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, 2005
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________ to ________
Commission File Number 0-9494
ASPEN EXPLORATION CORPORATION
-----------------------------------------------
(Exact Name of Aspen as Specified in its Charter)
Delaware 84-0811316
-------- ----------
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
Suite 208, 2050 S. Oneida St.,
Denver, Colorado 80224-2426
---------------- ----------
(Address of Principal Executive Offices) (Zip Code)
Issuer's telephone number: (303) 639-9860
Indicate by check mark whether Aspen (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that Aspen was required to file
such reports), and (2) has been subject to such filing requirements for the past
90 days.
Yes [ X ] No [ ]
Indicate 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, 2005
----- --------------------------------
Common stock, $.005 par value 6,758,308
Transitional small business disclosure format: ___ Yes XX No
-----
Part One. FINANCIAL INFORMATION
Item 1. Financial Statements
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, June 30,
2005 2005
---- ----
Current Assets:
Cash and cash equivalents, including $3,410,281 and
$2,812,971 of invested cashat September 30, 2005 and
June 30, 2005 respectively .......................................... $ 3,658,625 $ 3,430,146
Accounts & trade receivables ........................................ 791,211 614,720
Accounts receivable, related party .................................. 36,845 13,000
Prepaid expenses..................................................... 13,088 15,422
Precious metals ..................................................... 18,823 18,823
------------ ------------
Total current assets ........................................... 4,518,592 4,092,111
------------ ------------
Investment in oil and gas properties, at cost (full cost method of
accounting) ......................................................... 10,799,378 9,670,383
Less accumulated depletion and valuation allowance .................. (4,837,090) (4,587,090)
------------ ------------
5,962,288 5,083,293
------------ ------------
Property and equipment, at cost:
Furniture, fixtures and vehicles .................................... 114,076 154,819
Less accumulated depreciation ....................................... (39,637) (74,044)
------------ ------------
74,439 80,775
------------ ------------
TOTAL ASSETS ................................................... $ 10,555,319 $ 9,256,179
============ ============
(Statement Continues)
See notes to Consolidated Financial Statements
3
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
September 30, June 30,
2005 2005
---- ----
Current liabilities:
Accounts payable and accrued expenses ................................. $ 977,105 $ 655,190
Accounts payable - related party (Note 6) ............................. 73,767 103,233
Advances from joint interest owners ................................... 1,035,221 710,477
Asset retirement obligation (Note 3) .................................. 13,826 13,826
------------ ------------
Total current liabilities 2,099,919 1,482,726
------------ ------------
Asset retirement obligation, net of current portion (Note 3) .......... 108,384 82,384
Deferred income taxes (Note 9) ........................................ 1,195,883 1,015,488
------------ ------------
Total long term liabilities ........................................... 1,304,267 1,097,872
------------ ------------
Total liabilities ..................................................... 3,404,186 2,580,598
------------ ------------
Stockholders' equity:
(Notes 1 and 5):
Common stock, $.005 par value:
Authorized: 50,000,000 shares
Issued and outstanding: At September 30, 2005,
6,758,308 shares and June 30, 2005, 6,733,308 ..................... 33,791 33,666
Capital in excess of par value ........................................ 6,742,446 6,728,321
Accumulated retained earnings (deficit) ............................... 392,133 (69,169)
Deferred compensation ................................................. (17,237) (17,237)
------------ ------------
Total stockholders' equity ............................................ 7,151,133 6,675,581
------------ ------------
Total liabilities and stockholders' equity ............................ $ 10,555,319 $ 9,256,179
============ ============
See Notes to Consolidated Financial Statements
4
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended
September 30,
2005 2004
---- ----
Revenues:
Oil and gas .................................................... $1,062,543 $ 697,553
Management fees ................................................ 120,924 82,057
---------- ----------
Total Revenues ................................................... 1,183,467 779,610
---------- ----------
Costs and expenses:
Oil and gas production ......................................... 71,019 64,361
Depreciation, depletion and amortization ....................... 254,336 156,000
Selling, general and administrative ............................ 227,116 171,104
---------- ----------
Total Costs and Expenses ......................................... 552,471 391,735
---------- ----------
Operating income ................................................. 630,996 387,875
Other income (expense)
Interest and other, net ........................................ 10,701 4,689
Interest (expense) ............................................. 0 (3,053)
---------- ----------
Income before taxes .............................................. 641,697 389,781
Provision for income taxes ....................................... 180,395 168,163
---------- ----------
Net income ....................................................... $ 461,302 $ 221,618
========== ==========
Basic income per common share .................................... $ .07 $ .04
========== ==========
Diluted income per common share .................................. $ .06 $ .04
========== ==========
Basic weighted average number of common shares
outstanding
6,745,808 6,235,824
========== ==========
Diluted weighted average number of common shares
outstanding
7,163,243 6,421,889
========== ==========
The accompanying notes are an integral part of these statements.
