FORM 10-QSB
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, 2007
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 May 14, 2007
Common stock, $.005 par value 7,259,622
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
March 31, June 30,
2007 2006
------------ ------------
(unaudited)
ASSETS
Current Assets:
Cash and cash equivalents $ 3,179,469 $ 6,466,010
Short-term investments 1,074,937 1,002,527
Accounts and trade receivables 2,562,363 2,119,758
Accounts receivable - related party 1,273 1,273
Other current assets 56,452 356,823
------------ ------------
Total Current Assets 6,874,494 9,946,391
------------ ------------
Property and equipment
Oil and gas property (full cost method) 18,592,790 14,274,642
Support equipment 184,514 122,576
------------ ------------
18,777,304 14,397,218
Accumulated depletion and impairment - full cost pool (7,615,883) (6,118,879)
Accumulated depreciation - support equipment (43,840) (54,710)
------------ ------------
Net property and equipment 11,117,581 8,223,629
------------ ------------
Other assets:
Deposits 263,650 250,000
Deferred income taxes 1,482,500 771,000
------------ ------------
Total other assets 1,746,150 1,021,000
------------ ------------
Total Assets $ 19,738,225 $ 19,191,020
============ ============
(Statement Continues)
The accompanying notes are an integral part of these condensed consolidated financial statements.
2
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)
March 31, June 30,
2007 2006
------------- ------------
(unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable $ 2,510,585 $ 3,823,298
Other current liabilities and accrued expenses 1,089,485 2,187,147
Notes payable - current portion 275,004 --
Asset retirement obligation, current portion 28,000 62,800
------------ ------------
Total Current Liabilities 3,903,074 6,073,245
------------ ------------
Long-term liabilities
Notes payable, net of current portion 660,412 --
Asset retirement obligation, net of current portion 531,280 331,823
Deferred income taxes 3,609,000 2,685,000
------------ ------------
Total Long-Term Liabilities 4,800,692 3,016,823
------------ ------------
Stockholders' Equity:
Common stock, $.005 par value:
Authorized: 50,000,000 shares
Issued and outstanding: At March 31, 2007, 7,159,622 shares
and June 30, 2006, 7,094,641 shares 35,723 35,473
Capital in excess of par value 7,421,172 7,283,914
Retained earnings 3,577,564 2,900,798
Deferred compensation -- (119,233)
------------ ------------
Total Stockholders' Equity 11,034,459 10,100,952
------------ ------------
Total Liabilities and Stockholders' Equity $ 19,738,225 $ 19,191,020
============ ============
The accompanying notes are an integral part of these condensed 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,
------------------------------ ------------------------------
2007 2006 2007 2006
----------- ----------- ----------- -----------
Revenues:
Oil and gas sales $ 1,344,791 $ 1,496,427 $ 3,361,563 $ 4,576,203
Management fees 154,876 92,682 386,818 295,768
----------- ----------- ----------- -----------
Total Revenues 1,499,667 1,589,109 3,748,381 4,871,971
----------- ----------- ----------- -----------
Expenses:
Oil and gas production 247,292 164,796 576,534 356,966
Accretion, and depreciation,
depletion and amortization 548,176 450,000 1,528,330 1,159,040
Selling, general and administrative 266,728 205,592 1,047,065 668,654
----------- ----------- ----------- -----------
Total Operating Expenses 1,062,196 820,388 3,151,929 2,184,660
----------- ----------- ----------- -----------
Income from Operations 437,471 768,721 596,452 2,687,311
Other Income (Expenses)
Interest and other income 8,422 23,612 44,308 43,641
Interest and other expenses (10,948) (22) (15,716) (22)
Gain on investments 194,400 -- 685,096 --
Gain on sale of equipment -- -- 12,000 --
----------- ----------- ----------- -----------
Total Other Income (Expenses) 191,874 23,590 725,688 43,619
----------- ----------- ----------- -----------
Income Before Income Taxes 629,345 792,311 1,322,140 2,730,930
Provision for Income Taxes (212,393) (361,955) (287,393) (934,009)
----------- ----------- ----------- -----------
Net Income $ 416,952 $ 430,356 $ 1,034,747 $ 1,796,921
=========== =========== =========== ===========
Basic Net Income Per Share $ 0.06 $ 0.06 $ 0.14 $ 0.27
=========== =========== =========== ===========
Diluted Net Income Per Share $ 0.06 $ 0.06 $ 0.14 $ 0.24
=========== =========== =========== ===========
Dividends Per Share $ -- $ -- $ 0.05 $-
=========== =========== =========== ===========
Weighted Average Number of
Common Shares Outstanding:
Basic 7,149,735 6,775,715 7,149,735 6,762,712
=========== =========== =========== ===========
Diluted 7,326,684 7,360,966 7,326,684 7,347,290
=========== =========== =========== ===========
The accompanying notes are an integral part of these condensed consolidated financial statements.
