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 September 30, 2006
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 by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
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 November 10, 2006
Common stock, $.005 par value 7,159,622
Transitional small business disclosure format: [ ] Yes [X] No
Part One. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
September 30, June 30,
2006 2006
------------ ------------
(unaudited)
ASSETS
Current Assets:
Cash and cash equivalents $ 3,276,757 $ 6,466,010
Short-term investments 994,350 1,002,527
Accounts and trade receivables 2,890,227 2,119,758
Accounts receivable - related party 1,273 1,273
Prepaid expenses 370,200 338,000
Precious metals 18,823 18,823
------------ ------------
Total Current Assets 7,551,630 9,946,391
------------ ------------
Investment in oil and gas properties, at cost
(full cost method of accounting) 15,549,117 14,274,642
Less accumulated depletion and impairment (6,588,564) (6,118,879)
------------ ------------
8,960,553 8,155,763
------------ ------------
Property and Equipment, at cost:
Furniture, fixtures, and vehicles 184,151 122,576
Less accumulated depreciation (32,912) (54,710)
------------ ------------
151,239 67,866
------------ ------------
Other Assets:
Deposits 250,000 250,000
Deferred tax asset 1,368,000 771,000
------------ ------------
1,618,000 1,021,000
------------ ------------
Total Assets $ 18,281,422 $ 19,191,020
============ ============
(Statement Continues)
The accompanying notes are an integral part of these consolidated
financial statements.
2
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)
September 30, June 30,
2006 2006
------------ -------------
(unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued expenses $ 2,690,502 $ 3,823,298
Advances from joint interest owners 1,470,256 2,187,147
Asset retirement obligation, current portion 18,400 62,800
------------ ------------
Total Current Liabilities 4,179,158 6,073,245
------------ ------------
Asset Retirement Obligation, net of current portion 337,670 331,823
Deferred Income Taxes 3,196,000 2,685,000
------------ ------------
Total Long Term Liabilities 3,533,670 3,016,823
------------ ------------
Total Liabilities 7,712,828 9,090,068
------------ ------------
Commitments and Contingencies (Note 6)
Stockholders' Equity:
Common stock, $.005 par value:
Authorized: 50,000,000 shares
Issued and outstanding: At September 30, 2006, 7,159,622
shares and June 30, 2006, 7,094,641 shares 35,723 35,473
Capital in excess of par value 7,366,672 7,283,914
Retained earnings 3,172,017 2,900,798
Deferred compensation (5,818) (119,233)
------------ ------------
Total Stockholders' Equity 10,568,594 10,100,952
------------ ------------
Total Liabilities and Stockholders' Equity $ 18,281,422 $ 19,191,020
============ ============
The accompanying notes are an integral part of these consolidated financial statements.
3
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended
September 30,
--------------------------
2006 2005
----------- -----------
Revenues:
Oil and gas $ 962,933 $ 1,062,543
Management fees 96,103 120,924
Interest and other income 21,415 10,701
----------- -----------
Total Revenues 1,080,451 1,194,168
----------- -----------
Costs and Expenses:
Oil and gas production 191,178 71,019
Depreciation, depletion and amortization 480,277 254,336
Interest expense 4,745 --
Selling, general and administrative 493,568 227,116
----------- -----------
Total Costs and Expenses 1,169,768 552,471
----------- -----------
Operating Income (89,317) 641,697
Gain on Investments 262,536 --
Gain on Sale of Equipment 12,000 --
----------- -----------
Total Other Income 274,536 --
----------- -----------
Income Before Income Taxes 185,219 641,697
Income Tax Benefit (Provision) 86,000 (180,395)
----------- -----------
Net Income $ 271,219 $ 461,302
=========== ===========
Basic Earnings Per Common Share $ 0.04 $ 0.07
=========== ===========
Diluted Earnings Per Common Share $ 0.04 $ 0.06
=========== ===========
Weighted average number of common shares outstanding:
Basic 7,130,175 6,745,808
=========== ===========
Diluted 7,372,424 7,163,243
=========== ===========
The accompanying notes are an integral part of these consolidated
financial statements.
4
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended September 30,
--------------------------------
2006 2005
----------- -----------
Cash Flows from Operating Activities:
-------------------------------------
Net income $ 271,219 $ 461,302
Adjustments to reconcile net income to net cash provided
(used) by operating activities:
Accretion and depreciation, depletion, and amortization 480,277 254,336
Deferred income taxes (86,000) 180,395
Amortization of deferred compensation expense 113,415 --
Compensation expense related to stock options granted 54,508 --
Realized gain on investments (129,638) --
Unrealized gain on investments (130,414) --
Proceeds from sale of investments 268,230 --
Gain on sale of vehicle (12,000) --
Changes in assets and liabilities:
Decrease (increase) in receivable, prepaid expenses, and
Deposits (1,313,670) (198,002)
Increase (decrease) in accounts payable, accrued expenses,
deferred taxes, and advances from joint owners (1,338,687) 617,193
----------- -----------
Net Cash Provided (Used) by Operating Activities (1,822,760) 1,315,224
----------- -----------
Cash Flows from Investing Activities:
Additions to oil and gas properties (1,317,931) (1,102,995)
Additions to property and equipment (89,062) --
Sale of property and equipment 12,000 2,000
----------- -----------
Net Cash Used by Investing Activities (1,394,993) (1,100,995)
----------- -----------
Cash Flows from Financing Activities:
Proceeds from exercise of stock options 28,500 14,250
----------- -----------
Net Increase (Decrease) in Cash and Cash Equivalents (3,189,253) 228,479
Cash and Cash Equivalents, beginning of year 6,466,010 3,430,146
----------- -----------
Cash and Cash Equivalents, end of year $ 3,276,757 $ 3,658,625
=========== ===========
Other Information:
Interest paid $ 4,745 $ --
=========== ===========
Non-Cash Investing and Financing Activities:
Asset retirement obligation $ -- $ 26,000
The accompanying notes are an integral part of these consolidated financial statements.
