PAYABLE - RELATED PARTIES
The receivable from related parties constitutes amounts due from officers
and consultants for joint operating costs of wells operated by us. The
transactions are in the normal course of business with the same terms as
other joint owners and are repaid in a normal business cycle. The payable
from related parties represents unexpended prepayments made by officers and
consultants on wells operated by us as well as unpaid business expenses due
officers. These transactions are in the normal course of business.
Note 3 ASSET RETIREMENT OBLIGATION
We have adopted the provisions of Statement of Financial Accounting
Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations."
SFAS No. 143 generally applies to legal obligations associated with the
retirement of long-lived assets that result from the acquisition,
construction, development and/or the normal operation of a long-lived
asset. SFAS No. 143 requires us to recognize an estimated liability for the
plugging and abandonment of our gas wells. We have recognized the future
cost to plug and abandon the gas wells over the estimated useful lives of
the wells in accordance with SFAS No. 143. A liability for the fair value
of an asset retirement obligation with a corresponding increase in the
carrying value of the related long-lived asset is recorded at the time a
producing well is purchased or a drilled well is completed and ready for
production. We will amortize the amount added to the oil and gas properties
and recognize accretion expense in connection with the discounted liability
over the remaining life of the respective well. The estimated liability is
based on historical experience in plugging and abandoning wells, estimated
useful lives based on engineering studies, external estimates as to the
6
Note 3 ASSET RETIREMENT OBLIGATION (CONTINUED)
cost to plug and abandon wells in the future and federal and state
regulatory requirements. The liability is a discounted liability using a
credit adjusted risk-free rate of 6%. Revisions to the liability could
occur due to changes in plugging and abandonment costs, useful well lives
or if federal or state regulators enact new regulations on the plugging and
abandonment of wells.
A reconciliation of our liability for the nine months ended March 31, 2005
is as follows:
Asset retirement obligations as of
June 30, 2004 $79,582
ARO additions 8,000
Liabilities settled -0-
Accretion expense -0- *
Revision of estimate -0-
-------
Asset retirement obligation as of
March 31, 2005 $87,582
=======
* - Accretion not material
Note 4 EARNINGS PER SHARE
We follow 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.
Nine Months Ended
March 31, 2005 March 31, 2004
---------------------------------------------- -----------------------------------------
Per Per
Net Share Net Share
Income Shares Amount Income Shares Amount
------------ ----------- ----------- ----------- ----------- ---------
Basic earnings per share:
Net income and share amounts $ 1,386,157 6,406,510 $ .22 $ 219,981 5,863,828 $ .04
Dilutive securities:
stock options 292,000 676,000
Repurchased shares (57,692) (588,275)
----------- ----------- ---------- ----------- ----------- -------
Diluted earnings per share:
Net income and assumed share
conversion $ 1,386,157 6,640,818 $ .21 $ 219,981 5,951,553 $ .04
=========== =========== ========== =========== =========== =======
7
Note 5 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. On July 15, 2004, the debt and accrued interest were
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. The debt net
of unamortized discount related to warrants was recorded to equity upon
conversion. See Note 6.
The convertible debenture included warrants for up to 600,000 shares of
common stock exercisable as follows:
There are two warrants, each for 300,000 shares of common stock. The holder
exercised the initial warrant on March 11, 2005 and we received $330,000
($1.10 per share) and issued 300,000 shares of stock. Because the holder
exercised the first warrant before March 31, 2005, we issued an additional
warrant to purchase another 300,000 shares at $1.25 per share on March 11,
2005. The additional warrant will expire unless exercised by June 30, 2006.
The initial warrants were valued using the Black-Scholes valuation method
at $39,281 and have been recorded as a discount to the debt.
On October 12, 2004 we entered into a six month investor relations
consulting agreement with CEOcast, Inc. which provides for a monthly
consulting fee and issuance of 28,000 shares of our restricted common
stock. We valued the stock at $1.25 per share, or $35,000, and amortized
that amount over the six month consulting engagement.
Stock Options
-------------
On August 15, 2004, one officer, a consultant and an employee exercised
options for 92,000 shares of our common stock granted March 14, 2002 at an
average exercise price of $0.57 per share. As consideration for the options
purchased, the individuals surrendered common stock with a fair value equal
to the exercise price of the option shares and held longer than six 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
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.
On March 19, 2005, one officer and one director exercised options for
100,000 shares of our common stock granted March 14, 2002 at an average
exercise price of $0.57 per share. As consideration for the options
purchased, the individuals surrendered common stock with a fair value equal
to the exercise price of the option shares and held longer than six 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
17,812. The effect of the transaction is a net increase to the common stock
par value of $411 and a corresponding decrease to additional paid in
capital of $411.
8
Note 5 STOCKHOLDERS' EQUITY (CONTINUED)
As of March 31, 2005, we had an aggregate of 292,000 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.
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, 2004 484,000 $ .57
=======
Granted -0- --
=======
Exercised (192,000) .57
=======
Forfeited or expensed -0- --
=======
--------
Outstanding balance March 31, 2005 292,000 $ .57
======== =======
The following table summarizes information concerning outstanding and
exercisable options as of March 31, 2005:
Outstanding Exercisable
----------------------------------- --------------------------
Weighted
Average Weighted Weighted
Remaining Average Average
Exercise Number Contractual Exercisable Number Exercise
Price Outstanding Life In Years Price Exercisable Price
-------- ----------- ------------- ----------- ----------- ---------
$.57 142,000 08/15/2005(1) $.57 142,000 $.57
.57 150,000 08/15/2007(1) .57 150,000 .57
-------
292,000
=======
(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.