4
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended March 31,
----------------------------------
2007 2006
----------- -----------
Cash Flows from Operating Activities:
-------------------------------------
Net income $ 1,034,747 $ 1,796,921
Adjustments to reconcile net income to net cash provided
by operating activities:
Accretion and depreciation, depletion, and amortization 1,528,330 1,159,040
Deferred income taxes 212,500 338,342
Amortization of deferred compensation 119,233 43,904
Compensation expense related to stock options granted 109,008 --
Realized (gain) on investments (373,869) --
(Gain) on sale of vehicle (12,000) --
Unrealized (gain) on investments (311,227) --
Proceeds from sale of investments 612,686 --
Changes in assets and liabilities:
Increase in current assets other than cash, cash equivalents,
and short-term investments (155,884) (3,433,420)
Increase (decrease) in liabilities other than notes payable (2,410,375) 6,986,038
----------- -----------
Net Cash Provided by Operating Activities 353,149 6,890,825
----------- -----------
Cash Flows from Investing Activities:
-------------------------------------
Additions to oil and gas properties (2,718,200) (3,234,819)
Producing oil and gas properties purchased (1,075,000) --
Additions to property and equipment (89,425) (8,500)
Sale of property and equipment 12,000 2,000
----------- -----------
Net Cash (Used) in Investing Activities (3,870,625) (3,241,319)
----------- -----------
Cash Flows from Financing Activities:
-------------------------------------
Proceeds from exercise of stock options 28,500 --
Proceeds from issuance of common stock -- 36,499
Proceeds from issuance of long-term debt 600,000 --
Payment of long-term debt (39,584) --
Payment of cash dividends (357,981) --
----------- -----------
Net Cash Provided by Financing Activities 230,935 36,499
----------- -----------
Net Increase/(Decrease) in Cash and Cash Equivalents (3,286,541) 3,686,005
Cash and Cash Equivalents, beginning of year 6,466,010 3,430,146
----------- -----------
Cash and Cash Equivalents, end of year $ 3,179,469 $ 7,116,151
=========== ===========
Other Information:
------------------
Interest paid $ 15,716 $-
=========== ===========
Income taxes paid $ 800 $ 372,408
=========== ===========
Non-Cash Investing and Financing Activities:
--------------------------------------------
Asset retirement obligation $ 149,948 $ 26,000
=========== ===========
Notes payable assumed $ 375,000 $ --
=========== ===========
Stock issued for deferred consulting services $ -- $ 64,000
=========== ===========
The accompanying notes are an integral part of these condensed consolidated financial statements.
5
ASPEN EXPLORATION CORPORATION
Notes to Condensed Consolidated Financial Statements
(Unaudited)
March 31, 2007
NOTE 1 - BASIS OF PRESENTATION
---------------------
The accompanying condensed consolidated financial statements of Aspen
Exploration Corporation (the Company) are unaudited. However, in the opinion of
management, the accompanying condensed consolidated financial statements reflect
all adjustments, consisting of only normal recurring adjustments, necessary for
fair presentation for the interim period.
The consolidated 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
consolidated 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 consolidated
financial statements be read in conjunction with the consolidated 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
-------------------------------
Use of Estimates
----------------
The preparation of consolidated 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 consolidated 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.
Recent Accounting Pronouncements
--------------------------------
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 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.
6
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 February 2007, the FASB issued SFAS No. 159, The Fair Value Option for
Financial Assets and Financial Liabilities, which permits an entity to measure
certain financial assets and financial liabilities at fair value. The objective
of SFAS No. 159 is to improve financial reporting by allowing entities to
mitigate volatility in reported earnings caused by the measurement of related
assets and liabilities using different attributes, without having to apply
complex hedge accounting provisions. Under SFAS No. 159, entities that elect the
fair value option (by instrument) will report unrealized gains and losses in
earnings at each subsequent reporting date. The fair value option election is
irrevocable, unless a new election date occurs. SFAS No. 159 establishes
presentation and disclosure requirements to help financial statement users
understand the effect of the entity's election on its earnings, but does not
eliminate disclosure requirements of other accounting standards. Assets and
liabilities that are measured at fair value must be displayed on the face of the
balance sheet. This statement is effective beginning January 1, 2008 and we are
evaluating this pronouncement.
