UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(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, 1998
-----------------------------------
OR
[ ] TRANSACTION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______________________ to _________________
COMMISSION FILE NUMBER 0-9946
GOLDEN OIL COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 84-0836562
(State or other jurisdiction of incorporation (I.R.S. Employer
or organization) Identification No.)
550 POST OAK BOULEVARD, SUITE 550, HOUSTON, TEXAS 77027
(Address of principal executive offices) (Zip Code)
(713) 622-8492
(Registrants telephone number, including area code)
Indicate by check mark whether the Registrant (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 the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
YES [ ] NO [X]
As of November 1, 1998, the Registrant had outstanding 1,624,291 shares of
common stock, par value $.01 per share and 22,254 shares of Class B common
stock, par value $.01 per share.
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CONTENTS
PAGE
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
- Consolidated Statements of Operations..................... 3
- Consolidated Balance Sheets............................... 5
- Consolidated Statements of Cash Flows..................... 7
- Notes to Consolidated Financial Statements................ 9
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations................. 17
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K.............................. 28
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GOLDEN OIL COMPANY
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
THREE MONTHS ENDED
SEPTEMBER 30,
-----------------------------
1998 1997
----------- -----------
Revenues:
Oil and gas production .................. $ 204,013 $ 383,254
Other ................................... 5,659 6,488
----------- -----------
Total revenues ....................... 209,672 389,742
----------- -----------
Costs and expenses:
Production costs ........................ 229,886 323,077
Pit impoundment costs, net .............. -- 4,743
Impairment loss (Note 2) ................ 450,000 --
Depreciation, depletion and
amortization .......................... 73,955 79,020
General and administrative .............. 70,950 65,506
----------- -----------
Total costs and expenses ............. 824,791 472,346
----------- -----------
(615,119) (82,604)
Gain (loss) on sale of property,
equipment and other assets .............. -- 30,000
Interest expense, net ...................... (6,070) (5,841)
Other income (expense) ..................... 2,618 (610)
----------- -----------
Net earnings (loss) ........................ $ (618,571) $ (59,055)
=========== ===========
Basic and diluted (loss) per common
share ................................... $ (.38) $ (.04)
=========== ===========
Weighted average number of
common shares and common
share equivalents outstanding ........... 1,624,291 1,430,812
=========== ===========
See Notes to Consolidated Financial Statements.
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GOLDEN OIL COMPANY
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
NINE MONTHS ENDED
SEPTEMBER 30,
-----------------------------
1998 1997
----------- -----------
Revenues:
Oil and gas production .................. $ 737,688 $ 1,221,417
Other ................................... 20,050 19,710
----------- -----------
Total revenues ....................... 757,738 1,241,127
----------- -----------
Costs and expenses:
Production costs ........................ 703,668 848,899
Pit impoundment costs, net .............. 22,681 77,509
Impairment loss (Note 2) ................ 450,000 --
Depreciation, depletion and
amortization .......................... 220,568 239,926
General and administrative .............. 207,399 230,590
----------- -----------
Total costs and expenses ............. 1,604,316 1,396,924
----------- -----------
(846,578) (155,797)
Gain (loss) on sale of property,
equipment and other assets .............. (995) 22,448
Interest expense, net ...................... (14,671) (15,484)
Other income (expense) ..................... (17,080) (2,200)
----------- -----------
Net earnings (loss) ........................ $ (879,324) $ (151,033)
=========== ===========
Basic and diluted (loss) per common
share ................................... $ (.56) $ (.11)
=========== ===========
Weighted average number of
common shares and common
share equivalents outstanding ........... 1,562,020 1,426,489
=========== ===========
See Notes to Consolidated Financial Statements.
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GOLDEN OIL COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
SEPTEMBER 30, DECEMBER 31,
1998 1997
----------- -----------
ASSETS
Current assets:
Cash and cash equivalents ................ $ 58,980 $ 178,481
Accounts receivable, net ................. 416,208 402,512
Prepaid expenses and other ............... 37,220 39,409
----------- -----------
Total current assets ................ 512,408 620,402
----------- -----------
Property and equipment, at cost:
Oil and gas properties
(using the successful efforts
method of accounting)
Producing properties ................ 5,903,032 5,867,128
Non-producing properties ............ 105,000 105,000
----------- -----------
Total oil and gas properties ........ 6,008,032 5,972,128
----------- -----------
Pipeline, field and other well
equipment ................................ 241,393 225,274
Other property and equipment ................. 341,588 413,981
----------- -----------
6,591,013 6,611,383
Less accumulated depreciation,
depletion and amortization ............... (4,344,350) (3,757,030)
----------- -----------
Net property and equipment ............... 2,246,663 2,854,353
----------- -----------
Investments, real estate ..................... 199,129 192,229
Other assets ................................. 1,481 1,481
----------- -----------
$ 2,959,681 $ 3,668,465
=========== ===========
(Continued)
See Notes to Consolidated Financial Statements.