9
Note 5 STOCKHOLDERS' EQUITY (CONTINUED)
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 options and
consultants were granted 75,000 options. The consultant options were valued
using the fair value method of SFAS No. 123 as calculated by the
Black-Scholes option-pricing model. The fair value of each option grant, as
opposed to its exercisable price, is estimated on the date of grant using
the Black-Scholes option-pricing model with the following weighted average
assumptions: no dividend yield, expected volatility of 14.9%, credit
adjusted risk free interest rates of 8.5% and expected lives of 3.4 to 4.4
years. The resulting compensation expense relating to the consultant option
grant was included as an operating expense as the options vested.
Note 6 NOTES PAYABLE
The Company incurred the following debt:
March 31, June 30,
2005 2004
-------------------------
Note payable to a bank $ 37,500 $ 150,000
Convertible debenture issued to a
privately held corporation -0- 300,000
--------- ---------
37,500 450,000
--------- ---------
Less discount -- (39,281)
--------- ---------
$ 37,500 $ 410,719
========= =========
Proceeds from the note payable to a bank were 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 7.75% at March 31, 2005. The loan is collateralized by accounts
receivable, other rights to payments and all inventory.
On 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, paid interest at
4% per annum and included warrants convertible into 300,000 shares of
common stock. 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. See Note 5.
10
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 that industry. Corporate assets are principally cash,
furniture, fixtures and vehicles.
We have adopted SFAS No. 131, "Disclosures about Segments of an Enterprise
and Related Information." SFAS No. 131 requires the presentation of
descriptive information about reportable segments which is consistent with
that made available to the management of the Company to assess performance.
Our oil and gas segment derives its revenues from the sale of oil and gas
and prospect generation and administrative overhead fees charged to
participants in our oil and gas ventures. Corporate income is primarily
derived from interest income on funds held in money market accounts.
During the nine months ended March 31, 2005 and 2004, there were no
intersegment revenues. The accounting policies applied by each segment are
the same as those used by us in general.
There have been no differences from the last annual report in the basis of
measuring segment profit or loss. There have been no material changes in
the amount of assets for any operating segment since the last annual report
except for the oil and gas segment which capitalized approximately
$1,263,139 for the development and acquisition of oil and gas properties
and $7,360 in the corporate segment for the purchase of office equipment
and computers.
Segment information consists of the following for the nine months ended
March 31:
Oil and Gas Corporate Consolidated
----------- --------- ------------
Revenues:
2005 $ 3,135,040 $ 3,338 $3,138,378
2004 1,257,443 4,338 1,261,781
Income (loss) from operations:
2005 $ 2,407,699 $ (584,432) $1,823,267
2004 693,444 (473,463) 219,981
Identifiable assets:
2005 $ 6,188,211 $ 1,434,161 $7,622,372
2004 4,723,147 790,705 5,513,852
Depreciation, depletion and valuation charged to identifiable assets:
2005 $(456,450) $ (13,446) $ (469,896)
2004 (371,749) (13,775) (385,524)
Capital expenditures:
2005 $ 1,263,139 $ 7,360 $1,270,499
2004 1,033,040 -0- 1,033,040
11
Note 7 SEGMENT INFORMATION (CONTINUED)
Segment information consists of the following for the three months ended
March 31:
Oil and Gas Corporate Consolidated
----------- --------- ------------
Revenues:
2005 $ 1,163,303 $ 443 $1,163,746
2004 440,554 (427) 440,127
Income (loss) from operations:
2005 $ 900,855 $ (197,117) $ 703,738
2004 231,659 (154,897) 76,762
Note 8 MAJOR CUSTOMERS
We derived in excess of 10% of our revenue from various sources (oil and
gas sales) as follows:
The Company
-----------
A B C
- - -
Quarter ended:
March 31, 2005 36% 51% *
March 31, 2004 23% 51% 14%
* Less than 10% in 2005.
Note 9 INCOME TAXES
We have recorded net deferred income tax liability of $733,430 as of March
31, 2005. During the nine months ended March 31, 2005, we used
approximately $1,229,100 in net operating loss carryforwards leaving
approximately $774,700 in available federal net operating loss
carryforwards as of March 31, 2005 (net operating losses expire beginning
June 30, 2011 through the year ending June 30, 2023). For the three months
ended March 31, 2005, we have recorded no income tax provision for federal
or state income taxes due to the application of net operating loss
carryforwards. We have recorded a deferred tax provision of $1,273. The
deferred tax provision is nominal due to minimal additions to the oil and
gas assets during the quarter resulting in minimal increase in net deferred
tax liability.
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.
12
Note 9 INCOME TAXES (CONTINUED)
At March 31, 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:
2005
----
Deferred tax assets:
Federal tax loss carryforwards $ 294,700
Asset retirement obligation 35,191
-----------
329,891
-----------
Deferred tax (liabilities):
Property, plant and equipment (1,362)
Oil and gas properties (1,061,959)
-----------
(1,063,321)
-----------
$ (733,430)
===========
A reconciliation between the statutory federal income tax rate (34%) and
the effective rate of income tax expense for the nine months ended March 31
is as follows:
2005 2004
---------- -----------
Statutory federal income tax rate 34% 34%
Statutory state income tax
rate, net of federal benefit 9% 9%
Other (4)% -0-
Net operating loss (39)% (43)%
Change in deferred tax liability 23% -0-
----- -----
Effective rate 23% -0-%
===== =====
The provision for income taxes consists of the following components:
2005 2004
---------- ----------
Current tax expense, state $ -0- $ -0-
Deferred tax expense 437,110 -0-
---------- ----------
Total income tax provision $ 437,110 $ -0-
========== ==========
13
Note 10 DRILLING COMMITMENTS AND CONTINGENCIES
We have a proposed drilling budget for the period March through December
2005. The budget includes drilling ten wells in the Sacramento gas province
of northern California, although the actual number of wells drilled will be
based on permit, pipeline, and rig availability considerations. Our share
of the estimated costs to complete this program is set forth in the
following table:
Drilling Completion &
Area Wells Costs Equipping Costs Total
----------------------- ------------ ------------ ------------------ ----------
West Grimes Field 4 $415,000 $312,000 $727,000
Colusa County, CA
Malton Black Butte 2 115,000 122,000 237,000
Field,
Tehama County, CA
Colusa County, CA 3 256,000 292,000 548,000
Yolo County, CA 1 17,500 43,000 60,500
----------------------- ------------ ------------ ------------------ ----------
Total Expenditure 10 $803,500 $769,000 $1,572,500
============ ============ ================== ===========
NOTE 11 NEW ACCOUNTING PRONOUNCEMENTS
FASB 151 - Inventory Costs
In November 2004, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 151, which revised ARB No.43, relating to inventory costs. This
revision is to clarify the accounting for abnormal amounts of idle facility
expense, freight, handling costs and wasted material (spoilage). This
Statement requires that these items be recognized as a current period
charge regardless of whether they meet the criterion specified in ARB 43.