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 and year-to-date periods ended March 31, 2007
include: (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.
7
NOTE 3 - SHARE-BASED COMPENSATION (Continued)
------------------------
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.
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 June 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 three
and nine months ended March 31, 2007 of $27,500, and $109,008, respectively, 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,
or year-to-date periods ended March 31, 2007.
Prior to July 1, 2006, the Company accounted for these plans 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 plans 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 prior to the adoption of SFAS No. 123(R):
Nine Months Ended
March 31, 2006
--------------
Net income, as reported $ 1,796,921
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 (244,595)
-------------
Pro forma net income $ 1,552,326
=============
Basic Earnings Per Share
As Reported 0.27
Pro Forma 0.23
Diluted Earnings Per Share
As Reported 0.24
Pro Forma 0.21
8
NOTE 3 - SHARE-BASED COMPENSATION (Continued)
------------------------
On August 11, 2006, the Board Chairman ("Mr. Bailey") 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 2,019
shares equal to the exercise price.
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 of fiscal year 2007.
A summary of option activity under the plans as of March 31, 2007, and changes
during the nine 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 March 31, 2007 330,000 $ 1.75 2.13 $554,400
======== ======== ==== ========
Exercisable at March 31, 2007 223,334 $ 1.69 1.37 $388,601
======== ======== ==== ========
The grant-date fair value of options granted during the period was $23,508. The
total intrinsic value of options exercised during the period was $185,845.
A summary of the status of the Company's nonvested shares underlying the options
outstanding as of March 31, 2007, and changes during the nine months ended March
31, 2007, is presented below:
Weighted-
Average
Number of Grant-Date
Shares Fair Value
---------- ----------
Nonvested at June 30, 2006 256,666 $ 1.85
Granted --
Vested (106,667) 1.69
Forfeited (43,333) 2.67
--------
Nonvested at March 31, 2007 106,666 $ 1.68
======== ========
The total compensation cost related to nonvested awards not yet recognized on
March 31, 2007 is approximately $16,000 net of tax, and the weighted average
period over which this cost is expected to be recognized is 1.3 years. The total
fair value of options vested during the period was $180,267.
9
NOTE 3 - SHARE-BASED COMPENSATION (Continued)
------------------------
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 1.38 $ 0.57 100,000 $ .57
2.67 170,000 2.76 2.67 113,334 2.67
3.70 10,000 4.45 3.70 10,000 3.70
------- -------- ----- ------- --------
330,000 2.18 $ 1.75 223,334 $ 1.78
======= ======== ===== ======= ========
(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:
Nine Months Ending March 31,
---------------------------------------------------------------------------------------
2007 2006
----------------------------------------- ------------------------------------------
Net Per Share Net Per Share
Income Shares Amount Income Shares Amount
----------- ---------- ---------- ------------ ---------- -----------
Basic Earnings Per Share:
Net income and
share amounts $1,034,747 7,149,735 $0.14 $1,796,921 6,762,712 $0.27
Effect of Dilutive Securities:
Stock Options - 176,950 - - 584,578 (0.03)
----------- ---------- --------- ---------- ---------- --------
Diluted Earnings Per Share:
Net income and assumed
share conversion $1,034,747 7,326,685 $0.14 $1,796,921 7,347,290 $0.24
=========== ========== ========= =========== ========== ========
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 is 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.
10
NOTE 6 - CONTINGENCIES AND DRILLING COMMITMENTS
--------------------------------------
In January 2007 Aspen entered into a venture to explore for gold in Alaska with
Hemis Corporation, with offices in Las Vegas, Nevada, whereby Hemis will provide
all funding and be the operator of a venture to carry out permit acquisition and
exploration for commercial quantities of gold. If such deposits are found, Hemis
intends to produce and sell the gold as well as any other commercially valuable
minerals that may occur with the gold. Hemis has commenced work to obtain
permits for the project.