5
ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three months ended September 30,
2005 2004
----------- -----------
Cash flows from operating activities:
Net income ............................................................ $ 461,302 $ 221,618
Adjustments to reconcile net income to net cash
provided used by operating activities:
Depreciation, depletion and amortization ............................ 254,336 156,000
Stock issued for interest expense ................................... -- 500
Deferred income tax provision ....................................... 180,395 168,163
Changes in assets and liabilities:
(Increase) in receivable ............................................ (200,336) (65,267)
Decrease in prepaid expense ......................................... 2,334 6,705
Increase (decrease) in accounts payable and accrued expense ......... 617,193 (143,242)
----------- -----------
Net cash provided by operating activities ........................... 1,315,224 344,477
----------- -----------
Cash flows from investing activities:
Additions to oil and gas properties ................................. (1,102,995) (467,629)
Purchase of producing properties .................................... -- (60,520)
Equipment inventory sales ........................................... 2,000 --
----------- -----------
Net cash (used) by investing activities ............................. (1,100,995) (528,149)
----------- -----------
Cash flow from financing activities:
Common stock options exercised ...................................... 14,250 --
Payment of notes payable ............................................ -- (37,500)
----------- -----------
14,250 (37,500)
----------- -----------
Net increase (decrease) in cash and cash equivalents ................ 228,479 (221,172)
Cash and cash equivalents, beginning of year ........................ 3,430,146 1,329,376
----------- -----------
Cash and cash equivalents, end of year .............................. $ 3,658,625 $ 1,108,204
=========== ===========
Other information
Interest paid ....................................................... $ -0- $ 3,053
=========== ===========
Non-cash transactions additions to asset retirement obligation ....... $ 26,000 $ --
=========== ===========
The accompanying notes are an integral part of these statements.
6
ASPEN EXPLORATION CORPORATION
Notes to Condensed Consolidated Financial Statements
(Unaudited)
September 30, 2005
Note 1 BASIS OF PRESENTATION
The accompanying financial statements are unaudited. However, in our
opinion, the accompanying financial statements reflect all adjustments,
consisting of only normal recurring adjustments, necessary for fair
presentation. Interim results of operations are not necessarily indicative
of results for subsequent interim periods or the remainder of the year.
These financial statements should be read in conjunction with our Annual
Report on Form 10-KSB for the year ended June 30, 2005.
Except for the historical information contained in this Form 10-QSB, this
Form contains forward-looking statements that involve risks and
uncertainties. Our actual results could differ materially from those
discussed in this Report. Factors that could cause or contribute to such
differences include, but are not limited to, those discussed in this Report
and any documents incorporated herein by reference, as well as the Annual
Report on Form 10-KSB for the year ended June 30, 2005.
Note 2 RECEIVABLE - RELATED PARTIES
The receivable from related parties constitutes amounts due from officers
and consultants for joint operating costs of wells operated by us. The
transactions are in the normal course of business and provide for the same
terms as other unaffiliated joint owners and are repaid in a normal
business cycle.
Note 3 ASSET RETIREMENT OBLIGATION
We have adopted the provisions of Statement of Financial Accounting
Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations."
SFAS No. 143 generally applies to legal obligations associated with the
retirement of long-lived assets that result from the acquisition,
construction, development and/or the normal operation of a long-lived
asset. SFAS No. 143 requires us to recognize an estimated liability for the
plugging and abandonment of our gas wells. We have recognized the future
cost to plug and abandon the gas wells over the estimated useful lives of
the wells in accordance with SFAS No. 143. A liability for the fair value
of an asset retirement obligation with a corresponding increase in the
carrying value of the related long-lived asset is recorded at the time a
producing well is purchased or a drilled well is completed and ready for
production. We will amortize the amount added to the oil and gas properties
and recognize accretion expense in connection with the discounted liability
over the remaining life of the respective well. The estimated liability is
based on historical experience in plugging and abandoning wells, estimated
useful lives based on engineering studies, external estimates as to the
cost to plug and abandon wells in the future and federal and state
regulatory requirements. The liability is a discounted liability using
7
Note 3 ASSET RETIREMENT OBLIGATION (CONTINUED)
a credit adjusted risk-free rate of 6%. Revisions to the liability could
occur due to changes in plugging and abandonment costs, useful well lives
or if federal or state regulators enact new regulations on the plugging and
abandonment of wells.
A reconciliation of our liability for the year ended September 30, 2005 is
as follows:
Asset retirement obligations as of
June 30, 2005 $ 96,210
ARO additions 26,000
Liabilities settled -0-
Accretion expense -0-*
Revision of estimate -0-
---------
Asset retirement obligation as of
September 30, 2005 $ 122,210
=========
* Accretion not material
Note 4 EARNINGS PER SHARE
We follow SFAS No. 128, addressing earnings per share. SFAS No. 128
established the methodology of calculating basic earnings per share and
diluted earnings per share. The calculations differ by adding any
instruments convertible to common stock (such as stock options, warrants,
and convertible preferred stock) to weighted average shares outstanding
when computing diluted earnings per share.
The following is a reconciliation of the numerators and denominators used
in the calculations of basic and diluted earnings per share. We had a net
income of $461,302 for the three months ended September 30, 2005 and
$221,618 for the three months ended September 30, 2004.