5
ASPEN EXPLORATION CORPORATION
Notes to Condensed Consolidated Financial Statements
(Unaudited)
September 30, 2006
NOTE 1 - BASIS OF PRESENTATION
------------------------------
The accompanying financial statements of Aspen Exploration Corporation (the
Company) are unaudited. However, in the opinion of management, the accompanying
financial statements reflect all adjustments, consisting of only normal
recurring adjustments, necessary for fair presentation for the interim period.
The financial statements included herein have been prepared by the Company
pursuant to the rules and regulations of the Securities and Exchange Commission.
Certain information and footnote disclosures normally included in financial
statements prepared in accordance with generally accepted accounting principles
have been condensed or omitted pursuant to such rules and regulations.
Management believes the disclosures made are adequate to make the information
not misleading and suggests that these condensed financial statements be read in
conjunction with the financial statements and notes hereto included in the
Company's Form 10-KSB for the year ended June 30, 2006.
This Form 10-QSB includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical fact included in this Form 10-QSB, including, without
limitation, the statements under both "Notes to Consolidated Financial
Statements" and "Item 2. Management's Discussion and Analysis" located elsewhere
herein regarding the Company's financial position and liquidity, its strategies,
financial instruments, and other matters, are forward-looking statements.
Although the Company believes that the expectations reflected in such
forward-looking statements are reasonable, it can give no assurance that such
expectations will prove to have been correct. Important factors that could cause
actual results to differ materially from the Company's expectations are
disclosed in this Form 10-QSB in conjunction with the forward-looking
statements.
NOTE 2 - SIGNIFICANT ACCOUNTING POLICIES
----------------------------------------
The preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. The Company bases its
estimates on historical experience and on various other assumptions it believes
to be reasonable under the circumstances. Although actual results may differ
from these estimates under different assumptions or conditions, the Company
believes that its estimates are reasonable and that actual results will not vary
significantly from the estimated amounts.
NOTE 3 - SHARE-BASED COMPENSATION
---------------------------------
Stock Options
-------------
Effective July 1, 2006, the Company adopted the fair value recognition
provisions of Statement of Financial Accounting Standard 123(R) "Share-Based
Payment" ("SFAS 123(R)") using the modified prospective transition method. In
addition, the Securities and Exchange Commission issued Staff Accounting
Bulletin No. 107 "Share-Based Payment" ("SAB 107") in March, 2005, which
provides supplemental SFAS 123(R) application guidance based on the views of the
SEC. Under the modified prospective transition method, compensation cost
recognized in the quarterly period ended September 30, 2006 includes: (a)
compensation cost for all share-based payments granted prior to, but not yet
vested as of July 1, 2006, based on the grant date fair value estimated in
accordance with the original provisions of SFAS No. 123, and (b) compensation
cost for all share-based payments granted beginning July 1, 2006, based on the
grant date fair value estimated in accordance with the provisions of SFAS
123(R). In accordance with the modified prospective transition method, results
for prior periods have not been restated.
The Company currently has two share-based employee compensation plans, which are
described in the Notes to Consolidated Financial Statements in the company's
Annual Report on Form 10-KSB for the year ended June 30, 2006.
6
There was an aggregate of 936,000 common shares reserved for issuance under our
stock option plans effective at April 22, 2005, and March 14, 2002. These plans
provided for the issuance of 260,000 and 676,000 common shares, respectively,
pursuant to stock option exercises. The fair value of each option grant, as
opposed to its exercise 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 76%, risk free interest
rates of 3.92% and expected lives of 4.5 years. Expected volatility was
calculated based upon actual historical stock price movements over the most
recent periods ending September 30, 2006 equal to the expected option term.
Expected pre-vesting forfeitures were assumed to be zero. The expected option
term was calculated using the "simplified" method permitted by SAB 107.
The adoption of SFAS 123(R) resulted in stock compensation expense for the
quarterly period ended September 30, 2006 of $31,000 to income from continuing
operations and income before income taxes. This expense did not have a
significant effect on diluted earnings per share for the quarter.
Prior to July 1, 2006, the Company accounted for this plan under the recognition
and measurement provisions of Accounting Principles Board ("APB") Opinion No.
25, Accounting for Stock Issued to Employees, and related interpretations, as
permitted by Statement of Financial Accounting Standards ("SFAS") No. 123,
Accounting for Stock-Based Compensation. No stock-based employee compensation
expense was recognized in the Company's Consolidated Statement of Operations
prior to July 1, 2006, as all options granted under the Company's stock-based
compensation plan had an exercise price equal to the market value of the
underlying common stock on the date of grant. Effective July 1, 2006, the
Company adopted the fair value recognition provisions of SFAS No. 123 (R), Share
Based Payment, using the modified-prospective transition method as described in
SFAS No. 148, Accounting for Stock-Based Compensation - Transition and
Disclosure. Under this method, compensation cost recognized in the first quarter
of fiscal 2007 is the same as that which would have been recognized had the
recognition provisions of Statement 123 been applied from its original effective
date.
A summary of the pro forma effects to reported net income and earning per share,
as if the Company had elected to recognize compensation cost based on the fair
value of the options granted at grant date as prescribed by SFAS No. 123 for all
periods presented:
3 Months Ended
------------------
September 30, 2005
------------------
Net income, as reported $ 461,302
Add: Stock-based employee compensation expense included in
reported net income, net of related tax effects --
Deduct: Total stock-based compensation expense determined
under fair value based method for all awards, net of related tax effects (27,000)
-----------
Pro forma net income $ 434,302
===========
Basic Earnings Per Share
As Reported 0.07
Pro Forma 0.06
Diluted Earnings Per Share
As Reported 0.06
Pro Forma 0.06
On August 11, 2006, the Board Chairman exercised his option for 50,000 shares of
our common stock granted March 14, 2002 at a price of $0.57 per share. As
consideration for the option shares purchased, Mr. Bailey paid cash
consideration of $28,500.