At signing Aspen was paid $50,000 and will be paid this amount on each
anniversary of the agreement so long as Hemis continues work in the area. The
payment ceases when and if production begins. Aspen retained a 5% production
royalty, which may be taken in kind or in cash as Aspen prefers. Aspen provided
to Hemis exploration data assembled and gathered by Aspen over a period of
several years in the 1980's. Permits will be required before Hemis may commence
work and there is no assurance such needed permits will be issued by the State
of Alaska or by the Federal government.
The Company and Enserco Energy, Inc. entered into a "Contract for Sale and
Purchase of Natural Gas" dated November 1, 2005. Aspen and Enserco have
continuously renewed this contract since then. On January 30, 2007 Aspen agreed
to sell and Enserco 2,000 MMBTU (million BTUs or British Thermal Units) of gas
per day at a fixed price of $7.65 per MMBTU less transportation and other
expenses during the period April 1, 2007 through October 31, 2007. On April 12,
2007, the Company entered into a subsequent renewal of the gas sales contract to
sell Enserco 2,000 MMBTU of gas per day at a fixed price of $9.02 per MMBTU less
transportation and other expenses during the period from November 1, 2007
through March 31, 2008.
Aspen's sales of natural gas under the Enserco Contract qualify for the "Normal
Purchases and Normal Sales" exception in paragraph 10(b) of FAS 133. The Enserco
Contract contains net settlement provisions should the Company fail to deliver
natural gas when required under the Enserco Contract. Those provisions are
mutual and establish the sole and exclusive remedy of the parties in the event
of a breach of a firm obligation to deliver or receive natural gas. The
provisions are summarized as follows:
(i) In the event of a breach by Aspen on any day, Aspen would be required
to pay Enserco an amount equal to the positive difference, if any,
between the purchase price and transportation costs paid by Enserco
purchasing replacement natural gas and the amount of Aspen's default;
or
(ii) In the event of a breach by Enserco on any day, Enserco must pay to
Aspen any losses incurred by Aspen after attempting the resale of the
natural gas; or
(iii) In the event that Enserco has used commercially reasonable efforts to
replace the natural gas not delivered by Aspen, or Aspen has used
commercially reasonable efforts to sell the undelivered natural gas to
a third party and no such replacement or sale is available, the sole
and exclusive remedy of the performing party shall be any unfavorable
difference between the contract price and the spot price, adjusted for
transportation.
The natures of the penalties are based on the current market prices and
therefore are variable. Aspen has met its obligations under the contract since
the inception of the contract, and expects to continue to have sufficient gas
available for delivery to fulfill current contractual delivery quantity
obligations from anticipated production from the Company's California fields.
11
The Company has the following commitments for drilling and completion for the
period April 2007 through June 2007:
Drilling Completion and
Area Wells Costs Equipment Costs Total
-------------------------------- ---------------- ---------------- ---------------- --------------
Poplar Field Various
Roosevelt County, MT Recompletions $- $125,000 $125,000
West Grimes Field
Colusa County, CA 3 490,000 280,000 770,000
Kirk Field
Colusa County, CA 1 306,000 183,000 489,000
---------------- --------------- ------------- ------------
Total Expenditures 4 $796,000 $588,000 $1,384,000
================ =============== ============= ============
NOTE 7 - DIVIDENDS
----------
On November 8, 2006, the Company declared a cash dividend in the amount of $0.05
per share. The total of $357,981 was paid to the shareholders on December 6,
2006, as determined by shareholders of record as of November 20, 2006.
NOTE 8 - PROPERTY ACQUISITIONS
---------------------
In February 2007, Aspen purchased a working interest in certain oil producing
assets encompassing 22,600 acres in the East Poplar Unit and the Northwest
Poplar Field in Roosevelt County, Montana located in the Williston Basin. Aspen
acquired its interest from Nautilus Poplar, LLC, an unaffiliated entity, on the
same day that Nautilus Poplar LLC acquired the assets from Ballard Petroleum
Holdings, Inc., also an unaffiliated entity. The Unit and Field contain a total
of 33 producing oil wells, and 7 salt-water disposal wells. Current production
is 230 gross BOPD from the Charles "B" reservoir. The average net revenue
interest that Nautilus Poplar LLC acquired (before its conveyance to Aspen) is
greater than 80%, and Aspen's interest in revenues from the Poplar Field will
remain at 12.5% of the total interest acquired by Nautilus (about a 10% net
revenue interest based on an average 80% NRI) until Aspen receives a return of
110% of its investment. Thereafter, Aspen's interest will be reduced to 10% of
that acquired by Nautilus (approximately an 8.0% net revenue interest to Aspen).