Three Months Ended
September 30, 2005 September 30, 2004
---------------------------------- -----------------------------------------
Per Per
Net Share Net Share
Income Shares Amount Income Shares Amount
----------- --------- -------- ---------- ----------- -----------
Basic earnings per share:
Net income and share amounts $ 461,302 6,745,808 $ .07 $ 221,618 6,235,824 $ .04
Dilutive securities:
stock options -- 527,000 -- 392,000
Repurchased shares -- (109,565) -- (205,935)
-------------------------------------------------------------------------------
Diluted earnings per share:
Net income and assumed share
conversion $ 461,302 7,163,243 $ .06 $ 221,618 6,421,889 $ .04
========== ========== ======= ========= ========= ========
8
Note 5 STOCKHOLDERS' EQUITY
Stock Options
-------------
On August 15, 2005, a consultant exercised options for 25,000 shares of our
common stock granted March 14, 2002 at an average price of $0.57 per share.
The consultant paid us $14,250 to exercise his options on the 25,000
shares.
As of September 30, 2005, we had an aggregate of 527,000 common shares
reserved for issuance under our stock option plans. These plans provide for
the issuance of common shares pursuant to stock option exercises,
restricted stock awards and other equity based awards.
The following information summarizes information with respect to options
granted under our equity plans:
Number of Weighted Average Exercise
Shares Price of Shares Under Plans
------ ---------------------------
Outstanding balance June 30, 2005 552,000 $1.559
======
Granted -0- --
======
Exercised (25,000) .57
======
Forfeited or expensed -0- --
======
-------
Outstanding balance September 30, 2005 527,000 $1.606
======== ======
The following table summarizes information concerning outstanding and
exercisable options as of September 30, 2005:
Outstanding Exercisable
--------------------------- -------------------------
Weighted
Average Weighted Weighted
Remaining Average Average
Exercise Number Contractual Exercisable Number Exercise
Price Outstanding Life In Years Price Exercisable Price
-------- ----------- ------------- ----------- ----------- --------
$ .57 117,000 08/15/2006(1) $ .57 -0- $ .57
.57 150,000 08/15/2007(1) .57 -0- .57
2.67 260,000 01/01/2007(1) 2.67 -0- 2.67
-------
527,000
(1) The term of the option will be the earlier of the contractual life of
the options or 90 days after the date the optionee is no longer an
employee, consultant or director of the Company.
We account for stock options using APB No. 25 for directors and employees
and SFAS No. 123 for consultants.
There were 260,000 options granted in 2005. Directors and employees were
granted 235,000 and consultants were granted 25,000. The consultant options
were valued using the fair value method of SFAS No. 123 as calculated by
the Black-Scholes option-pricing model. The fair value of each option
grant, as opposed to its exercisable price, is estimated on the date of
grant using the Black-Scholes option-pricing model with the following
weighted average assumptions: no dividend yield, expected volatility of
9
Note 5 STOCKHOLDERS' EQUITY (CONTINUED)
159.54%, risk free interest rates of 3.92% and expected lives of 4.5 years.
The resulting compensation expense relating to the option grant to
directors and employees of $549,821 and consultant of $58,492 will be
included as an operating expense ratably over the vesting period. The
options vest one-third January 2006, 2007 and 2008.
Note 6 MAJOR CUSTOMERS
We derived in excess of 10% of our revenue from various sources (oil and
gas sales) as follows:
The Company
-----------
A B C D
- - - -
Quarter ended:
September 30, 2005 46% 40% * 11%
September 30, 2004 26% 55% 11% *
* Less than 10%.
Note 7 INCOME TAXES
We have recorded a deferred income tax liability of $1,195,883 as of
September 30, 2005. During the first quarter of 2005, we used no net
operating loss carryforwards leaving approximately $164,000 in available
federal net operating loss carryforwards as of September 30, 2005.
The deferred tax consequences of temporary differences in reporting items
for financial statement and income tax purposes are recognized, if
appropriate. Realization of future tax benefits related to the deferred tax
assets is dependent on many factors, including our ability to generate
taxable income within the net operating loss carryforward period. We have
considered these factors in reaching our conclusion as to the valuation
allowance for financial reporting purposes. Primarily, our proved oil and
gas reserves substantially exceed our expected future costs and hence, we
believe it more likely than not that the benefit will be realized.
10
Note 7 INCOME TAXES (CONTINUED)
At September 30, the income tax effect of temporary differences comprising
the deferred tax assets and deferred tax liabilities on the accompanying
balance sheet is the result of the following:
2005
------------
Deferred tax assets:
Federal tax loss
carryforwards $ 149,133
Asset retirement obligation 10,999
-----------
160,132
Deferred tax (liabilities):
Property, plant and equipment 277
Oil and gas properties (1,356,292)
-----------
(1,356,015)
-----------
$(1,195,883)
A reconciliation between the statutory federal income tax rate (34%) and
the effective rate of income tax expense for the two years ended September
30 is as follows:
2005
----
Statutory federal income
tax rate 34%
Less: Net operating losses and
Future deductions (15)%
----
Net federal income tax rate 19%
Statutory state income tax
rate, net of federal benefit 9%
Effective rate 28%
====
11
Note 7 INCOME TAXES (CONTINUED)
The provision for income taxes consists of the following components:
2005 2004
-------- --------
Current tax expense, state $ -- $ --
Deferred tax expense 180,395 168,163
-------- --------
Total income tax provision $180,395 $168,163
======== ========
We have available federal net operating loss carryforwards of approximately
$164,000 (net operating losses expire beginning June 30, 2023 through the
year ending June 30, 2026).