On August 14, 2006, an employee exercised her option for 17,000 shares of our
common stock granted March 14, 2002 at a price of $0.57 per share. As
consideration for the option shares purchased, the employee surrendered shares
equal to the exercise price.
7
Additionally, 10,000 options were granted to a non-employee Director on
September 11, 2006. The fair value of those options was estimated using the
Black-Scholes option-pricing model with the following assumptions: no dividend
yield, expected volatility of 73%, risk free interest rates of 4.97% and
expected life of 5 years. As a result, $23,500 was recognized as Director Fees
during the first quarter.
A summary of option activity under the plans as of September 30, 2006, and
changes during the three months then ended, is presented below:
Weighted
Weighted Average
Average Remaining Aggregate
Number of Exercise Contractual Intrinsic
Shares Price Term Value
-------- ----- ---- --------
Outstanding at June 30, 2006 484,000 1.56
Granted 10,000 3.70
Exercised (64,981) 0.57
Forfeited or expired (99,019) 0.57
--------
Outstanding at September 30, 2006 330,000 $1.75 2.69 $627,000
======== ===== ==== ========
Exercisable at September 30, 2006 166,667 $1.47 2.54 $363,334
======== ===== ==== ========
The grant-date fair value of options granted during the period was $2.35. The
total intrinsic value of options exercised during the period was $269,960.
A summary of the status of the Company's nonvested shares as of September 30,
2006, and changes during the three months ended September 30, 2006, is presented
below:
Weighted-Average
Number of Grant-Date
Nonvested Shares Shares Fair Value
---------------- -------- ----------
Nonvested at June 30, 2006 256,666 $1.85
Granted -- --
Vested (50,000) 0.57
Forfeited or expired (43,333) 2.67
--------
Nonvested at September 30, 2006 163,333 $2.03
======== =====
The total compensation cost related to nonvested awards not yet recognized on
September 30, 2006 is approximately $51,000 net of tax, and the weighted average
period over which this cost is expected to be recognized is 1.07 years. The
total fair value of options vested during the period was $25,000.
8
The following information summarizes information with respect to options granted
under equity plans:
Outstanding Exercisable
--------------------------- -------------------------
Weighted
Average
Remaining Weighted Weighted
Contractual Average Average
Exercise Number Life in Years Exercisable Number Exercisable
Price Outstanding (1) Price Exercisable Price
-------- ----------- ------------- ----------- ----------- -----------
$0.57 150,000 1.88 $0.57 100,000 $0.57
2.67 170,000 3.28 2.67 56,667 2.67
3.70 10,000 4.95 3.70 10,000 3.70
--------- -------- ------- --------- -------
330,000 2.69 $1.75 166,667 $1.47
========= ======== ======= ========= =======
(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.
NOTE 4 - EARNINGS PER SHARE
---------------------------
The Company's calculation of earnings per share of common stock is as follows:
Three Months Ending September 30,
-------------------------------------------------------------------
2006 2005
-------------------------------- --------------------------------
Net Per Share Net Per Share
Income Shares Amount Income Shares Amount
--------- --------- -------- --------- --------- --------
Basic Earnings Per Share:
Net income and share
amounts $ 271,219 7,130,175 $ 0.04 $ 461,302 6,745,808 $ 0.07
Effect of Dilutive
Securities:
Stock Options -- 242,250 -- -- 417,435 (0.01)
--------- --------- -------- --------- --------- --------
Diluted Earnings Per Share:
Net income and assumed
share conversion $ 271,219 7,372,425 $ 0.04 $ 461,302 7,163,243 $ 0.06
========= ========= ======== ========= ========= ========
NOTE 5 - INCOME TAXES
---------------------
The Company uses the asset and liability method of accounting for deferred
income taxes. Deferred tax assets and liabilities are determined based on the
temporary differences between the financial statement and tax basis of assets
and liabilities. Deferred tax assets or liabilities at the end of each period
are determined using the tax rate in effect at that time.
The total future deferred income tax liability is extremely complicated for any
energy company to estimate due in part to the long-lived nature of depleting oil
and gas reserves and variables such as product prices. Accordingly, the
liability is subject to continual recalculation, revision of the numerous
estimates required, and may change significantly in the event of such things as
major acquisitions, divestitures, product price changes, changes in reserve
estimates, changes in reserve lives, and changes in tax rates or tax laws.
9
NOTE 6 - CONTINGENCIES AND DRILLING COMMITMENTS
-----------------------------------------------
On December 20, 2005 Calpine Corporation, one of our major purchasers of natural
gas (currently purchases about 10% of our gas), filed for Chapter 11 bankruptcy
protection in New York. At the time of the filing, Calpine Corporation owed the
Company, exclusive of outside owner participation, approximately $193,000. The
Company believes that the amount due to Aspen at the time of this filing will be
collectible, and has not established a reserve or allowance, but because of
issues associated with all bankruptcies, there are no assurances that it will be
collected. The Company will continue to monitor the situation with respect to
collectibility and take further actions as determined to be appropriate.
On July 31, 2006, the Company entered into a gas sales contract to sell Enserco
2,000 MMBTU of gas per day at a fixed price of $10.15 less transportation and
other expenses. The contract is for the term November 1, 2006 through March 31,
2007, requires Enserco to purchase the stated quantities at the stated prices,
and contains monetary penalties for non-delivery of the gas. On October 4, 2006,
the Company entered into a gas sales contract to sell Enserco 2,000 MMBTU of gas
per day at a fixed price of $7.30 less transportation and other expenses. The
contract is for the term December 1, 2006 through March 31, 2007, requires
Enserco to purchase the stated quantities at the stated prices, and contains
monetary penalties for non-delivery of the gas. These contracts were designated
as normal sales contracts.