In addition, this Statement requires the allocation of fixed production
overheads to the costs of conversion be based on normal capacity of the
production facilities. This Statement is effective for financial statements
for fiscal years beginning after June 15, 2005. Earlier application is
permitted for inventory costs incurred during fiscal years beginning after
the date of this Statement is issued. We believe this Statement will have
no impact on our financial statements once adopted.
FASB 152 - Accounting for Real Estate Time-Sharing Transactions
In December 2004, the FASB issued SFAS No. 152, which amends SFAS No. 66,
Accounting for Sales of Real Estate, to reference the financial accounting
and reporting guidance for real estate time-sharing transactions that is
provided in AICPA Statement of Position (SOP) 04-2, Accounting for Real
Estate Time-Sharing Transactions. This Statement also amends SFAS No. 67,
Accounting for Costs and Initial Rental Operations of Real Estate Projects,
to state that the guidance for (a) incidental operations and (b) costs
incurred to sell real estate projects does not apply to real-estate
time-sharing transactions. The accounting for those operations and costs is
subject to the guidance in SOP 04-2. This Statement is effective for
financial statements for fiscal years beginning after June 15, 2005. We
believe this Statement will have no impact on our financial statements once
adopted.
14
NOTE 11 NEW ACCOUNTING PRONOUNCEMENTS (CONTINUED)
FASB 153 - Exchanges of Nonmonetary Assets
In December 2004, the FASB issued SFAS No. 153. This Statement addresses
the measurement of exchanges of nonmonetary assets. The guidance in APB
Opinion No. 29, Accounting for Nonmonetary Transactions, is based on the
principle that exchanges of nonmonetary assets should be measured based on
the fair value of the assets exchanged. The guidance in that Opinion,
however, included certain exceptions to that principle. This Statement
amends Opinion No. 29 to eliminate the exception for nonmonetary exchanges
of similar productive assets and replaces it with a general exception for
exchanges of nonmonetary assets that do not have commercial substance. A
nonmonetary exchange has commercial substance if the future cash flows of
the entity are expected to change significantly as a result of the
exchange. This Statement is effective for financial statements for fiscal
years beginning after June 15, 2005. Earlier application is permitted for
nonmonetary asset exchanges incurred during fiscal years beginning after
the date of this Statement is issued. We believe this Statement will have
no impact on our financial statements once adopted.
FASB 123R (revised 2004) - Share-Based Payments
In December 2004, the FASB issued a revision to SFAS No. 123, Accounting
for Stock Based Compensation. This Statement supersedes APB Opinion No. 25,
Accounting for Stock Issued to Employees, and its related implementation
guidance. This Statement establishes standards for the accounting for
transactions in which an entity exchanges its equity instruments for goods
or services. It also addresses transactions in which an entity incurs
liabilities in exchange for goods or services that are based on the fair
value of the entity's equity instruments or that may be settled by the
issuance of those equity instruments. This Statement focuses primarily on
accounting for transactions in which an entity obtains employee services in
share-based payment transactions. This Statement does not change the
accounting guidance for share-based payment transactions with parties other
than employees provided in SFAS No. 123 as originally issued and EITF Issue
No. 96-18, "Accounting for Equity Instruments That Are Issued to Other Than
Employees for Acquiring, or in Conjunction with Selling, Goods or
Services." This Statement does not address the accounting for employee
share ownership plans, which are subject to AICPA Statement of Position
93-6, Employers' Accounting for Employee Stock Ownership Plans.
A public entity will initially measure the cost of employee services
received in exchange for an award of liability instruments based on its
current fair value; the fair value of that award will be re-measured
subsequently at each reporting date through the settlement date. Changes in
fair value during the requisite service period will be recognized as
compensation cost over that period. A nonpublic entity may elect to measure
its liability awards at their intrinsic value through the date of
settlement.
The grant-date fair value of employee share options and similar instruments
will be estimated using the option-pricing models adjusted for the unique
characteristics of those instruments (unless observable market prices for
the same or similar instruments are available).
15
NOTE 11 NEW ACCOUNTING PRONOUNCEMENTS (CONTINUED)
Excess tax benefits, as defined by this Statement, will be recognized as an
addition to paid-in-capital. Cash retained as a result of those excess tax
benefits will be presented in the statement of cash flows as financing cash
inflows. The write-off of deferred tax assets relating to unrealized tax
benefits associated with recognized compensation cost will be recognized as
income tax expense unless there are excess tax benefits from previous
awards remaining in paid-in capital to which it can be offset.
The notes to the financial statements of both public and nonpublic entities
will disclose information to assist users of financial information to
understand the nature of share-based payment transactions and the effects
of those transactions on the financial statements.
The effective date of this Statement for us is the first annual reporting
period beginning July 1, 2006. We intend to comply with this Statement at
the scheduled effective date for our relevant financial statements and
believe the adoption of the Statement may have a material impact on our
financial statements.
NOTE 12 SUBSEQUENT EVENTS
On April 12, 2005, the board of directors approved the issuance of 14,000
shares of restricted common stock to CEOcast, Inc. as partial consideration
for consulting services to be provided over a six month term being
performed pursuant to a consulting agreement dated April 12, 2005.
