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ASPN Form 10QSB for ASPEN EXPLORATION CORP
Form 10QSB for ASPEN EXPLORATION CORP
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12-Nov-2004
Quarterly Report
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This segment should be read in conjunction with the management's discussion and analysis of financial condition and results of operations contained in our Annual Report on Form 10-KSB for the year ended June 30, 2004, which has been filed with the Securities and Exchange Commission. The management discussion and analysis and other portions of this report contain forward-looking statements (as such term is defined in Section 21E of the Securities Exchange Act of 1934, as amended). These statements reflect our current expectations regarding our possible future results of operations, performance, and achievements. These forward-looking statements are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995.
Wherever possible, we have tried to identify these forward-looking statements by using words such as "anticipate," "believe," "estimate," "expect," "plan," "intend," and similar expressions. These statements reflect our current beliefs and are based on information currently available to us. Accordingly, these statements are subject to certain risks, uncertainties, and contingencies, which could cause our actual results, performance, or achievements to differ materially from those expressed in, or implied by, such statements. These risks, uncertainties and contingencies include, without limitation, the factors set forth in our Form 10-KSB under "Item 6. Management's Discussion and Analysis of Financial Conditions or Plan of Operation - Factors that may affect future operating results." We have no obligation to update or revise any such forward-looking statements that may be made to reflect events or circumstances after the date of this Form 10-QSB.
Overview
Aspen Exploration Corporation was organized in 1980 for the purpose of acquiring, exploring and developing oil and gas and other mineral properties. Since 1996, we have focused our efforts on the exploration, development and operation of natural gas properties in the Sacramento Valley of northern California. We are currently the operator of 48 gas wells and have a non-operated interest in 15 additional gas wells.
We currently have offices in Bakersfield, California and Denver, Colorado and have 2 full time employees as well as the Chairman of the Board who allocates a portion of his time to the Company. We also make extensive use of consultants for the conduct of our business, ranging from financial, engineering, land, legal, and geological and geophysical specialists.
We will typically review 20 to 25 prospects for every well we participate in, using 3-D seismic and well control geology to evaluate each prospect. Our goal is to identify low to moderate risk wells with good gas reserve potential.
Where possible, we attempt to be the operator of each property we invest in. Our knowledge of drilling and operating wells in the Sacramento Valley allows us to maximize the potential return of each property. Administrative charges to the properties help cover approximately 33% of our selling, general and administrative expenses.
Outlook and Trends
We expect our natural gas production to increase substantially during fiscal 2005 due to recent drilling successes. Total production for the year will
depend on the number of wells successfully completed, the date they are put on line, their initial rate of production, and their production decline rates. We also anticipate that the average price for our product will be in the range of $5.00 to $7.25 per MMBTU for the fiscal year ended June 30, 2005.
Over the past five years we have been able to replace our produced reserves and increase our yearly natural gas production. We have also benefited from a general increase in natural gas prices over the past two years, from a low of $2.78 per MMBTU average during the first quarter of fiscal 2003 to $5.31 per MMBTU for the quarter ended September 30, 2004.
Quantitative and Qualitative Disclosure About Risk
Our ability to replace reserves, dissipated through production or recalculation, will depend largely on how successful our drilling and acquisition efforts will be in the future. While we cannot predict the future, our historic success ratio over the past four years has been 87%. With the use of 3-D seismic and well control data, interpreted by our geological and geophysical consultants, we feel we can manage our dry hole risk as well as anyone in the industry.
Commodity prices are impacted by many factors that are outside of our control. Historically, commodity prices have been volatile and we expect them to remain volatile. Commodity prices are affected by changes in market demands, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas and NGL (natural gas liquids) prices, and therefore, we cannot determine what effect increases or decreases in production volumes will have on future revenues.
On regulatory and operational matters, we actively manage our exploration and production activities. We value sound stewardship and strong relationships with all stakeholders in conducting our business. We attempt to stay abreast of emerging issues to effectively anticipate and manage potential impacts to our operations.
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, 2004 through March 31, 2005, we are contractually obligated to deliver 4,000 MMBTU per day to two of our natural gas purchasers as follows:
2,000 MMBTU/Day @ $7.97 per MMBTU 1,000 MMBTU/Day @ $6.90 per MMBTU 500 MMBTU/Day @ $7.52 per MMBTU 500 MMBTU/Day @ $8.75 per MMBTU
The average price received during the first quarter of fiscal 2005 for our natural gas was approximately $5.31 per MMBTU.
During December 2003, we borrowed $225,000 from a bank for a modest acquisition. We currently pay 2% over the bank's prime rate for that facility. At September 30, 2004, the effective interest rate was 6.75% and the outstanding loan balance was $112,500. In June 2004, we borrowed $300,000 from an Oklahoma corporation to facilitate the drilling and completion of several wells in northern California. This debt was converted to our common stock on July 15, 2004.