The Company has the following commitments for drilling and completion for the
period October 2006 through December 2006:
Drilling Completion and
Area Wells Costs Equipment Costs Total
---- ----- ----- --------------- -----
West Grimes Field
Colusa County, CA 2 $- $132,000 $132,000
Malton Black Butte
Tehama County, CA 2 85,000 174,000 259,000
----- ------- -------- --------
Total Expenditures 4 $85,000 $306,000 $391,000
===== ======= ======== ========
NOTE 7 - ASSET RETIREMENT OBLIGATION
------------------------------------
The Company has 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 the Company to recognize an estimated
liability for the plugging and abandonment of all oil and gas wells. 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. The increase in the asset
will be amortized over time 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. In
the first quarter, the Company plugged four wells and added two resulting in a
net decrease to the ARO liability of $43,457. Accretion expense of $4,903 was
recognized during the period ending September 30, 2006.
10
NOTE 8 - RECENT ACCOUNTING PRONOUNCEMENTS
-----------------------------------------
In September 2006, Statement of Financial Accounting Standards (SFAS) No. 157,
Fair Value Measurements was issued by the Financial Accounting Standards Board
(FASB). This statement defines fair value, establishes a framework for measuring
fair value and expands disclosures about fair value measurements. SFAS No. 157
will become effective for the Company's fiscal year beginning after November 15,
2007, and the Company is currently assessing the potential impact of this
Statement on its financial statements.
In September 2006, the FASB issued SFAS No. 158, "Employers' Accounting for
Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB No.
87, 88, 106 and 132(R)." FASB No. 158 improves financial reporting by requiring
an employer to recognize the over funded or under funded status of a defined
benefit postretirement plan (other than a multiemployer plan) as an asset or
liability in its statement of financial position and to recognize changes in
that funded status in the year in which the changes occur through comprehensive
income. This Statement also improves financial reporting by requiring an
employer to measure the funded status of a plan as of the date of its year-end
statement of financial position, with limited exceptions. FASB No. 158 is
effective as of the fiscal year ending after December 15, 2006. The Company does
not believe SFAS No. 158 will have an impact on its of operations.
In September 2006, Staff Accounting Bulletin ("SAB") No. 108, Considering the
Effects of Prior Year Misstatements when Quantifying Misstatements in Current
Year Financial Statements. Registrants must quantify the impact on current
period financial statements of correcting all misstatements, including both
those occurring in the current period and the effect of reversing those that
have accumulated from prior periods. This SAB will be applied beginning with the
first fiscal year ending after November 15, 2006. The adoption of SAB No. 108
should have no effect to the financial position and result of operations of the
Company.
In June 2006, the FASB issued Interpretation (FIN) No. 48, Accounting for
Uncertainty in Income Taxes--an interpretation of FASB Statement No. 109. FIN 48
prescribes a recognition threshold and measurement attribute for the financial
statement recognition and measurement of a tax position taken or expected to be
taken in a tax return, and provides guidance on derecognition, classification,
interest and penalties, accounting in interim periods, disclosure, and
transition. This Interpretation is effective for fiscal years beginning after
December 15, 2006. The Company is currently assessing the potential impact of
this Interpretation on its financial statements.
In February 2006, SFAS No. 155, Accounting for Certain Hybrid Financial
Instruments--an amendment of FASB Statements No. 133 and 140 was issued. This
Statement resolves issues addressed in Statement 133 Implementation Issue No.
D1, Application of Statement 133 to Beneficial Interests in Securitized
Financial Assets. SFAS No. 155 will become effective for the Company's fiscal
year beginning after September 15, 2006, and the Company is currently assessing
the potential impact of this Statement on its financial statements.
NOTE 9 - SUBSEQUENT EVENTS
--------------------------
On November 8, 2006, the Aspen board of directors voted to declare a cash
dividend of $0.05 per share payable on or about December 6, 2006 to shareholders
of record November 20, 2006.
The Stoddard-Johnston #1-1 well, located in the West Grimes Gas Field, Colusa
County, California, was drilled to a depth of 8,700 feet and encountered 60 feet
of potential gas pay in several intervals in the Forbes formation. One of these
Forbes intervals was perforated and tested gas on a 3/16 inch choke at a
stabilized rate of 1,628 MCFPD. The shut in pressure is in excess of 5,000 psig.
Gas sales commenced on October 20, 2006. Aspen has a 21% operated working
interest in this well.
The WGU #15-12 well was conventionally drilled to a depth of 6,070 feet.
Production casing was run, the drilling rig was released, and a completion rig
moved in and drilled 130 feet deeper to 6,200 feet with an underbalanced system
in an attempt to find gas pay in the Forbes formation. The open hole interval
tested gas on a 1/2 inch choke at a stabilized rate of 481 MCFPD. Gas sales
commenced on November 2, 2006. Aspen has a 21% operated working interest in this
well.
The Johnson Unit #12 well, located in the Malton Black Butte Field, Tehama
County, California, was drilled to a depth of 4,700 feet and encountered
potential gas pay in several intervals in the Forbes formation. Production
casing was run based on favorable mud log and electric log responses. One of
these Forbes intervals was perforated and tested gas on a 3/16 inch choke at a
stabilized rate of 141 MCFPD. Gas sales commenced on October 27, 2006. Aspen has
a 36% operated working interest in this well.
11
The Sewald #1-1 well, located in the Malton Black Butte Field, Tehama County,
California, was drilled to a depth of 4,900 feet and encountered potential gas
pay in the Forbes formation. Production casing was run based on favorable mud
log and electric log responses. The well is currently waiting on a completion
rig. This was the tenth successful gas well out of eleven attempts by Aspen in
this field. Aspen has a 20.5% non-operated working interest in this well.