Note 8 DRILLING COMMITMENTS AND CONTINGENCIES
We have a proposed drilling budget for the period October through December
2005. The budget includes drilling four 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:
Completion &
Area Wells Drilling Costs Equipping Costs Total
---------------------------------- ------------ --------------------- ----------------------- --------------
Denverton Creek Field, 1 $170,000 $76,000 $246,000
Solano County, CA
West Grimes Field 1 139,000 86,000 225,000
Colusa County,
CA
Buckeye, Colusa 1 165,000 132,000 297,000
County, CA
Winters, Yolo 1 85,000 81,000 166,000
County, CA
------------ --------------------- ----------------------- --------------
Total Expenditure 4 $559,000 $375,000 $934,000
============ ===================== ======================= ==============
12
Note 9 SUBSEQUENT EVENTS
The Kalfsbeek #1-13 well located in the Buckeye Gas Field, Colusa County,
California, was drilled to a depth of 8,800 feet and encountered
approximately 90 feet of potential gas pay in several intervals in the
Forbes formation. Production casing was run based on favorable mud log and
electric log responses. Several of these Forbes intervals were perforated
and tested gas at a stabilized rate of 2,909 MCFPD with a flowing tubing
pressure of 2,005 psig and a flowing casing pressure of 2,080 psig. The
shut in tubing and casing pressures were 3,250 psig. Aspen has a 30.625%
operated working interest in this well.
The WGU #15-10 well located in the West Grimes Gas Field, Colusa County,
California, was directionally drilled to a depth of 8,520 feet (7,975 feet
TVD) and encountered approximately 100 feet of potential gas pay in several
intervals in the Forbes formation. Production casing was run based on
favorable mud log and electric log responses. Aspen has a 21% operated
working interest in this well.
The Street #1-3 well located in the Dry Slough Gas Field, Yolo County,
California, was directionally drilled to a depth of 6,450 feet (5,563 feet
TVD) and encountered approximately 45 feet of potential gas pay in several
intervals in the Starkey and Winters formations. Production casing was run
based on favorable mud log and electric log responses. The well will be
completed in the near future. Aspen has a 21.875% operated working interest
in this well.
13
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
This segment should be read in conjunction with the management's discussion
and analysis of financial condition and results of operations contained in our
Annual Report on Form 10-KSB for the year ended June 30, 2005, which has been
filed with the Securities and Exchange Commission. The management discussion and
analysis and other portions of this report contain forward-looking statements
(as such term is defined in Section 21E of the Securities Exchange Act of 1934,
as amended). These statements reflect our current expectations regarding our
possible future results of operations, performance, and achievements. These
forward-looking statements are made pursuant to the safe harbor provisions of
the Private Securities Litigation Reform Act of 1995.
Wherever possible, we have tried to identify these forward-looking
statements by using words such as "anticipate," "believe," "estimate," "expect,"
"plan," "intend," and similar expressions. These statements reflect our current
beliefs and are based on information currently available to us. Accordingly,
these statements are subject to certain risks, uncertainties, and contingencies,
which could cause our actual results, performance, or achievements to differ
materially from those expressed in, or implied by, such statements. These risks,
uncertainties and contingencies include, without limitation, the factors set
forth in our Form 10-KSB under "Item 6. Management's Discussion and Analysis of
Financial Conditions or Plan of Operation - Factors that may affect future
operating results." We have no obligation to update or revise any such
forward-looking statements that may be made to reflect events or circumstances
after the date of this Form 10-QSB.
Overview
--------
Aspen Exploration Corporation was organized in 1980 for the purpose of
acquiring, exploring and developing oil and gas and other mineral properties.
Since 1996, we have focused our efforts on the exploration, development and
operation of natural gas properties in the Sacramento Valley of northern
California. We are currently the operator of 51 gas wells and have a
non-operated interest in 15 additional gas wells.
We currently have offices in Bakersfield, California and Denver, Colorado
and have 2 full time employees as well as the Chairman of the Board who
allocates a portion of his time to the Company. We also make extensive use of
consultants for the conduct of our business, ranging from financial,
engineering, land, legal, and geological and geophysical specialists. Our goal
is to identify low to moderate risk wells with good gas reserve potential.
Where possible, we attempt to be the operator of each property we invest
in. Our knowledge of drilling and operating wells in the Sacramento Valley
allows us to maximize the potential return of each property. Administrative
charges to the properties help cover approximately 53% of our selling, general
and administrative expenses.
Outlook and Trends
------------------
We expect our natural gas production to increase substantially during
fiscal 2006 due to recent drilling successes. Total production for the year will
depend on the number of wells successfully completed, the date they are put on
line, their initial rate of production, and their production decline rates. We
also anticipate that the gas price for our product will be in the range of $7.00
to $13.00 per MMBTU for the fiscal year ended June 30, 2006 as compared to the
gas price of $6.20 during our 2005 fiscal year.