On April 22, 2005, the Board of Directors approved the following stock
options:
Officers and Directors
as a group 210,000
Employee 25,000
Consultant 25,000
--------
Total options granted 260,000
========
The exercise price of these options is $2.67 per share and the options vest
and may be exercised 1/3 each on January 1, 2006, 2007 and 2008. All of the
options expire on January 1, 2010.
On October 18, 2004, we entered into an agreement with UR-Energy Inc., a
privately held Canadian corporation, which stipulated, among other things,
that Aspen would exchange 2,000,000 shares it currently holds in ISL
Resources Corporation for 2,000,000 shares of UR-Energy Inc. restricted
common shares. We also received warrants for an additional 1,000,000 shares
of UR-Energy Inc. exercisable at $.75 Cdn per share.
The exchange of stock in ISL Resources Corporation stock in UR-Energy Inc.
had no immediate financial impact on Aspen since Aspen had carried the ISL
Resources Corporation shares at a zero basis on our books and no gain or
loss was recognized on the exchange.
16
NOTE 12 SUBSEQUENT EVENTS (CONTINUED)
On April 25, 2005, we entered into a transaction with UR-Energy Inc.
exchanging the 2,000,000 shares of their common stock and the warrants
referenced above for $560,000 (U.S.) and 500,000 shares of newly issued
UR-Energy Inc. common stock. The funds received increased our working
capital and will be used to cover a substantial portion of our fiscal 2005
drilling program. Financial and tax consequences of this transaction will
be recognized during our fourth quarter.
17
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
This segment should be read in conjunction with the management's discussion
and analysis of financial condition and results of operations contained in our
Annual Report on Form 10-KSB for the year ended June 30, 2004, which has been
filed with the Securities and Exchange Commission. The management discussion and
analysis and other portions of this report contain forward-looking statements
(as such term is defined in Section 21E of the Securities Exchange Act of 1934,
as amended). These statements reflect our current expectations regarding our
possible future results of operations, performance, and achievements. These
forward-looking statements are made pursuant to the safe harbor provisions of
the Private Securities Litigation Reform Act of 1995.
Wherever possible, we have tried to identify these forward-looking
statements by using words such as "anticipate," "believe," "estimate," "expect,"
"plan," "intend," and similar expressions. These statements reflect our current
beliefs and are based on information currently available to us. Accordingly,
these statements are subject to certain risks, uncertainties, and contingencies,
which could cause our actual results, performance, or achievements to differ
materially from those expressed in, or implied by, such statements. These risks,
uncertainties and contingencies include, without limitation, the factors set
forth in our Form 10-KSB under "Item 6. Management's Discussion and Analysis of
Financial Conditions or Plan of Operation - Factors that may affect future
operating results." We have no obligation to update or revise any such
forward-looking statements that may be made to reflect events or circumstances
after the date of this Form 10-QSB.
Overview
--------
Aspen Exploration Corporation was organized in 1980 for the purpose of
acquiring, exploring and developing oil and gas and other mineral properties.
Since 1996, we have focused our efforts on the exploration, development and
operation of natural gas properties in the Sacramento Valley of northern
California. We are currently the operator of 47 gas wells and have a
non-operated interest in 15 additional gas wells.
We currently have offices in Bakersfield, California and Denver, Colorado
and have 2 full time employees as well as the Chairman of the Board who
allocates a portion of his time to the Company. We also make extensive use of
consultants for the conduct of our business, ranging from financial,
engineering, land, legal, and geological and geophysical specialists.
We will typically review 20 to 25 prospects for every well we participate
in, using 3-D seismic and well control geology to evaluate each prospect. Our
goal is to identify low to moderate risk wells with good gas reserve potential.
Where possible, we attempt to be the operator of each property we invest
in. Our knowledge of drilling and operating wells in the Sacramento Valley
allows us to maximize the potential return of each property. Administrative
charges to the properties help cover approximately 35% of our selling, general
and administrative expenses.
Outlook and Trends
------------------
We expect our natural gas production (in volume of gas produced) to
increase substantially during fiscal 2005 due to recent drilling successes.
Total production for the year will depend on the number of wells successfully
18
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 $6.00 to $6.50 per MMBTU for the fiscal year
ended June 30, 2005 as compared to an average price of $4.96 per MMBTU during
the fiscal year ended June 30, 2004. Based upon the increasing production levels
and continued strong gas prices, which currently exceed $6.00 per MCF, Aspen
expects continued strong earnings for the balance of the year.
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 $6.12 per
MMBTU for the nine months ended March 31, 2005.
Non-Cash Transactions
---------------------
On October 18, 2004, we entered into an agreement with UR-Energy Inc., a
privately held Canadian corporation, which stipulated, among other things, that
Aspen would exchange 2,000,000 shares it currently holds in ISL Resources
Corporation for 2,000,000 shares of UR-Energy Inc. restricted common shares. We
also received warrants for an additional 1,000,000 shares of UR-Energy Inc.
exercisable at $.75 Cdn per share.
The exchange of stock in ISL Resources Corporation stock in UR-Energy Inc.
had no immediate financial impact on Aspen since Aspen had carried the ISL
Resources Corporation shares at a zero basis on our books and no gain or loss
was recognized on the exchange.
On April 25, 2005, we entered into a transaction with UR-Energy Inc.
exchanging the 2,000,000 shares of their common stock and the warrants
referenced above for $560,000 (U.S.) and 500,000 shares of newly issued
UR-Energy Inc. common stock. The funds received increased our working capital
and will be used to cover a substantial portion of our fiscal 2005 drilling
program. Financial and tax consequences of this transaction will be recognized
during our fourth quarter.
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 four years has been 87%. 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.