The Alston #23-2 well, located in the Rice Creek Gas Field, Tehama County,
California, was drilled to a depth of 5,700 feet and encountered potential gas
pay in the Forbes formation. Several of these Forbes intervals were perforated
and commercial gas production has not been obtained thus far. The well is
currently shut in for further evaluation. Aspen has a 38.75% operated working
interest in this well.
The Pope Bypass #1-5 well, located in the Winters gas field, Yolo County,
California, was recompleted on September 12, 2006, for a gas rate of 650 MCFPD
with a flowing tubing pressure of 1,850 psig and a flowing casing pressure of
1,865 psig. This well was drilled in May 2003 and encountered approximately 70
feet of gas pay in the Winters formation. It has produced approximately 815,000
MCF of gas to date and we believe there are several behind-pipe zones remaining
in the well. Aspen has a 25.4% operated working interest in this well.
12
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
General
-------
The following discussion provides information on the results of operations for
the periods ended September 30, 2006 and 2005 and our financial condition,
liquidity and capital resources as of September 30, 2006 and June 30, 2006. The
financial statements and the notes thereto contain detailed information that
should be referred to in conjunction with this discussion.
The profitability of our operations in any particular accounting period will be
directly related to the realized prices of oil and gas sold, the type and volume
of oil and gas produced and the results of development, exploitation,
acquisition, and exploration activities. The realized prices for natural gas
will fluctuate from one period to another due to regional market conditions and
other factors, while oil prices will be predominantly influenced by world supply
and demand. The aggregate amount of oil and gas produced may fluctuate based on
the success of development and exploitation of oil and gas reserves pursuant to
current reservoir management. Accordingly, our results of operations may
fluctuate from period to period based on the foregoing principal factors, among
others.
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 56 gas wells and have a
non-operated interest in 21 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.
Where possible, we attempt to be the operator of each property in which we
invest. 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 20% of our selling, general
and administrative expenses.
Outlook and Trends
------------------
Total production for the year will depend on the number of wells successfully
completed, the date they commence gas sales, their initial rate of production,
and their production decline rates. Over the past five years we have been able
to replace the majority of our produced reserves. We have also benefited from a
general increase in natural gas prices over the past three years, from a low of
$4.64 per MMBTU average during the second quarter of fiscal 2004 to $10.02 per
MMBTU during the second quarter of fiscal 2006. We also anticipate that the
average price for our product will be in the range of $4.00 to $8.00 per million
British Thermal Unit (MMBTU) for the fiscal year ended June 30, 2007 as compared
to the average gas price of $8.03 received during our 2006 fiscal year. We
received an average of $6.08 per MMBTU for the three months ended September 30,
2006 as compared to an average of $7.26 per MMBTU during the first three months
of our 2006 fiscal year.
Quantitative and Qualitative Disclosure About Risk
--------------------------------------------------
The prices that we receive for the oil and natural gas (including natural gas
liquids) produced are impacted by many factors that are outside of our control.
Historically, these commodity prices have been volatile and we expect them to
remain volatile. Prices for oil and natural gas are affected by changes in
market demands, overall economic activity, weather, pipeline capacity
constraints, inventory storage levels, the world political situation, 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.
13
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. Effective November 1, 2006 through March 31, 2007, we
are contractually obligated to deliver 2,000 MMBTU per day at $10.15 per MMBTU,
and effective December 1, 2006 through March 31, 2007, we are contractually
obligated to deliver an additional 2,000 MMBTU per day at $7.30 per MMBTU to one
of our natural gas purchasers. These contracts were designated as normal sales
contracts.
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, completion and production of prospects, the acquisition
of producing properties, working capital, servicing debt and the payment of
income taxes. During the first three months of our 2007 fiscal year, we used
more than $3.1 million of cash in our operations, investing activities and
financing activities as compared to generating cash of $228,000 during the same
period of our 2006 fiscal year.
We used cash of $(1,822,760) in our operations for the three months ended
September 30, 2006, as compared to $1,315,244 cash provided by our operations
for the three months ended September 30, 2005. This negative change of
approximately $(3.1 million) was due to increased accounts receivable, prepaid
expenses and deposits (a negative change of approximately $1.3 million) and
using our cash to reduce accounts payable and other current liabilities (a
negative change of approximately $1.3 million). Other factors that impacted our
cash flow were a reduction in net income and realized and unrealized gain on
investments that substantially offset the amount received from the sale of that
investment.
Investing activities used cash to increase capitalized oil and gas costs and
office equipment of $1,394,993 and $1,100,995 in the three months ended
September 30, 2006 and 2005. Cash in the current three month period ended
September 30, 2006 was used for lease acquisition, seismic work, intangible
drilling and well workovers ($1,317,931), and equipment of ($89,062). These
expenditures are net of the sale of interests in wells to be drilled charged to
third party investors.
We have a proposed drilling budget for the period October 2006 through December
2006. The budget includes drilling one well and completing three wells in the
Sacramento gas province of northern California. Our share of the estimated costs
to complete this program is set forth in the following table:
Drilling Completion and
Area Wells Costs Equipment Costs Total
---- ----- ----- --------------- -----
West Grimes Field
Colusa County, CA 2 $- $132,000 $132,000
Malton Black Butte
Tehama County, CA 2 85,000 174,000 259,000
----- ------- -------- --------
Total Expenditures 4 $85,000 $306,000 $391,000
===== ======= ======== ========
Our working capital (current assets less current liabilities) at September 30,
2006, was $3,372,472, which reflects an approximate $501,000 decrease from our
working capital at June 30, 2006. Our working capital decreased by 14% during
the first three months of our 2007 fiscal year because of our negative cash flow
of more than $3.1 million and a resulting reduction of current assets by an
amount greater than the reduction in our current liabilities.