The crude oil is 40 degrees API sweet and is readily marketed at the lease
boundary. All produced water is disposed within the Unit boundary.
Aspen's participation in the acquisition will provide the Company with
diversification into long-lived oil reserves. There is also upside reserve
potential via increased water disposal capacity, re-activation of old wells,
water shut off techniques, behind-pipe potential in the Charles A, B, & C, and
drilling potential in the Mission Canyon and Nisku. This acquisition also
provides ownership in 3-D seismic data over 22,600 acres. This acquisition is
not expected to generate any significant cash flow for Aspen for the first two
years.
Aspen will pay 12.5% of the costs for a 10% working interest in the project.
During the first year, Aspen will also receive 12.5% of the net revenues (after
deduction for royalties, taxes, operating expenses, etc.) until 110% payout, at
which time Aspen's working interest reverts to 10%. After the first year, even
if 110% payout has not occurred, Aspen will only pay 10% of the costs and
receive 12.5% of the net revenues until 110% payout. After 110% payout, Aspen
will have a 10% working interest and receive 10% of the net revenues. The
initial cost to Aspen for its 12.5% before payout working interest (including
its share of the acquisition costs) was approximately $1,450,000, which is
approximately $1,075,000 after deduction of $375,000 (12.5% of the $3,000,000
loan proceeds obtained by Nautilus in connection with the purchase), with an
additional $400,000 of anticipated capital expenditures during the first year.
Aspen funded its participation in this project with a combination of bank debt
($600,000, discussed in Note 9, below), cash on hand and the sale of
approximately 100,000 shares of UR Energy stock (which yielded about $330,000).
Closing of this acquisition occurred on February 13, 2007.
NOTE 9 - LONG-TERM AND SHORT-TERM OBLIGATIONS
------------------------------------
Long-term debt
In January 2007, we borrowed $600,000 from Wells Fargo Bank, NA pursuant to a
promissory note payable over thirty-six months to partially finance the
acquisition of the Poplar Field discussed in Note 8. Interest on the note is
charged at LIBOR plus 2.25%. We subsequently entered into an interest rate swap
12
agreement with Wells Fargo Bank, which fixes the interest rate on the note at
8.10%. Principal of $16,667 plus interest payments are due monthly beginning
February 15, 2007 and continuing to January 15, 2010. Collateral consists of a
blanket filing on Accounts Receivables. At March 31, 2007 the outstanding
balance on the note was $566,666, of which $200,004 is classified as current.
The Wells Fargo note contains restrictive covenants which, among other things,
requires us to maintain a certain "Net Worth" defined as total stockholder's
equity of not less that $9,000,000 at any time, net income after taxes not less
than $1,000 on an annual basis and an EBITDA ratio, as defined.
Short-term debt
In February 2007, as part of the Poplar acquisition, Aspen agreed to be
responsible for 12.5% of a $3,000,000 loan obtained by Nautilus in connection
with the purchase of the Poplar Field assets. Nautilus Poplar, LLC obtained the
loan from the Jonah Bank of Wyoming, as lender. Aspen's share of this loan is
$375,000 plus interest at a rate of 9.0%, and Aspen is subject to the repayment
schedule that Nautilus Poplar negotiated and to the other terms and conditions
of the loan agreement as fully as if Aspen were a party to the loan agreement.
Aspen's share of principal payments of $6,250 plus interest are due monthly
through February 25, 2009. At March 31, 2007, the outstanding balance was
$368,750, of which $75,000 is classified as current.
NOTE 10 - SUBSEQUENT EVENTS
-----------------
On April 12, 2007, the Company entered into a renewal of its gas sales contract
with Enserco Energy, Inc. as described above in Note 6.
On April 9, 2007 Aspen's President and CEO, Mr. Cohan, exercised options to
purchase 100,000 shares at a price of $0.57 each, for total cash consideration
of $57,000.
13
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 March 31, 2007 and 2006 and our financial condition, liquidity
and capital resources as of March 31, 2007 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, and the other factors set forth in this
report and in our report on Form 10-KSB for the year ended June 30, 2006. 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 in California, own
non-operating interests in an additional 20 gas wells in California and
approximately 33 oil wells in Montana.