19
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. During the period April 1, 2005 through
September 30, 2005, we are contractually obligated to deliver 3,500 MMBTU per
day to two of our natural gas purchasers as follows:
2,000 MMBTU/Day @ $6.49 per MMBTU
1,500 MMBTU/Day @ $6.90 per MMBTU
The average price received during the first nine months of fiscal 2005 for
our natural gas was approximately $6.12 per MMBTU as compared to $4.88 per MMBTU
during the first nine months of fiscal 2004.
During December 2003, we borrowed $225,000 from a bank for an acquisition.
We currently pay 2% over the bank's prime rate for that facility. At March 31,
2005, the effective interest rate was 7.75% and the outstanding loan balance was
$37,500. In June 2004, we borrowed $300,000 from an Oklahoma corporation to
facilitate the drilling and completion of several wells in northern California.
This debt was converted to our common stock on July 15, 2004.
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.
For the nine months ended March 31, 2005, the increase in cash flow from
operations of $833,251, or 78%, was due primarily to:
An increase in net income of approximately $1,166,176 ($1,386,157 in 2005
as compared to $219,981 in 2004); and
A $1,411,291 decrease in accounts payable and accrued expenses in 2005
(which used cash during the 2005 period) compared to a decrease in accounts
payable and accrued expenses in 2004 of $111,494; and
The increase in net income and decrease in payable were further reduced by
an increase in receivables of $87,116 in 2005 (which used cash) compared to
an increase in receivables of $38,445 during 2004.
Investing activities used cash to increase capitalized oil and gas costs
and furniture and equipment of $1,270,499 and $1,033,040 in the nine months
ended March 31, 2005 and 2004. Cash in the current nine month period ended March
31, 2005 was used for lease acquisition, seismic work, intangible drilling and
well recompletions ($862,769), and the purchase of oil and gas well equipment
($400,370) and office equipment of ($7,360). These expenditures are net of the
sale of interests in wells to be drilled charged to third party investors.
20
We have a proposed drilling budget for the period March through December
2005. The budget includes drilling ten wells in the Sacramento gas province of
northern California, although the actual number of wells drilled will be based
on permit, pipeline, and rig availability considerations. Our share of the
estimated costs to complete this program is set forth in the following table:
Completion &
Area Wells Drilling Costs Equipping Costs Total
---------------------- ------------- -------------- --------------- --------------
West Grimes Field 4 $415,000 $312,000 $727,000
Colusa County, CA
Malton Black Butte 2 115,000 122,000 237,000
Field,
Tehama County, CA
Colusa County, CA 3 256,000 292,000 548,000
Yolo County, CA 1 17,500 43,000 60,500
--------------------- ------------- -------------- --------------- -------------
Total Expenditure 10 $803,500 $769,000 $1,572,500
============= ============== =============== =============
Our working capital (current assets less current liabilities) at March 31,
2005, was $1,551,388, which reflects an approximate $1,652,474 increase from our
working capital deficit at June 30, 2004. Our working capital situation improved
during the first nine months of our 2005 fiscal year because of our positive
cash flow from operations and our ability to pay down our current liabilities,
both made possible by our increase in net revenues and in net income recognized
during the period. We anticipate that our working capital and anticipated cash
flow from operations and future successful drilling will be sufficient to pay
our current liabilities as long as our gas production continues to provide us
with sufficient cash flow. As discussed below, this is dependent, in part, on
maintaining or increasing our level of production and the national and world
market maintaining its current prices for our gas production.
Our capital requirements can fluctuate over a twelve month period because
our drilling program is usually carried out in California's dry season, from
late April until November, after which wet weather either precludes further
activity or makes it cost prohibitive.
We believe that internally generated funds will be sufficient to finance
our drilling and operating expenses for the next twelve months. In June 2004, we
borrowed $300,000 from an Oklahoma corporation to facilitate the drilling and
completion of several wells in northern California. This debt and accrued
interest were converted into 300,500 shares of our common stock at $1.00 per
share on July 15, 2004. 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 planned future completion
and pipeline costs.
21
Results of Operations
---------------------
March 31, 2005 Compared to March 31, 2004
-----------------------------------------
For the nine months ended March 31, 2005, 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 nine months ended
March 31, 2005, our revenues increased by approximately $1,877,000 as compared
to the comparable period of our 2004 fiscal year because of:
Increased production (476,500 MMBTU sold as compared to 226,700 MMBTU sold
during the first nine months of our 2004 fiscal year);
Increased price received for our production (an average of $6.12 per MMBTU
during the first nine months of our 2005 fiscal year as compared to $4.88
per MMBTU received during that period in 2004); and
Increased management fees received ($201,441 during fiscal 2005 as compared
to $150,634 during fiscal 2004) because we were operators of more wells
during 2005 (47 wells compared to 33 wells in 2004).
For the three months ended March 31, 2005, our revenues increased by
approximately $702,000 as compared to the comparable period of 2004 because of:
Increased production (169,150 MMBTU sold as compared to 71,900 during the
three months ended March 31, 2004);
Increased price received for our production (an average of $6.52 per MMBTU
during the three months ended March 31, 2005 compared to $5.28 per MMBTU
received for the three months ended March 31, 2004); and
Oil and gas production costs increased $82,590, or 44%, for the nine months
ended March 31, 2005 and increased $21,123, or 25%, for the three months
ended March 31, 2005. The increase in operating costs can be attributed to
the addition of 8 net wells, from 54 wells to 62 wells and our percentage
working interests in these wells were somewhat higher than the average of
wells owned at March 31, 2004. An operator of two of the wells we
participated in provided us with a summary billing from inception to the
current year which accounted for approximately 12% of the year to date
increase. Equipment rental and water disposal fees increased due to the
addition of compressors and increased water production in our more mature
wells.
Depletion and depreciation expense increased $84,372 and $32,320 for the
nine and three months ended March 31, 2005. These increases of 22% and 25%,
respectively, were the result of using the approximate same depletion rate
as fiscal 2004, but applying it to a larger full cost pool which resulted
in the higher total depletion taken.