14
Over the past five years we have been able to replace the majority of our
produced reserves and increase our yearly natural gas production. We have also
benefited from a general increase in natural gas prices over the past two years,
from a low of $2.78 per MMBTU average during the first quarter of fiscal 2003 to
$7.26 per MMBTU for the quarter ended September 30, 2005.
Quantitative and Qualitative Disclosure About Risk
--------------------------------------------------
Our ability to replace reserves, dissipated through production or
recalculation, will depend largely on how successful our drilling and
acquisition efforts will be in the future. While we cannot predict the future,
our historic success ratio over the past five years has been 88%. With the use
of 3-D seismic and well control data, interpreted by our geological and
geophysical consultants, we feel we can manage our dry hole risk as well as
anyone in the industry.
Commodity prices are impacted by many factors that are outside of our
control. Historically, commodity prices have been volatile and we expect them to
remain volatile. Commodity prices are affected by changes in market demands,
overall economic activity, weather, pipeline capacity constraints, inventory
storage levels, basis differentials and other factors. As a result, we cannot
accurately predict future natural gas and NGL (natural gas liquids) prices, and
therefore, we cannot determine what effect increases or decreases in production
volumes will have on future revenues.
On regulatory and operational matters, we actively manage our exploration
and production activities. We value sound stewardship and strong relationships
with all stakeholders in conducting our business. We attempt to stay abreast of
emerging issues to effectively anticipate and manage potential impacts to our
operations.
To manage commercial risk, we may use financial tools to hedge the price we
will receive for our product. The primary purpose of hedging is to provide
adequate return on our investments, grow our reserves while leaving as much
commodity price upside as possible. During the period November 1, 2005 through
March 31, 2006, we are contractually obligated to deliver 3,750 MMBTU per day to
two of our natural gas purchasers as follows:
1,000 MMBTU/Day @ $8.43 per MMBTU
1,000 MMBTU/Day @ $8.40 per MMBTU
500 MMBTU/Day @ $9.49 per MMBTU
500 MMBTU/Day @ $9.48 per MMBTU
750 MMBTU/Day @ $11.02 per MMBTU
The average price received during the first quarter of fiscal 2006 for our
natural gas was approximately $7.21 per MMBTU.
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.
15
Cash of $1,315,224 and $344,477 was provided by our operations for the
three months ended September 30, 2005 and 2004. The 2005 period generated net
income of $461,302, and we were able to generate increased positive cash flow
from operations during the first three months of fiscal 2005 as compared to the
2004 period (when we generated net income of $221,618) because of:
An increase in oil and gas sales (52%) due to increased volumes sold
(13%) and the price received for our gas (37%); and
An increase in accounts payable and accrued expenses of $617,193 in
2005 (which conserved cash) compared to a decrease in accounts payable
and accrued expenses of $143,242 (which used cash during the 2004
period); and
These changes were offset by increased depletion, depreciation and
amortization expense of $254,336 in 2005 compared to $156,000 in 2004.
Investing activities used cash to increase net capitalized oil and gas
costs of $1,100,995 and $528,149 in the three months ended September 30, 2005
and 2004. Cash in the current three month period ended September 30, 2005 was
used for lease acquisition, seismic work, intangible drilling and well workovers
($878,875), and the purchase of oil and gas well equipment ($222,120). These
expenditures are net of the sale of interests in wells to be drilled charged to
third party investors.
We have a proposed drilling, completion and construction budget for the
period October through December 2005. The budget includes drilling four wells in
the Sacramento gas province of northern California. Our share of the estimated
costs to complete this program over the next three months is set forth in the
following table:
Completion &
Area Wells Drilling Costs Equipping Costs Total
---------------------------------- ------------ --------------------- ----------------------- --------------
Denverton Creek Field, 1 $170,000 $76,000 $246,000
Solano County, CA
West Grimes Field 1 139,000 86,000 225,000
Colusa County,
CA
Buckeye, Colusa 1 165,000 132,000 297,000
County, CA
Winters, Yolo 1 85,000 81,000 166,000
County, CA
------------ --------------------- ----------------------- --------------
Total Expenditure 4 $559,000 $375,000 $934,000
============ ===================== ======================= ==============
Our working capital (current assets less current liabilities) at September
30, 2005, was $2,418,673, which reflects an approximate $190,700 decrease from
our working capital at June 30, 2005. Our working capital declined by 7.3%
during the first quarter of our 2005 fiscal year because of an increase in
advances from joint owners of $325,000 that were not expended for drilling
16
projects at September 30, 2005, and an increase in accounts payable of $293,000.
These increases were offset somewhat by the increase in cash and accounts
receivable of $429,000. We anticipate that our working capital and anticipated
cash flow from operations and future successful drilling will be sufficient to
pay our current liabilities. 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 below, this
is dependent, in part, on maintaining or increasing our level of production and
the national and world market maintaining its current prices for our gas
production.