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 in California. 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 58% and 37% of
our selling, general and administrative expenses for the three and nine-month
periods ended March 31, 2007, respectively.
Outlook and Trends
------------------
Total production for the year depends on a variety of factors set forth herein
and in our Form 10-KSB for the year ended June 30, 2006. Over the past five
years, through our exploration and development activities and property
acquisitions, the Company has been able to increase our oil and gas reserves
notwithstanding our production. Since our 2003 fiscal year, only at June 30,
2005, were our reserves at year-end less than our reserves at the previous
year-end.
We have entered into contracts with Enserco Energy, Inc. to sell about 30% of
our production from April 1, 2007 through March 31, 2008. We also anticipate
that the average price for our product will be in the range of $4.00 to $9.00
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 $7.75 per MMBTU for the three months ended March
31, 2007 as compared to an average of $8.18 per MMBTU during the third quarter
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
14
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.
To manage commercial risk, we may use financial tools to hedge the price we will
receive for our product. The primary purpose of hedging is to provide adequate
return on our investments, grow our reserves while leaving as much commodity
price upside as possible. We have done so through a contract with Enserco
Energy, Inc., since November 1, 2005. Under the current renewal of that
contract, we are contractually obligated to deliver 2,000 MMBTU per day at $7.65
per MMBTU through October 31, 2007, and then $9.02 per MMBTU through March 31,
2008. 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, although during the quarter ended March 31, 2007, we also
borrowed $600,000 to purchase an interest in the Poplar Field and became
obligated for an additional $375,000 indebtedness.
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 nine months of our 2007 fiscal year, we used more than $3.2
million of cash in our operations, investing activities and financing activities
as compared to those activities generating more than $3.6 million during the
same period of our 2006 fiscal year.
We generated cash of $353,149 from operations for the nine months ended March
31, 2007, as compared to $6,890,825 cash generated from operating activities for
the nine months ended March 31, 2006. This negative change of approximately $6.5
million was due to a number of factors, including a reduction of our net income
of approximately $762,000 (as discussed below in results of operations), and a
use of cash to retire current liabilities (which were more than $6 million at
June 30, 2006 as compared to less than $4 million at March 31, 2007). Our
current liabilities decreased by about $2.2 million during the 2007 period as
compared to an increase in current liabilities of approximately $6.9 million
during the 2006 period.
Investing activities used cash to increase capitalized oil and gas costs and
office equipment of $3.9 million during the first nine months of 2007 as
compared to $3.2 million in the nine months ended March 31, 2006. Cash in the
current nine month period ended March 31, 2007 was used for oil and gas property
acquisition ($1.01 million), lease acquisition, seismic work, intangible
drilling and well workovers and equipment ($2.7 million), and support equipment
of ($89,000). 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 April 2007 through June 2007.
The budget includes drilling four wells in California and re-completing /
repairing several wells in Montana. 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
------------------------------ ---------------- ---------------- ----------------- -------------
Poplar Field Various
Roosevelt County, MT Recompletions $ - $125,000 $ 125,000
West Grimes Field 3 490,000 280,000 770,000
Colusa County, CA
Kirk Field
Colusa County, CA 1 306,000 183,000 489,000
---------------- ------------ ------------- -------------
Total Expenditures 4 $796,000 $588,000 $1,384,000
================ ============ ============= =============
15
Our working capital (current assets less current liabilities) at March 31, 2007,
was $2.97 million, which reflects an approximate $902,000 decrease from our
working capital of approximately $3.9 million at June 30, 2006. Our working
capital decreased during the first nine months of our 2007 fiscal year because
of our negative cash flow of more than $3.9 million from investing activities
and a significant use of cash to reduce our current liabilities.
We anticipate that our working capital and anticipated cash flow from operations
and future successful drilling activities will be sufficient to finance our
drilling and operating expenses for the next twelve months and to pay our other
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.
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
---------------------
March 31, 2007 Compared to March 31, 2006
-----------------------------------------
In general, our operations during 2007 have been adversely affected by reduced
production and average prices received for our production, together with
increasing costs of production and accretion, depletion, depreciation, and
amortization, and increased general and administrative expenses. Aspen is aware
of these changes, but believes that some of the negative trend in cash flow is
temporary as a result of the addition of our Poplar Field properties acquired in
the current quarter. As noted, oil and gas prices are subject to national and
international pressures, and Aspen has no control over those prices.