Management fees of $59,600, which is an increase of $21,000, or 54%, in
management fees, received during the three month period ended March 31,
2005 compared to management fees of $38,600 received in the prior three
month period. Management fees increased because our current year drilling
program was completed prior to the end of the second quarter. When the
second and third quarters of fiscal 2005 and 2004 are compared, management
fees increased $14,700, or 14%, from $104,700 to $119,400 and reflects
timing differences in the second and third quarters of 2004.
22
The following table sets forth certain items from our Condensed Consolidated
Statements of Operations as expressed as a percentage of total revenues, shown
for the nine months of fiscal 2005, 2004 and 2003:
For the Nine Months Ended
-----------------------------------------
3/31/2005 3/31/2004 3/31/2003
------------- ------------- -------------
Total revenues 100.0% 100.0% 100.0%
Oil & gas production costs 8.6 15.0 16.0
------------- ------------- -------------
Income from operations 91.4 85.0 84.0
------------- ------------- -------------
Costs and expenses
Depreciation and depletion 15.0 30.7 33.1
Selling, general and administrative 18.1 36.9 54.3
Interest expense - - -
------------- ------------- -------------
Total costs and expenses 33.1 67.6 87.4
------------- ------------- -------------
Income before income taxes 58.3 17.4 (3.4)
Provision for income taxes 13.9 - -
------------- ------------- -------------
Net income (loss) 44.4 17.4 (3.4)
============= ============= =============
To facilitate discussion of our operating results for the nine months ended
March 31, 2005 and 2004, we have included the following selected data from our
Condensed Consolidated Statements of Operations:
Comparison of the Fiscal
Nine Months Ended March 31, Increase (Decrease)
----------------------------------------------------------------------------
2005 2004 Amount Percentage
----------------------------------------------------------------------------
Revenues:
Oil and gas sales $ 2,933,599 $ 1,106,809 $ 1,826,790 165%
Management fees 201,441 150,634 50,807 34
Interest and other 3,338 4,338 (1,000) (23)
----------- ----------- ----------- -----------
Total revenues 3,138,378 1,261,781 1,876,597 149
----------- ----------- ----------- -----------
Cost and expenses:
Oil and gas production 270,891 188,301 82,590 44
Depreciation and depletion 469,896 385,524 84,372 22
General and administrative 568,493 464,026 104,467 23
Interest expense 5,831 3,949 1,882 48
----------- ----------- ----------- -----------
Total costs and expenses 1,315,111 1,041,800 273,311 26
----------- ----------- ----------- -----------
Income before taxes 1,823,267 219,981 1,603,286 729
Provision for income taxes 437,110 -- 437,110 N/A
----------- ----------- ----------- -----------
Net income $ 1,386,157 $ 219,981 $ 1,166,176 530%
=========== =========== =========== ===========
23
Central to the issue of success of the nine months operations ended March 31,
2005 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
-------------- --------------- ------------------
2005
----------------------------
lst Quarter $697,553 130,000 $5.31
2nd Quarter 1,132,359 177,350 6.37
3rd Quarter 1,103,687 169,150 6.52
-------------- --------------- ------------------
Year to date 2,933,599 476,500 6.16
-------------- --------------- ------------------
2004
----------------------------
lst Quarter 341,926 72,600 4.75
2nd Quarter 362,942 79,900 4.64
3rd Quarter 401,941 71,900 5.28
-------------- --------------- ------------------
Year to date 1,106,809 224,400 4.88
-------------- --------------- ------------------
2003
----------------------------
lst Quarter 198,431 65,800 2.78
2nd Quarter 241,700 63,700 3.76
3rd Quarter 314,222 57,900 5.47
-------------- --------------- ------------------
Year to date 754,353 187,400 3.23
-------------- --------------- ------------------
Third Quarter change
----------------------------
2005
----------------------------
Amount $701,746 97,250 $1.24
Percentage 175% 135% 23%
2004
----------------------------
Amount $87,719 14,000 $(.19)
Percentage 28% 24% (3%)
(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 first nine months of fiscal 2005 and the twelve
months of fiscal 2004. As the table above notes, revenue has increased
approximately 175% when comparing the two three month periods ended March 31,
2005 and 2004. Volumes sold increased approximately 135%, while the price
received for our product increased 23%.
Total revenue increased $1,876,600, or 149% when comparing the two periods,
while operating and production costs increased $82,600, or 44%.
A significant ratio presented is the percentage of management fees charged to
operated wells versus our general and administrative costs. This coverage of
general and administrative costs improved from approximately 32% for the nine
months ended March 31, 2004 to approximately 35% at March 31, 2005.
When comparing general and administrative expense for 2005 and 2004, costs
increased by $104,500, or 23% due to increased audit and accounting fees,
officers salaries and the initiation of an investor relations service.
24
Results of operations and net income are presented in the following table:
Quarterly Financial Information (unaudited)
(1) (2) Net Income (loss)
Total Operating Net Income Per Share
Revenues Income (loss) Basic Diluted
--------------- -------------- ----------------- ----------- -------------
2005
------------------------
1st Quarter $784,299 $715,249 $389,781 $.063 $.061
2nd Quarter 1,190,333 1,092,632 729,748 .074 .070
3rd Quarter 1,163,746 1,056,268 703,738 .109 .109
--------------- -------------- ----------------- ----------- -------------
Total 3,138,378 2,864,149 1,823,267 .25 .24
--------------- -------------- ----------------- ----------- -------------
2004
------------------------
lst Quarter 388,337 348,739 50,197 .010 .010
2nd Quarter 433,317 365,761 93,022 .010 .010
3rd Quarter 440,127 354,642 76,762 .010 .010
--------------- -------------- ----------------- ----------- -------------
Total 1,261,781 1,069,142 219,981 0.03 0.03
--------------- -------------- ----------------- ----------- -------------
2003
------------------------
lst Quarter 264,896 223,246 (41,650) (.01) (.01)
2nd Quarter 279,080 237,155 (15,660) - -
3rd Quarter 337,476 271,845 28,748 - -
--------------- -------------- ----------------- ----------- -------------
Total $ 881,452 $ 732,246 $ (28,562) - -
--------------- -------------- ----------------- ----------- -------------
(1) Operating income is oil and gas sales plus management fees less direct
operating costs.