14
Because of our working capital reduction (which resulted from our negative cash
flow as described above), our total current assets reduced by approximately $2.4
million from June 30, 2006 through September 30, 2006. This reduction was
partially offset by an increase in our investment in oil and gas properties of
approximately $1.3 million during the quarter (as compared to approximately $1.4
million negative cash flow from investing activities during the quarter).
Notwithstanding the decrease in total assets, our stockholders' equity increased
by approximately $470,000 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 obligations. Based
on national and international concerns, we anticipate that our gas production
will continue to provide us with sufficient cash flow through our current fiscal
year and beyond. As discussed herein, 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.
We believe that internally generated funds will be sufficient to finance our
drilling and operating expenses for the next twelve months. 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.
Results of Operations
---------------------
September 30, 2006 Compared to September 30, 2005
-------------------------------------------------
For the three months ended September 30, 2006, 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 three
months ended September 30, 2006, our oil and gas production increased from
146,445 MMBTU sold to 158,391 MMBTU sold (an increase of approximately 8.2%).
Notwithstanding this increased production, our revenues decreased by
approximately $(114,000) as compared to the comparable period of our 2005 fiscal
year because of:
Decreased price received for our production (an average of $6.08 per MMBTU
during the first three months of our 2007 fiscal year as compared to $7.26
per MMBTU received during that period in 2006); and
Decreased management fees received ($96,103 during fiscal 2007 as compared
to $120,924 during fiscal 2006) because we received less drilling and
completion fees during fiscal 2007 than in fiscal 2006.
Oil and gas production costs increased $120,159, or 169%, for the three months
ended September 30, 2006 and increased $6,658, or 10%, for the three months
ended September 30, 2005. The increase in operating costs is substantially
greater than the 8.2% increase in oil and gas production and can be attributed
to the addition of 5 gross wells, from 51 wells to 56 wells and our percentage
working interests in these wells were somewhat higher than the average of wells
owned at September 30, 2005. The increase was also due to the payment of a full
year of ad valorem taxes in several of the counties where Aspen's gas wells are
located. Equipment rental and water disposal fees increased due to the addition
of compressors and increased water production in our more mature wells.
Additionally, all of the costs for the service companies who perform work on
Aspen's wells increased dramatically during the past twelve months.
Depletion, depreciation and amortization expense increased approximately
$226,000 for the three months ended September 30, 2006. This increase of 89% was
the result of using the approximate same depletion rate as fiscal 2006, but
applying it to a larger full cost pool which resulted in the higher total
depletion taken.
Our general and administrative expenses increased by approximately $266,000 from
that for the same period in our fiscal 2006 (an increase of about 117%) because
of increased audit and accounting fees, officers salaries including a non-cash
charge $31,000 as a result of recognition of additional share-based compensation
expense in accordance with the implementation of FAS 123(R), a non-cash charge
of $23,508 for stock options issued to a Director, and the amortization of
deferred compensation for the initiation of an investor relations service of
$113,000 settled in shares of our common stock in the prior year.
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 three months of fiscal 2006, 2005 and 2004:
15
For the Three Months Ended
------------------------------------------------------------
September 30, 2006 September 30, 2005 September 30, 2004
------------------ ------------------ ------------------
Total Revenues 100.0% 100.0% 100.0%
Oil and Gas Production Costs 17.7% 5.9% 8.2%
-------- ------- --------
Income from Operations 82.3% 94.1% 91.8%
-------- ------- --------
Cost and expenses
Depreciation and depletion 44.5% 21.3% 19.9%
Selling, general and administrative 45.7% 19.0% 21.8%
Interest expense 0.4% 0.0% 0.3%
-------- ------- --------
Total Costs and Expenses 97.8% 40.3% 42.0%
-------- ------- --------
Income Before Income Taxes
and Other Income -8.2% 53.8% 49.8%
Other Income 25.0%
Provision for Income Taxes 8.0% 15.1% 21.4%
-------- ------- --------
Net Income (Loss) 25.1% 38.7% 28.4%
======== ======= ========
To facilitate discussion of our operating results for the three months ended
September 30, 2006 and 2005, we have included the following selected data from
our Condensed Consolidated Statements of Operations:
Comparison of the Fiscal Three
Months Ended September 30, Increase (Decrease)
-------------------------- --------------------------
2006 2005 Amount Percentage
----------- ----------- ----------- -----------
Revenues:
Oil and gas sales $ 962,933 $ 1,062,543 $ (99,610) -9%
Management fees 96,103 120,924 (24,821) -21%
Interest and other 21,415 10,701 10,715 100%
----------- ----------- ----------- -----------
Total Revenues 1,080,451 1,194,168 (113,716) -10%
----------- ----------- ----------- -----------
Cost and Expenses:
Oil and gas production 191,178 71,019 120,159 169%
Depreciation and depletion 480,277 254,336 225,941 89%
General and administrative 493,568 227,116 266,452 117%
Interest expense 4,745 -- 4,745 100%
----------- ----------- ----------- -----------
Total Costs and Expenses 1,169,768 552,471 617,297 112%
----------- ----------- ----------- -----------
Income Before Taxes
and Other Income (89,317) 641,697 (731,013) -114%
Other Income 274,536 -- 274,536 100%
Income Tax Benefit (Provision) 86,000 (180,395) 266,395 -148%
----------- ----------- ----------- -----------
Net Income (Loss) $ 271,219 $ 461,302 $ (190,082) -41%
=========== =========== =========== ===========
16
Total revenue decreased $(113,716) or 10% when comparing the two periods, while
operating and production costs increased $120,159, or 169%.
A significant ratio presented is the percentage of management fees charged to
operated wells versus our general and administrative costs. This ratio coverage
of general and administrative costs decreased from approximately 53% during the
three months ended September 30, 2005 to approximately 20% at September 30,
2006.