For the nine months and three months ended March 31, 2007, our operations
continued to be focused on the production of oil and gas, and the acquisition of
producing oil and gas properties in California and Montana. Our oil and gas
production decreased from 531,000 MMBTU sold during the first nine months of
March 31, 2006, to 488,000 MMBTU sold during the same period in 2007 (a decrease
of approximately 8%). As a result of our decreased production and decreased
prices during the first nine months of our 2007 fiscal year ($6.89 per MMBTU
during 2007 as compared to $8.62 per MMBTU during the same period in 2006), our
revenues from oil and gas sales decreased during the 2007 period by
approximately $1.2 million from approximately $4.6 million (2006) to
approximately $3.4 million (2007), and decreased during the three month periods
from $1,496,427 (2006) to $1,344,791 (2007). A comparison of the three month
period ending March 31, 2007 to the same period in 2006 similarly results in a
decrease in production of (5%), a decrease in price per MMBTU of (5%), and a
decrease in revenue of (10%).
Oil and gas production costs increased approximately 62% and 50% in the nine and
three months ended March 31, 2007, respectively, as compared to the same periods
in 2006, from approximately $357,000 to more than $577,000, and during the three
month periods from $164,796 (2006) to $247,292 (2007). The increase can be
attributed to the addition of 5 gross operated gas 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 March 31, 2006. The increase was also due to
the addition of 33 producing oil wells and 7 saltwater disposal wells in Montana
as well as the payment of a full year of ad valorem taxes in several of the
California 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 32%, from
approximately $1,159,000 for the nine months ended March 31, 2006 as compared to
more than $1,528,000 during the 2007 period, and during the three month periods
from $450,000 (2006) to $548,176 (2007). This increase 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.
16
Our general and administrative expenses increased 57%, from approximately
$669,000 during the nine months ended March 31, 2006 to approximately $1,047,000
during the 2007 period because of increased audit and accounting fees, officers
salaries including a non-cash charge of $85,500 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 $23,500 for stock options
issued to a Director, and the amortization of deferred compensation for the
initiation of an investor relations service of $119,233 settled in shares of our
common stock in the prior year. Our general and administrative expenses
increased 30%, from approximately $205,592 during the three months ended March
31, 2006 to approximately $266,728 during the 2007 period for the same reasons.
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 2007, 2006, and 2005:
For the Nine Months Ended
--------------------------------------------------------------------
March 31, 2007 March 31, 2006 March 31, 2005
-------------------- ------------------- -------------------
Total Revenues 100.0% 100.0% 100.0%
Oil and Gas Production Costs 15.4% 7.3% 8.6%
-------------------- ------------------- -------------------
Gross Operating Profit 84.6% 92.7% 91.4%
-------------------- ------------------- -------------------
Expenses
Depreciation and depletion 40.8% 23.8% 15.0%
Selling, general and administrative 27.9% 13.7% 18.1%
-------------------- ------------------- -------------------
Total operating expenses 84.1% 44.8% 33.1%
-------------------- ------------------- -------------------
Income from operations 15.9% 55.2% 58.3%
Other Income (expenses) 19.4% 0.9% 0.0%
Provision for Income Taxes 7.7% 19.2% 13.9%
-------------------- ------------------- -------------------
Net Income (Loss) 27.6% 36.9% 44.4%
==================== =================== ===================
17
To facilitate discussion of our operating results for the nine months ended
March 31, 2007 and 2006, 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)
---------------------------------- --------------------------------
2007 2006 Amount Percentage
------------- ------------ ----------- -----------
Revenues:
Oil and gas sales $ 3,361,563 $ 4,576,203 $(1,214,640) -27%
Management fees 386,818 295,768 91,050 31%
----------- ----------- ----------- -----------
Total Revenues 3,748,381 4,871,971 (1,123,590) -23%
----------- ----------- ----------- -----------
Cost and Expenses:
Oil and gas production 576,534 356,966 219,568 62%
Depreciation and depletion 1,528,330 1,159,040 369,290 32%
General and administrative 1,047,065 668,654 378,411 57%
----------- ----------- ----------- -----------
Total Costs and Expenses 3,151,929 2,184,660 967,269 44%
----------- ----------- ----------- -----------
Operating Income 596,452 2,687,311 (2,090,859) -78%
Other income (expenses) 725,688 43,619 682,069 1564%
Income Tax Benefit (Provision) (287,393) (934,009) 646,616 -69%
----------- ----------- ----------- -----------
Net Income (Loss) $ 1,034,747 $ 1,796,921 $ (762,175) -42%
=========== =========== =========== ===========
Total revenue decreased $1.1 million or 23% when comparing the two periods,
while operating and production costs increased $967,000, or 44%.