(2) Before provision for deferred income taxes.
As can be seen in the table, revenues and operating income have improved in
every quarter when comparing the nine month periods ended March 31, 2005 and
2004. We believe this is due to the steady increase in production volumes sold
in each subsequent quarter and the fact that we have enjoyed an appreciating
price received for our product. Operating income has increased because
production costs have increased at a lesser rate than production and prices.
Contractual Obligations:
------------------------
We had four contractual obligations as of March 31, 2005. The following table
lists our significant liabilities at March 31, 2005:
Payments Due By Period
------------------------------------------------------------------------------------------
Less than After
Contractual Obligations 1 year 2-3 years 4-5 years 5 years Total
------------------------- --------------- -------------- -------------- --------------- ---------------
Employment Obligations $214,714 $500,678 $261,020 $-0- 976,412
Bank Loans 37,500 -0- -0- -0- 37,500
Operating Leases 8,470 -0- -0- -0- 8,470
--------------- -------------- -------------- --------------- ---------------
Total contractual
cash obligations $260,684 $500,678 $261,020 $-0- $1,022,382
=============== ============== ============== =============== ===============
25
In addition to the contractual obligations disclosed in the preceding table, we
also have made certain commitments for drilling pursuant to a budget described
in Note 10 to the financial statements for the nine months ended March 31, 2005.
Based on that budget, we also expect to expend $733,500 in drilling ten wells
through December 2005, and up to an additional $772,000 if all ten wells are
completed and equipped for production.
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 on the Denver office through December 31, 2004
at a lease rate of $1,261 per month. We are currently leasing this space on a
month to month basis. The Bakersfield, California office has 546 square feet and
a monthly rental fee of $730 to $770 over the term of the lease. The three year
lease expires February 8, 2006. Rent expense for the nine months ended March 31,
2005 and 2004 was $18,921 and $18,337, respectively.
We have sufficient working capital to meet all of these commitments and
obligations.
Critical Accounting Policies and Estimates:
-------------------------------------------
We believe the following critical accounting policies affect our most
significant judgments and estimates used in the preparation of our Condensed
Consolidated Financial Statements.
Reserve Estimates:
------------------
Our estimates of oil and natural gas reserves, by necessity, are projections
based on geologic and engineering data, and there are uncertainties inherent in
the interpretation of such data as well as the projection of future rates of
production and the timing of development expenditures. Reserve engineering is a
subjective process of estimating underground accumulations of oil and natural
gas that are difficult to measure. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological
interpretation and judgment. Estimates of economically recoverable oil and
natural gas reserves and future net cash flows necessarily depend upon a number
of variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects of
regulations by governmental agencies and assumptions governing future oil and
natural gas prices, future operating costs, severance and excise taxes,
development costs and workover and remedial costs, all of which may in fact vary
considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of oil and natural gas attributable to any
particular group of properties, classifications of such reserves based on risk
of recovery, and estimates of the future net cash flows expected therefrom may
vary substantially. Any significant variance in the assumptions could materially
affect the estimated quantity and value of the reserves, which could affect the
carrying value of our oil and gas properties and/or the rate of depletion of the
oil and gas properties. Actual production, revenues and expenditures with
respect to our reserves will likely vary from estimates, and such variances may
be material.
Many factors will affect actual future net cash flows, including:
- The amount and timing of actual production;
- Supply and demand for natural gas;
- Curtailments or increases in consumption by natural gas purchasers; and
- Changes in governmental regulations or taxation.
26
Accounts Receivable:
--------------------
Accounts receivable balances are evaluated on a continual basis and allowances
are provided for potentially uncollectable accounts based on management's
estimate of the collectability of customer accounts. If the financial condition
of a customer were to deteriorate, resulting in an impairment of its ability to
make payments, an additional allowance may be required. Allowance adjustments
are charged to operations in the period in which the facts that give rise to the
adjustments become known.
Property, Equipment, Depreciation and Depletion:
------------------------------------------------
We follow the full-cost method of accounting for oil and gas properties. Under
this method, all productive and nonproductive costs incurred in connection with
the exploration for and development of oil and gas reserves are capitalized.
Such capitalized costs include lease acquisition, geological and geophysical
work, delay rentals, drilling, completing and equipping oil and gas wells,
including salaries, benefits and other internal salary related costs directly
attributable to these activities. Costs associated with production and general
corporate activities are expensed in the period incurred. Interest costs related
to unproved properties and properties under development are also capitalized to
oil and gas properties. If the net investment in oil and gas properties exceeds
an amount equal to the sum of (1) the standardized measure of discounted future
net cash flows from proved reserves, and (2) the lower of cost or fair market
value of properties in process of development and unexplored acreage, the excess
is charged to expense as additional depletion. Normal dispositions of oil and
gas properties are accounted for as adjustments of capitalized costs, with no
gain or loss recognized.
We apply SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets." Under SFAS No. 144, long-lived assets and certain intangibles are
reported at the lower of the carrying amount or their estimated recoverable
amounts. Long-lived assets subject to the requirements of SFAS No. 144 are
evaluated for possible impairment through review of undiscounted expected future
cash flows. If the sum of undiscounted expected future cash flows is less than
the carrying amount of the asset or if changes in facts and circumstances
indicate, an impairment loss is recognized.