Liquidity and Capital Resources
We have historically financed our operations with internally generated funds and limited borrowings from banks and third parties, and farmout arrangements, which permit third parties (including some related parties) to participate in our drilling prospects. Our principal uses of cash are for operating expenses, the acquisition, drilling and production of prospects, the acquisition of producing properties, working capital, servicing debt and the payment of income taxes.
Cash of $344,477 and $329,733 was provided by our operations for the three months ended September 30, 2004 and 2003. Even though the 2003 period generated a modest net income of $50,197, we were able to generate a comparable positive cash flow from operations during the first three months of fiscal 2003 as compared to the 2004 period (when we generated net income of $221,618) because of:
Lower depreciation, depletion and amortization expenses ($127,600 in 2003 as compared to $156,000 in 2004); and
A $213,907 increase in accounts payable and accrued expenses in 2003 (which conserved cash during the 2003 period) compared to an $143,242 reduction in accounts payable and accrued expenses in 2004 (which required cash payments).
Investing activities used cash to increase capitalized oil and gas costs of $528,149 and $139,900 in the three months ended September 30, 2004 and 2003. Cash in the current three month period ended September 30, 2004 was used for lease acquisition, seismic work, intangible drilling and well workovers ($353,279), and the purchase of oil and gas well equipment ($174,870). 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 2004. The budget includes drilling one well in the Sacramento gas province of northern California and the completion of the Verona Pipeline. 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
-------------------------- ------------- ----------------------- ------------------------- --------------
West Grimes Field 1 $105,000 $71,000 $176,000
Colusa County, CA
Verona Pipeline - 120,000 120,000
------------- ----------------------- ------------------------- -- --------------
Total Expenditure 1 $105,000 $191,000 $296,000
============= ======================= ========================= ==============
Our working capital (current assets less current liabilities) at September 30, 2004, was $177,765, which reflects an approximate $279,000 increase from our working capital deficit at June 30, 2004. Our working capital situation improved during the first quarter of our 2005 fiscal year because of our positive cash
flow from operations and our ability to pay down our current liabilities, both made possible by our increase in net revenues and in net income recognized during the quarter. We anticipate that our working capital and anticipated cash flow from operations and future successful drilling will be sufficient to pay our current liabilities as long as our gas production continues to provide us with sufficient cash flow. As discussed below, this is dependent, in part, on maintaining or increasing our level of production and the national and world market maintaining its current prices for our gas production.
Our capital requirements can fluctuate over a twelve month period because our drilling program is usually carried out in California's dry season, from late April until November, after which wet weather either precludes further activity or makes it cost prohibitive.
We believe that internally generated funds will be sufficient to finance our drilling and operating expenses for the next twelve months. In June 2004, we borrowed $300,000 from an Oklahoma corporation to facilitate the drilling and completion of several wells in northern California. This debt and accrued interest were converted into 300,500 shares of our common stock at $1.00 per share on July 15, 2004. If our drilling efforts are successful, the anticipated increased cash flow from the new gas discoveries, in addition to our existing cash flow, should be sufficient to fund our share of planned future completion and pipeline costs.
Results of Operations
September 30, 2004 Compared to September 30, 2003
For the three months ended September 30, 2004, our operations continued to be focused on the production of oil and gas, and the investigation for possible acquisition of producing oil and gas properties in California. During the 2004 period our revenues increased by more than $395,000 as compared to the comparable period of our 2003 fiscal year because of:
Increased production (130,000 MMBTU sold as compared to 72,600 MMBTU sold during the first three months of our 2003 fiscal year);
Increased price received for our production (an average of $5.31 per MMBTU during the first three months of our 2005 fiscal year as compared to $4.75 per MMBTU received during that period in 2004); and
Increased management fees received ($82,100 during fiscal 2005 as compared to $45,900 during fiscal 2004) because we were operators of more wells during 2005 (48 wells compared to 33 wells in 2004).