Central to the issue of success of the three months operations ended September
30, 2006 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
----------- ----------- -----------
2007
--------------------
1st Quarter $ 962,933 158,391 $ 6.08
----------- ----------- ---------
Year to date 962,933 158,391 6.08
----------- ----------- ---------
2006
--------------------
1st Quarter 1,062,543 146,445 7.26
2nd Quarter 2,018,233 201,371 10.02
3rd Quarter 1,496,427 182,987 8.18
4th Quarter 823,747 141,840 5.81
----------- ----------- ---------
Year to date 5,400,950 672,643 8.03
----------- ----------- ---------
2005
--------------------
1st 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
4th Quarter 919,578 145,500 6.30
----------- ----------- ---------
Year to date 3,853,177 622,000 6.20
----------- ----------- ---------
2004
--------------------
1st 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
----------- ----------- ---------
First Quarter Change
--------------------
2007
--------------------
Amount $ (99,610) $ 11,946 $ (1.18)
Percentage -10% 8% -19%
2006
--------------------
Amount $ 364,990 $ 16,445 $ 1.95
Percentage 52% 13% 37%
(1) Price per MMBTU may not agree with oil and gas sales because of the
inclusion of oil and NGL sales.
17
Oil and gas revenue and volumes sold of our product have shown a general
improvement over the first three months of fiscal 2007 and the twelve months of
fiscal 2006. As the table above notes, revenue has decreased approximately 10%
when comparing the three month periods ended September 30, 2006 and 2005.
Volumes sold increased approximately 8%, while the price received for our
product decreased 16%. The decrease in revenues even though there was an
increase in production volumes was due the 16% decrease in natural gas prices.
Contractual Obligations
-----------------------
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
lease payments are $901 to $934 over the term of the lease, which expires July
31, 2008. Rent expense for the three months ended September 30, 2006 and 2005
was $6,395 and $6,163, respectively.
Effective November 1, 2006 through March 31, 2007, we are contractually
obligated to deliver 2,000 MMBTU per day at $10.15 per MMBTU, and effective
December 1, 2006 through March 31, 2007, an additional 2,000 MMBTU per day at
$7.30 per MMBTU to one of our natural gas purchasers. These contracts were
designated as normal sales contracts.
Critical Accounting Policies and Estimates
------------------------------------------
The Company believes the following accounting policies and estimates are
critical in the preparation of its consolidated financial statements: the
carrying value of its oil and natural gas properties, the accounting for oil and
gas reserves, and the estimate of its asset retirement obligations.
Oil and Gas Properties
----------------------
The Company uses the full cost method of accounting for costs related to its oil
and natural gas properties. Capitalized costs included in the full cost pool are
depleted on an aggregate basis using the units-of-production method.
Depreciation, depletion and amortization is a significant component of oil and
natural gas properties. A change in proved reserves without a corresponding
change in capitalized costs will cause the depletion rate to increase or
decrease.
Both the volume of proved reserves and any estimated future expenditures used
for the depletion calculation are based on estimates such as those described
under "Reserve Estimates" below.
The capitalized costs in the full cost pool are subject to a quarterly ceiling
test that limits such pooled costs to the aggregate of the present value of
future net revenues attributable to proved oil and natural gas reserves
discounted at 10 percent plus the lower of cost or market value of unproved
properties less any associated tax effects. If such capitalized costs exceed the
ceiling, the Company will record a write-down to the extent of such excess as a
non-cash charge to earnings. Any such write-down will reduce earnings in the
period of occurrence and result in lower depreciation and depletion in future
periods. A write-down may not be reversed in future periods, even though higher
oil and natural gas prices may subsequently increase the ceiling.
Changes in oil and natural gas prices have historically had the most significant
impact on the Company's ceiling test. In general, the ceiling is lower when
prices are lower. Even though oil and natural gas prices can be highly volatile
over weeks and even days, the ceiling calculation dictates that prices in effect
as of the last day of the test period be used and held constant. The resulting
valuation is a snapshot as of that day and, thus, is generally not indicative of
a true fair value that would be placed on the Company's reserves by the Company
or by an independent third party. Therefore, the future net revenues associated
with the estimated proved reserves are not based on the Company's assessment of
future prices or costs, but rather are based on prices and costs in effect as of
the end the test period.
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
18
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.
Accounts Receivable
-------------------
Accounts receivable balances are evaluated on a continual basis and allowances
are provided for potentially uncollectible accounts based on management's
estimate of the collectibility 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. At the present time, we believe that we will collect
the full amount of the pre-petition and post-petition receivables from Calpine
Corporation (notwithstanding its bankruptcy petition). We will continue to
monitor this situation and revise our estimates as appropriate.
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 5%. Revisions to the liability could occur due to changes in
well lives, or if federal and state regulators enact new requirements on the
plugging and abandonment of gas wells. In the first quarter, we plugged four
wells and added two resulting in a net decrease to the ARO liability of $43,457.
Accretion expense of $4,903 was recognized during the period ending September
30, 2006.
Deferred Taxes
--------------
Deferred income taxes have been determined in accordance with Statement of
Financial Accounting Standards No. 109, "Accounting for Income Taxes." At
September 30, 2006 the Company recorded income tax expense comprised of a $0
current expense and a deferred tax benefit of $86,000. Projections of future
income taxes and their timing require significant estimates with respect to
future operating results. Accordingly, the net deferred tax liability is
continually re-evaluated and numerous estimates are revised over time. As such,
the net deferred tax liability may change significantly as more information and
data is gathered with respect to such events as changes in commodity prices,
their effect on the estimate of oil and gas reserves, and the depletion of these
long-lived reserves.
19
Off Balance Sheet Arrangements
------------------------------
We have no off balance sheet arrangements and thus no disclosure is required.