Our capital requirements can fluctuate over a twelve month period because
the majority of our drilling program is usually carried out in California's dry
season, from late April until November, after which wet weather either precludes
further activity or makes it cost prohibitive.
We believe that internally generated funds will be sufficient to finance
our drilling and operating expenses for the next twelve months. 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.
17
Results of Operations
---------------------
September 30, 2005 Compared to September 30, 2004
-------------------------------------------------
For the three months ended September 30, 2005, our operations continued to be
focused on the production of oil and gas, and the investigation for possible
acquisition of producing oil and gas properties in California. During the 2005,
period our revenues increased by approximately $410,000 as compared to the
comparable period of our 2004 fiscal year because of:
Increased production (146,400 MMBTU sold as compared to 130,000 MMBTU
sold during the first three months of our 2004 fiscal year);
Increased price received for our production (an average of $7.26 per
MMBTU during the first three months of our 2006 fiscal year as compared
to $5.31 per MMBTU received during that period in 2005); and
Increased management fees received ($120,900 during fiscal 2006 as
compared to $82,100 during fiscal 2005) because we were operators of
more wells during 2006 (51 wells compared to 48 wells in 2005).
18
The following table sets forth certain items from our Condensed Consolidated
Statements of Operations as expressed as a percentage of total revenues, shown
by quarter for the three months of fiscal 2005, 2004, 2003 and 2002:
For the Three Months Ended
------------ ------------ ------------- ------------
9/30/05 9/30/2004 9/30/2003 9/30/2002
------------ ------------ ------------- ------------
Total revenues 100.0% 100.0% 100.0% 100.0%
Oil & gas production costs 5.9 8.2 10.1 14.3
------------ ------------ ------------- ------------
Income from operations 94.1 91.8 89.9 85.7
------------ ------------ ------------- ------------
Costs and expenses
Depreciation and depletion 21.3 19.9 32.9 32.2
Selling, general and administrative 19.0 21.8 44.1 70.1
Interest expense .0 .3 .0 .0
------------ ------------ ------------- ------------
Total costs and expenses 40.3 42.0 77.0 102.3
------------ ------------ ------------- ------------
Income before income taxes 53.8 49.8 12.9 (16.6)
Provision for income taxes 15.1 21.4 .0 .0
------------ ------------ ------------- ------------
Net income (loss) 38.7 28.4 12.9 (16.6)
============ ============ ============= ============
To facilitate discussion of our operating results for the three months ended
September 30, 2005 and 2004, 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)
---------------------------------------- --------------------------------
2005 2004 Amount Percentage
------------------- -------------------- --------------- ----------------
Revenues:
Oil and gas sales $1,062,543 $697,553 $ 364,990 52%
Management fees 120,924 82,057 38,867 47
Interest and other 10,701 4,689 6,012 128
------------------- -------------------- --------------- ---------------
Total revenues 1,194,168 784,299 409,869 52
------------------- -------------------- --------------- ---------------
Cost and expenses:
Oil and gas production 71,019 64,361 6,658 10
Depreciation and depletion 254,336 156,000 98,336 63
Selling, general and administrative 227,116 171,104 56,012 33
Interest expense 0 3,053 (3,053) (100)
------------------- -------------------- --------------- ---------------
Total costs and expenses 552,471 394,518 157,953 40
------------------- -------------------- --------------- ---------------
Income before taxes 641,697 389,781
Provision for income taxes 180,395 168,163
------------------- -------------------
Net income $461,302 $221,618
=================== ===================
19
Central to the issue of success of the three months operations ended September
30, 2005 is the discussion of changes in oil and gas sales, volumes of natural
gas sold and the price received for those sales. We present them here in tabular
form:
Oil & Gas MMBTU (1)
Sales Sold Price/MMBTU
-------------- --------------- ------------------
2006
----------------------------
lst Quarter $1,062,543 146,445 $7.26
-------------- --------------- ------------------
2005
----------------------------
lst Quarter 697,553 130,000 5.31
2nd Quarter 1,132,359 177,350 6.37
3rd Quarter 1,103,687 169,150 6.52
4th Quarter 919,578 145,500 6.30
-------------- --------------- ------------------
Year to date 3,853,177 622,000 6.20
-------------- --------------- ------------------
2004
----------------------------
lst Quarter 341,926 72,600 4.75
2nd Quarter 362,942 79,900 4.64
3rd Quarter 401,941 71,900 5.28
4th Quarter 481,441 80,600 5.97
-------------- --------------- -----------------
Year to date 1,588,250 305,000 5.17
-------------- --------------- -----------------
2003
----------------------------
lst Quarter 198,431 65,800 2.78
2nd Quarter 241,700 63,700 3.76
3rd Quarter 314,222 57,900 5.47
4th Quarter 314,445 60,600 5.19
-------------- --------------- ------------------
Year to date 1,068,798 248,000 4.23
-------------- --------------- -----------------
First Quarter change
----------------------------
2006
----------------------------
Amount $364,990 16,445 $1.95
Percentage 52% 13% 37%
2005
----------------------------
Amount $355,627 57,400 $.56
Percentage 104% 79% 12%
(1) Price per MMBTU may not agree with oil and gas sales because of the
inclusion of oil and NGL sales.