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 44% during the
nine months ended March 31, 2006 to approximately 37% at March 31, 2007.
18
Central to the issue of success of the nine months operations ended March 31,
2007 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
2nd Quarter 1,053,839 156,002 6.76
3rd Quarter 1,344,791 173,623 7.75
----------------- ----------------- ------------------
Year to date 3,361,563 488,016 6.89
----------------- ----------------- ------------------
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
----------------- ----------------- ------------------
Third Quarter Change
----------------------
2007
----------------------
Amount $ (151,636) $ (9,364) $ (0.43)
Percentage -10% -5% -5%
2006
----------------------
Amount $392,740 $13,837 $1.66
Percentage 35% 8% 26%
(1) Price per MMBTU may not agree with oil and gas sales because of the
inclusion of oil and NGL sales.
19
Oil and gas revenue and volumes sold of our product have shown a general
decrease over the first nine months of fiscal 2007. As the table above notes,
revenue has decreased approximately 27% when comparing the nine-month periods
ended March 31, 2007 and 2006. Volumes sold decreased approximately 8%, while
the price received for our product decreased 19%.
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 nine months ended March 31, 2007 and 2006 was
$19,778 and $24,372, respectively.
Effective November 1, 2006 through March 31, 2007, we were contractually
obligated to deliver 2,000 MMBTU per day at $10.15 per MMBTU, effective December
1, 2006 through March 31, 2007, we were contractually obligated to deliver an
additional 2,000 MMBTU per day at $7.30 per MMBTU, effective April 1, 2007
through October 31, 2007, we are contractually obligated to deliver 2,000 MMBTU
per day at $7.65 per MMBTU, and effective November 1, 2007 through March 31,
2008, we are contractually obligated to deliver 2,000 MMBTU per day at $9.02 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, but does not impact cash flow. 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. Aspen has not
recognized any write-downs of the full cost pool during the first nine months of
2007 or the comparable period in 2006.
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 of the test period.
20
Other Developments
------------------
Subsequent to the quarter ending March 31, 2007, the Emigh #34-1 well, located
in the Denverton Creek Field, Solano County, California, was deepened from a
depth of 10,200 feet to 10,761 feet, and encountered potential gas pay in the
Third Starkey and Petersen formations. A production liner was run based on
favorable mud log and electric log responses. Aspen has a 45% operated working
interest in this well. The well is currently waiting on a completion rig.
In addition, the WGU #14-10 well, located in the West Grimes Gas Field, Colusa
County, California, was directionally drilled to a depth of 8,460 feet (7,974
feet TVD) and encountered encouraging mud log shows and electric log responses
in several intervals in the Forbes formation. Production casing was run and the
well is currently waiting on a completion rig. Aspen has a 21% operated working
interest in this well.
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.
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 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; however, no allowance is recorded for the period ending March 31,
2007, as all receivables are expected to be collected in full.
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.
21
Deferred Taxes
--------------
Deferred income taxes have been determined in accordance with Statement of
Financial Accounting Standards No. 109, "Accounting for Income Taxes." For the
period ended March 31, 2007 the Company recorded income tax expense of $287,000.
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.
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 March 31, 2007, 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 March 31, 2007, 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 fiscal quarter that has materially affected, or is
reasonably likely to materially affect, our internal control over financial
reporting.
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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, 2006, 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, 2006, 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.
23
(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.
On April 9, 2007, President and CEO, Robert Cohan, exercised options for 100,000
shares of our common stock granted March 14, 2002, at an average price of $0.57
per share. Mr. Cohan paid $57,000 to exercise his options on the 100,000 shares.
(a) The options were exercised on April 9, 2007, to purchase 100,000 shares
of our common stock.
(b) No underwriter, placement agent, or finder was involved in the
transaction. Mr. Cohan is an accredited investor.
(c) The total exercise price for the options was $57,000, 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.
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.
24
(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.
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Item 6. 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.
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: May 14, 2007 /s/ Robert A. Cohan
--------------------------------------------
Robert A. Cohan, Chief Executive Officer and
Chief Financial Officer
(principal executive and financial officer)
26