Forward Looking Statements
--------------------------
"Safe harbor under the Private Securities Litigation Reform Act of 1995:" Any
statements in this Form 10-QSB that are not historical facts are forward-looking
statements that involve risks and uncertainties. Words such as "estimate,"
"will," "intend," "continue," "target," "expect," "achieve," "strategy,"
"future," "may," "goal(s)," or other comparable words or phrases or the negative
of those words, and other words of similar meaning indicate forward-looking
statements and important factors which could affect actual results.
Forward-looking statements are made based on Management's current expectations
and beliefs concerning future developments and their potential effects upon
Aspen Exploration Corporation. These items are discussed at length in Part I, on
page 25 of Aspen's Form 10-KSB filed with the Securities and Exchange
Commission, under the heading "Factors That May Affect Future Operating Results"
in the section titled "Management's Discussion and Analysis of Financial
Condition or Plan of Operation." No material changes are have been noted as of
the filing of this 10-QSB.
Item 3. CONTROLS AND PROCEDURES
As of September 30, 2006, we have carried out an evaluation under the
supervision of, and with the participation of the Chief Executive Officer, of
the effectiveness of the design and operation of our disclosure controls and
procedures pursuant to Rule 13a-15 under the Securities and Exchange Act of
1934, as amended.
Based on the evaluation as of September 30, 2006, the Chief Executive Officer
(who is also our principal financial officer) has concluded that our disclosure
controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) under the
Securities Exchange Act of 1934) are effective to ensure that the information
required to be disclosed in the reports that we file or submit under the
Securities Exchange Act of 1934 is recorded, processed, summarized and reported
within the time periods specified in SEC rules and forms.
There was no change in our internal control over financial reporting during the
most recently completed calendar quarter that has materially affected, or is
reasonably likely to materially affect, our internal control over financial
reporting.
20
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
The following sets forth the information required by Item 701 of Regulation S-B
with respect to the unregistered sale of equity securities:
On August 11, our Board chairman, R. V. Bailey, exercised options for 50,000
shares of our common stock granted March 14, 2002, at an average price of $0.57
per share. Mr. Bailey paid us $28,500 to exercise his options on the 50,000
shares.
(a) The options were exercised on August 11, 2006, to purchase 50,000 shares of
our common stock.
(b) No underwriter, placement agent, or finder was involved in the transaction.
The Board chairman is an accredited investor.
(c) The total exercise price for the options was $28,500, which was paid in
cash. No underwriting discounts or commission were paid.
(d) We relied on the exemption from registration provided by Section 4(2) and
4(6) under the Securities Act of 1933 for this transaction and Regulation D
for the issuance. 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 (and its advisors) posed, and otherwise understood the
risks of accepting our securities for investment purposes.
(e) The common stock issued in this transaction is not convertible or
exchangeable.
(f) We will use the proceeds for working capital, as well as expenses of
drilling and (if warranted) completing oil and gas wells.
On August 14, an employee surrendered 2,019 mature shares of common stock to
exercise a stock option resulting in the net issue of 14,981 shares. The option
to acquire 17,000 shares was originally granted March 14, 2002, at an exercise
price of $0.57 per share.
(a) The options were exercised on August 14, 2006, to purchase 17,000 shares of
our common stock. The option holder exercised options to acquire 17,000
shares in the cashless exercise which had a value of $9,690 by surrendering
2,019 shares of Aspen's common stock with a fair value based on a ten-day
average bid price immediately prior to the exercise date of $4.80.
(b) No underwriter, placement agent, or finder was involved in the transaction.
The employee is an accredited investor.
(c) The total exercise price for the options was $9,690, which was paid by
surrendering 2,019 shares to purchase 17,000 shares. No underwriting
discounts or commission were paid.
21
(d) We relied on the exemption from registration provided by Section 4(2) under
the Securities Act of 1933 for this transaction and Regulation D for the
issuance. 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 (and its advisors) posed, and otherwise understood the
risks of accepting our securities for investment purposes.
(e) The common stock issued in this transaction is not convertible or
exchangeable.
(f) We received no proceeds from the exercise of this transaction.
Option to Director
------------------
Aspen appointed Kevan B. Hensman a director of Aspen effective September 11,
2006. In connection with that appointment, Aspen granted Mr. Hensman an option
to purchase 10,000 shares of Aspen common stock.
(a) On September 11, 2006, we issued an option to purchase 10,000 shares of
Aspen's common stock to Kevan B. Hensman. The options are exercisable at
$3.70, expire September 11, 2011 and vested immediately.
(b) No underwriters were involved in this transaction.
(c) The stock options were issued in consideration of Mr. Hensman joining the
board of directors and Aspen received no cash therefore.
(d) The transaction was exempt from registration under the Securities Act of
1933, as amended by reason of Section 4(2) and 4(6) of the Securities Act
of 1933.
(e) The options are exercisable to purchase shares of common stock as described
above.
(f) No proceeds were received.
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.
22
Item 6. EXHIBITS
(a) Exhibits
Exhibit No. Document
----------- -----------------------------------------------------------------
31 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002 (Robert A. Cohan, Chief Executive Officer).
32 Certification Pursuant to 18 U.S.C. ss.1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002 (Robert A.
Cohan, Chief Executive Officer).
Other exhibits and schedules are omitted because they are not applicable, not
required or the information is included in the financial statements or notes
thereto.
(b) Reports on Form 8-K
None.
In accordance with the requirements of the Securities Exchange Act of 1934, we
have duly caused this report to be signed on our behalf by the undersigned,
thereunto duly authorized.
ASPEN EXPLORATION CORPORATION
Date: November 13, 2006 /s/ Robert A. Cohan
----------------------------------------
Robert A. Cohan, Chief Executive Officer
and Chief Financial Officer
(principal executive and financial
officer)
23