Asset retirement obligations:
-----------------------------
We recognize the future cost to plug and abandon gas wells over the estimated
useful life of the wells in accordance with the provision of SFAS No. 143. SFAS
No. 143 requires that we record a liability for the present value of the asset
retirement obligation with a corresponding increase to the carrying value of the
related long-lived asset. We amortize the amount added to the oil and gas
properties and recognize accretion expense in connection with the discounted
liability over the remaining lives of the respective gas wells. Our liability
estimate is based on our historical experience in plugging and abandoning gas
wells, estimated well lives based on engineering studies, external estimates as
to the cost to plug and abandon wells in the future and federal and state
regulatory requirements. The liability is discounted using a credit-adjusted
risk-free rate of 6%. Revisions to the liability could occur due to changes in
well lives, or if federal and state regulators enact new requirements on the
plugging and abandonment of gas wells.
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Item 3. CONTROLS AND PROCEDURES
As required by Rule 13a-15 under the Securities Exchange Act of 1934, as of
the filing date of this report, we carried out an evaluation of the
effectiveness of the design and operation of our disclosure controls and
procedures. This evaluation was carried out under the supervision and with the
participation of our principal executive officer (who is also our principal
financial officer), who concluded that our disclosure controls and procedures
are effective. There have been no significant changes in our internal controls
or in other factors, which could significantly affect internal controls
subsequent to the date we carried out our evaluation.
Disclosure controls and procedures are controls and other procedures
that are designed to ensure that information required to be disclosed in our
reports filed or submitted under the Securities Exchange Act is recorded,
processed, summarized and reported, within the time periods specified in the
Securities and Exchange Commission's rules and forms. Disclosure controls and
procedures include, without limitation, controls and procedures designed to
ensure that information required to be disclosed in our reports filed under the
Exchange Act is accumulated and communicated to management, including our
principal executive officer and our principal financial officer, as appropriate,
to allow timely decisions regarding required disclosure.
PART II
Item 1. Legal Proceedings.
------------------
There are no material pending legal or regulatory proceedings against Aspen
Exploration Corporation, and it is not aware of any that are known to be
contemplated.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
------------------------------------------------------------
During 2004, we issued a convertible debenture and detachable warrants to
one accredited investor in exchange for the investor's loan to us of $300,000.
On July 15, 2004, the debt was converted to 300,500 shares of restricted common
stock as consideration for payment of principal and interest.
The convertible debenture included warrants for up to 600,000 shares of
common stock exercisable as follows:
There were two warrants, each for 300,000 shares of common stock. The
holder exercised the initial warrant on March 11, 2005 and we received
$330,000 ($1.10 per share) and issued 300,000 shares of stock. Because the
holder exercised the first warrant before March 31, 2005, we issued an
additional warrant exercisable to purchase another 300,000 shares at $1.25
per share. The warrant will expire unless exercised by June 30, 2006.
The initial warrants were valued using the Black-Scholes valuation method
at $39,281 and have been recorded as a discount to the debt.
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.
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The following sets forth the information required by Item 701 in connection
with that transaction:
(a) The conversion was completed effective July 15, 2004.
(b) There was no placement agent or underwriter for the transaction or the
original transaction that took place in fiscal year 2004.
(c) The shares were not sold for cash. The shares of common stock were issued in
exchange for (and in conversion of) outstanding convertible debt.
(d) We relied on the exemption from registration provided by Sections 3(a)(9)
under the Securities Act of 1933 for the conversion transaction, and upon the
exemptions from registration provided by Sections 4(2), 4(6), and Regulation D
for the issuance of the initial debt. In addition, we did not engage in any
public advertising or general solicitation in connection with this transaction;
and 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 Exploration it requested, received answers to all questions it
posed, and otherwise understood the risks of accepting our securities for
investment purposes.
(e) The common stock issued in this transaction are not convertible or
exchangeable. Warrants were issued in this transaction as described above. There
are no registration rights associated with the issuance of the common stock or
the warrants.
(f) We received no cash proceeds from the issuance of the shares of common
stock. The original loan made by the accredited investor was used for working
capital and drilling operations.
On April 12, 2005, the board of directors approved the issuance of 14,000
shares of restricted common stock to CEOcast, Inc. as partial consideration for
consulting services to be provided over a six month term being performed
pursuant to a consulting agreement dated April 12, 2005. The following sets
forth the information required by Item 701 in connection with that transaction:
(a) The issuance was completed on April 22, 2005.
(b) There was no placement agent or underwriter for the transaction.
(c) The shares were not sold for cash. The shares of common stock were issued in
exchange for services pursuant to a consulting agreement.
(d) We relied on the exemption from registration provided by Sections 4(2) and
4(6) under the Securities Act of 1933 and Regulation D for the issuance of the
shares. In addition, we did not engage in any public advertising or general
solicitation in connection with this transaction; and we provided the investor
with disclosure of all aspects of our business, including providing the 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 investor obtained
all information regarding Aspen Exploration it requested, received answers to
all questions it posed, and otherwise understood the risks of accepting our
securities for investment purposes.
29
(e) The common stock issued in this transaction is not convertible or
exchangeable. Aspen Exploration granted piggyback registration rights to
CEOcast, Inc.
(f) We received no cash proceeds from the issuance of the shares of common
stock.
Item 3. Defaults Upon Senior Securities.
--------------------------------
None.
Item 4. Submission of Matters to a Vote of Security Holders.
----------------------------------------------------
No matter was submitted during the first quarter of the fiscal year covered
by this report to a vote of security holders, through the solicitation of
proxies or otherwise.
Item 5. Other Information.
------------------
None.
Item 6. Exhibits.
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31. Rule 13a-14(a) Certification
32. Section 1350 Certification
In accordance with the requirements of the Securities Exchange Act of 1934,
we have duly caused this report to be signed on our behalf by the undersigned,
thereunto duly authorized.
ASPEN EXPLORATION CORPORATION
/s/ Robert A. Cohan
-----------------------------------
By: Robert A. Cohan,
May 10, 2005 Chief Executive Officer,
Principal Financial Officer
30