Oil and gas revenue, volumes sold and price received for our product have shown
a steady improvement over the first three months of fiscal 2006 and during the
twelve months of fiscal 2005. As the table above notes, revenue has increased
approximately 52% when comparing the three month periods ended September 30,
2005 and 2004. Volumes sold increased approximately 13%, while the price
received for our product increased 37%.
Total revenue increased $365,000, or 52% when comparing the two periods, while
operating and production costs increased $6,660, or 10%. Our results during the
current period were favorable in part because we were able to keep increases in
our production costs significantly less than the increases in prices received
for natural gas. The 10% increase in production costs is even less than the 13%
increase in volumes produced.
A significant ratio presented is the percentage of management fees charged to
operated wells versus our general and administrative costs. This coverage of
20
general and administrative costs improved from approximately 48% for the three
months ended September 30, 2004 to approximately 53% at September 30, 2005.
When comparing general and administrative expense for 2006 and 2005, costs
increased approximately $56,000, or 33%, primarily because of increases in
promotion and advertising ($24,000), accounting and audit fees ($13,000), legal
fees, medical insurance, corporate reporting and consulting fees and other
($19,000).
Results of operations and net income are presented in the following table:
Quarterly Financial Information (unaudited)
Income (loss)
(1) (2) Before Income Taxes
Total Operating Income (loss) Per Share
Revenues Income Before Income Taxes Basic Diluted
--------------- ------------- ------------------------ --------- -------------
2006
------------------------ --------------- ------------- ------------------------ --------- -------------
lst Quarter $1,194,168 $1,112,448 $641,697 $.095 $.090
--------------- ------------- ------------------------ --------- -------------
2005
------------------------
1st Quarter 784,299 715,249 389,781 .063 .061
2nd Quarter 1,190,333 1,092,632 729,748 .074 .070
3rd Quarter 1,163,746 1,056,268 703,738 .109 .109
4th Quarter 980,926 908,704 382,957 .094 .090
--------------- ------------- ------------------------ --------- -------------
Total 4,119,304 3,772,853 2,206,224 .34 .33
--------------- ------------- ------------------------ --------- -------------
2004
------------------------
lst Quarter 388,337 348,739 50,197 .01 .01
2nd Quarter 433,317 365,761 93,022 .01 .01
3rd Quarter 440,127 354,642 76,762 .01 .01
4th Quarter 558,899 509,066 145,664 .02 .01
--------------- ------------- ------------------------ --------- -------------
Total 1,820,680 1,578,208 365,645 .05 .05
--------------- ------------- ------------------------ --------- -------------
2003
------------------------
lst Quarter 264,896 232,246 (44,238) (.008) (.007)
2nd Quarter 279,080 237,155 (15,660) (.003) (.003)
3rd Quarter 337,476 271,845 28,748 .005 .005
4th Quarter 432,369 272,421 133,876 .023 .022
--------------- ------------- ------------------------ --------- -------------
Total $1,313,821 $1,013,667 $102,726 $.02 $.02
--------------- ------------- ------------------------ --------- -------------
(1) Operating income is oil and gas sales plus management fees less direct operating costs.
(2) Before provision for deferred income taxes.
As can be seen in the table, revenues and operating income have improved in
every quarter when comparing the three month periods ended September 30, 2005
and 2004. We believe this is due to the steady increase in production volumes
sold in each subsequent quarter and the fact that we have enjoyed an
appreciating price received for our product. Operating income has increased
because production costs have increased at a lesser rate than production and
prices.
21
Contractual Obligations:
------------------------
We had five contractual obligations as of September 30, 2005. The following
table lists our significant liabilities at September 30, 2005:
Payments Due By Period
------------------------------------------------------------------------------------------
Less than After
Contractual Obligations 1 year 2-3 years 4-5 years 5 years Total
---------------------------------- --------------- -------------- -------------- --------------- ---------------
Employment Obligations $222,200 $468,200 $87,200 $-0- $777,600
Contract Services 30,000 -0- -0- -0- 30,000
Obligations
Operating Leases 9,500 1,600 -0- -0- 11,100
--------------- -------------- -------------- --------------- ---------------
Total contractual
cash obligations $261,700 $469,800 $87,200 $-0- $818,700
=============== ============== ============== =============== ===============
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 month to month lease agreement beginning January 1, 2005 on the Denver
office at a lease rate of $1,261 per month. The Bakersfield, California office
has 546 square feet and a monthly rental fee of $730 to $770 over the term of
the lease. The three year lease expires February 8, 2006. Rent expense for the
three months ended September 30, 2005 and 2004 was $6,163 and $6,033,
respectively.
Critical Accounting Policies and Estimates:
-------------------------------------------
We believe the following critical accounting policies affect our most
significant judgments and estimates used in the preparation of our Condensed
Consolidated Financial Statements.