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 2004, 2003 and 2002:
For the Three Months Ended
---------------------------------------
9/30/2004 9/30/2003 9/30/2002
--------- ---------- -----------
Total revenues 100.0% 100.0% 100.0%
Oil & gas production costs 8.2 10.1 14.3
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Income from operations 91.8 89.9 85.7
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Costs and expenses
Depreciation and depletion 19.9 32.9 32.2
Selling, general and administrative 21.8 44.1 70.1
Interest expense .3 .0 .0
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Total costs and expenses 42.0 77.0 102.3
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Income before income taxes 49.8 12.9 (16.6)
Provision for income taxes 21.4 .0 .0
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Net income (loss) 28.4 12.9 (16.6)
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To facilitate discussion of our operating results for the three months ended September 30, 2004 and 2003, 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)
---------------------------------------- ---------------------------
2004 2003 Amount Percentage
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Revenues:
Oil and gas sales $ 697,553 $ 341,926 $ 355,627 104%
Management fees 82,057 45,915 36,142 79
Interest and other 4,689 496 4,193 845
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Total revenues 784,299 388,337 395,962 102%
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Cost and expenses:
Oil and gas production 64,361 39,102 25,259 65
Depreciation and depletion 156,000 127,600 28,400 22
Selling, general and administrative 171,104 171,438 (334) --
Interest expense 3,053 -0- 3,053 --
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Total costs and expenses 394,518 338,140 56,378 17%
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Income before taxes 389,781 50,197
Provision for income taxes 168,163 -0-
--------- ---------
Net income $ 221,618 $ 50,197
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Central to the issue of success of the three months operations ended September 30, 2004 is the discussion of changes in oil and gas sales, volumes of natural gas sold and the price received for those sales. We present them here in tabular form:
Oil & Gas MMBTU (1)
Sales Sold Price/MMBTU
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2005
-----
lst Quarter $ 697,553 130,000 $ 5.31
--------- -------- --------
2004
----
lst Quarter 341,926 72,600 4.75
2nd Quarter 362,942 79,900 4.64
3rd Quarter 401,941 71,900 5.28
--------- -------- --------
Year to date 1,106,809 224,400 4.88
--------- -------- --------
2003
----
lst Quarter 198,431 65,800 2.78
2nd Quarter 241,700 63,700 3.76
3rd Quarter 314,222 57,900 5.47
--------- -------- --------
Year to date 754,353 187,400 3.23
--------- -------- --------
First Quarter change
--------------------
2005
----
Amount $355,627 57,400 $ .56
Percentage 104% 79% 12%
2004
----
Amount $143,495 6,800 $ 1.97
Percentage 72% 10% 71%
(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 2005 and the twelve months of fiscal 2004. As the table above notes, revenue has increased approximately 104% when comparing the two three month periods ended September 30, 2004 and 2003. Volumes sold increased approximately 79%, while the price received for our product increased 12%.
Total revenue increased $396,000, or 104% when comparing the two periods, while operating and production costs increased $25,300, or 65%.
A significant ratio presented is the percentage of management fees charged to operated wells versus our general and administrative costs. This coverage of general and administrative costs improved from approximately 27% for the three months ended September 30, 2003 to approximately 48% at September 30, 2004.
When comparing general and administrative expense for 2005 and 2004, costs declined slightly by $334, or 0.2%.
Results of operations and net income are presented in the following table:
Quarterly Financial Information (unaudited)
(1) (2) Net Income (loss)
Total Operating Net Income Per Share
Revenues Income (loss) Basic Diluted
---------- ---------- ---------- --------- ---------
2005
------------------- ---------- ---------- ---------- --------- ---------
1st Quarter $ 784,299 $ 715,249 $ 389,781 $ .063 $ .061
---------- ---------- ---------- --------- ---------
2004
-------------------
lst Quarter 388,337 348,739 50,197 .010 .010
2nd Quarter 433,317 365,761 93,022 .010 .010
3rd Quarter 440,127 354,642 76,762 .010 .010
------------------- ---------- ---------- ---------- --------- ---------
Total 1,261,781 1,069,142 219,981 0.04 0.04
---------- ---------- ---------- --------- ---------
2003
-------------------
lst Quarter 264,896 223,246 (41,650) (.01) (.01)
2nd Quarter 279,080 237,155 (15,660) -- --
3rd Quarter 337,476 271,845 28,748 -- --
------------------- ---------- ---------- ---------- --------- ---------
Total $ 881,452 $ 732,246 $ (28,562) -- --
---------- ---------- ---------- --------- ---------
(1) Operating income is oil and gas sales plus management fees less direct
operating costs. (2) Before provision for deferred income taxes.
As can be seen in the table, revenues and operating income have improved in
every quarter when comparing the three month periods ended September 30, 2004
and 2003. We believe this is due to the steady increase in production volumes
sold in each subsequent quarter and the fact that we have enjoyed an
appreciating price received for our product. Operating income has increased
because production costs have increased at a lesser rate than production and
prices.
Contractual Obligations:
------------------------
We had five contractual obligations as of September 30, 2004. The following
table lists our significant liabilities at September 30, 2004:
Payments Due By Period
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Less than After
Contractual Obligations 1 year 2-3 years 4-5 years 5 years Total
----------------------- --------- --------- --------- -------- ---------
Employment Obligations $210,400 $208,300 $127,300 $ -0- $ 546,000
Bank Loans 112,500 -0- -0- -0- 112,500
Operating Leases 12,960 3,850 -0- -0- 16,810
-------- -------- -------- -------- ---------
Total contractual
cash obligations $335,860 $212,150 $127,300 $ -0- $ 675,310
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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. 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, 2004 and 2003 was $6,033 and $5,973, 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 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 . . .