Reserve Estimates:
------------------
Our estimates of oil and natural gas reserves, by necessity, are projections
based on geologic and engineering data, and there are uncertainties inherent in
the interpretation of such data as well as the projection of future rates of
production and the timing of development expenditures. Reserve engineering is a
subjective process of estimating underground accumulations of oil and natural
gas that are difficult to measure. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological
interpretation and judgment. Estimates of economically recoverable oil and
natural gas reserves and future net cash flows necessarily depend upon a number
of variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects of
regulations by governmental agencies and assumptions governing future oil and
natural gas prices, future operating costs, severance and excise taxes,
development costs and workover and remedial costs, all of which may in fact vary
considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of oil and natural gas attributable to any
22
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 uncollectable accounts based on management's
estimate of the collectability of customer accounts. If the financial condition
of a customer were to deteriorate, resulting in an impairment of its ability to
make payments, an additional allowance may be required. Allowance adjustments
are charged to operations in the period in which the facts that give rise to the
adjustments become known.
Property, Equipment, Depreciation and Depletion:
------------------------------------------------
We follow the full-cost method of accounting for oil and gas properties. Under
this method, all productive and nonproductive costs incurred in connection with
the exploration for and development of oil and gas reserves are capitalized.
Such capitalized costs include lease acquisition, geological and geophysical
work, delay rentals, drilling, completing and equipping oil and gas wells,
including salaries, benefits and other internal salary related costs directly
attributable to these activities. Costs associated with production and general
corporate activities are expensed in the period incurred. Interest costs related
to unproved properties and properties under development are also capitalized to
oil and gas properties. If the net investment in oil and gas properties exceeds
an amount equal to the sum of (1) the standardized measure of discounted future
net cash flows from proved reserves, and (2) the lower of cost or fair market
value of properties in process of development and unexplored acreage, the excess
is charged to expense as additional depletion. Normal dispositions of oil and
gas properties are accounted for as adjustments of capitalized costs, with no
gain or loss recognized.
We apply SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets." Under SFAS No. 144, long-lived assets and certain intangibles are
reported at the lower of the carrying amount or their estimated recoverable
amounts. Long-lived assets subject to the requirements of SFAS No. 144 are
evaluated for possible impairment through review of undiscounted expected future
cash flows. If the sum of undiscounted expected future cash flows is less than
the carrying amount of the asset or if changes in facts and circumstances
indicate, an impairment loss is recognized.
Asset retirement obligations:
-----------------------------
We recognize the future cost to plug and abandon gas wells over the estimated
useful life of the wells in accordance with the provision of SFAS No. 143. SFAS
No. 143 requires that we record a liability for the present value of the asset
retirement obligation with a corresponding increase to the carrying value of the
related long-lived asset. We amortize the amount added to the oil and gas
23
properties and recognize accretion expense in connection with the discounted
liability over the remaining lives of the respective gas wells. Our liability
estimate is based on our historical experience in plugging and abandoning gas
wells, estimated well lives based on engineering studies, external estimates as
to the cost to plug and abandon wells in the future and federal and state
regulatory requirements. The liability is discounted using a credit-adjusted
risk-free rate of 6%. Revisions to the liability could occur due to changes in
well lives, or if federal and state regulators enact new requirements on the
plugging and abandonment of gas wells.
24
Item 3. CONTROLS AND PROCEDURES
As required by Rule 13a-15 under the Securities Exchange Act of 1934, as of
the filing date of this report, we carried out an evaluation of the
effectiveness of the design and operation of our disclosure controls and
procedures. This evaluation was carried out under the supervision and with the
participation of our principal executive officer (who is also our principal
financial officer), who concluded that our disclosure controls and procedures
are effective. There have been no significant changes in our internal controls
or in other factors, which could significantly affect internal controls
subsequent to the date we carried out our evaluation.
Disclosure controls and procedures are controls and other procedures that
are designed to ensure that information required to be disclosed in our reports
filed or submitted under the Securities Exchange Act is recorded, processed,
summarized and reported, within the time periods specified in the Securities and
Exchange Commission's rules and forms. Disclosure controls and procedures
include, without limitation, controls and procedures designed to ensure that
information required to be disclosed in our reports filed under the Exchange Act
is accumulated and communicated to management, including our principal executive
officer and our principal financial officer, as appropriate, to allow timely
decisions regarding required disclosure.
PART II
Item 1. Legal Proceedings.
-----------------
There are no material pending legal or regulatory proceedings against Aspen
Exploration Corporation, and it is not aware of any that are known to be
contemplated.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
----------------------------------------------------------
None during the period
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Submission of Matters to a Vote of Security Holders.
----------------------------------------------------
No matter was submitted during the first quarter of the fiscal year covered
by this report to a vote of security holders, through the solicitation of
proxies or otherwise.
Item 5. Other Information.
-----------------
None.
Item 6. Exhibits.
--------
31. Rule 13a-14(a) Certification
32. Section 1350 Certification
25
In accordance with the requirements of the Securities Exchange Act of 1934,
we have duly caused this report to be signed on our behalf by the undersigned,
thereunto duly authorized.
ASPEN EXPLORATION CORPORATION
/s/ Robert A. Cohan
--------------------------------------------
By: Robert A. Cohan,
November 10, 2005 Chief Executive Officer,
Principal Financial Officer
26