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GOLDEN OIL COMPANY
CONSOLIDATED BALANCE SHEETS (CONTINUED)
(UNAUDITED)
SEPTEMBER 30, DECEMBER 31,
1998 1997
------------ ------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Notes payable and
current portion of long-term
debt ....................................... $ 77,779 $ 114,969
Accounts payable ............................ 1,314,595 1,201,629
Accrued expenses ............................ 291,421 290,362
------------ ------------
Total current liabilities .............. 1,683,795 1,606,960
------------ ------------
Long-term debt ................................. 147,118 24,091
Other liabilities .............................. 113,959 168,281
Commitments and contingencies
(See Notes 4 and 5) ............................ -- --
Stockholders' equity:
Preferred stock, par value $.01;
authorized 10,000,000 shares, none
issued ..................................... -- --
Common stock, par value $.01;
authorized 15,000,000 shares;
issued and outstanding; 1,624,291
shares at September 30, 1998
and 1,524,291 at December 31,
1997........................................ 16,243 15,243
Class B common stock, par value $.01
(convertible share-for-share into
common stock); authorized 3,500,000 shares;
issued and outstanding 22,254 shares at
September 30, 1998 and December 31,
1997 ....................................... 223 223
Additional paid-in capital ................... 13,907,479 13,883,479
Accumulated deficit .......................... (12,909,136) (12,029,812)
------------ ------------
Total stockholders'
equity ................................ 1,014,809 1,869,133
------------ ------------
$ 2,959,681 $ 3,668,465
============ ============
See Notes to Consolidated Financial Statements.
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GOLDEN OIL COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
NINE MONTHS ENDED
SEPTEMBER 30,
-------------------------
1998 1997
--------- ---------
Cash flows from operating activities:
Net earnings (loss) ......................... $(879,324) $(151,033)
Adjustments to reconcile net
income to net cash
provided by operating activities:
Depreciation, depletion
and amortization ......................... 220,568 239,926
Impairment loss ............................. 450,000 --
Equity in net (income) loss
of investment in commercial
realty ................................... (6,900) 3,788
Loss on sale of property
and equipment ............................ 995 7,552
Gain on sale of producing
properties ............................... -- (30,000)
Guarantee fee ............................... 25,000 --
Changes in components of working
capital:
(Increase) decrease in
accounts receivable, net .............. (13,696) (27,995)
(Increase) decrease in
prepaid expenses and other ............ 2,189 (16,839)
Increase (decrease) in
accounts payable ...................... 112,966 (181,753)
Increase (decrease) in
accrued expenses ...................... 1,059 74,558
Increase (decrease) in
other liabilities ..................... (54,322) 100,850
--------- ---------
Net cash provided by (used
in) operating activities ................. $(141,465) $ 19,054
========= =========
(Continued)
See Notes to Consolidated Financial Statements.
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GOLDEN OIL COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
(UNAUDITED)
NINE MONTHS ENDED
SEPTEMBER 30,
-------------------------
1998 1997
--------- ---------
Cash flows from investing activities:
Proceeds from sale of
property and equipment .................... $ 1,174 $ 2,662
Proceeds from sale of
producing properties ...................... -- 30,000
Additions of oil and gas
properties ................................ (35,904) (86,809)
Additions of other property
and equipment ............................. (29,143) (6,527)
Decrease in short-term
investments ............................... -- 25,000
--------- ---------
Net cash used in investing
activities ................................. $ (63,873) $ (35,674)
--------- ---------
Cash flows from financing activities:
Proceeds from issuance of
long-term debt ........................... 250,000 64,566
Payment of debt .......................... (164,163) (98,741)
Proceeds from the exercise
of stock warrants ........................ -- 20,000
--------- ---------
Net cash provided by (used in)
financing activities ........................ $ 85,837 $ (14,175)
--------- ---------
Net increase (decrease) in cash
and cash equivalents ........................ (119,501) (30,795)
Cash and cash equivalents at
beginning of period ......................... 178,481 165,209
--------- ---------
Cash and cash equivalents at
end of period ............................... $ 58,980 $ 134,414
========= =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid for interest expense was $13,941 and $15,735 for the nine months
ended September 30, 1998 and 1997, respectively. No cash was paid for federal
income taxes during the same corresponding periods.
See Notes to Consolidated Financial Statements
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING PRINCIPLES
For a summary of significant accounting principles, see Notes to
Consolidated Financial Statements and Note 1 thereof contained in the
Annual Report on Form 10-K of Golden Oil Company ("Golden" or "Company")
for the year ended December 31, 1997. The Company follows the same
accounting policies during interim periods as it does for annual reporting
purposes.
The accompanying consolidated financial statements are condensed and
unaudited and have been prepared pursuant to the rules and regulations of
the Securities and Exchange Commission ("SEC"). In the opinion of
management, the unaudited interim financial statements reflect such
adjustments as are necessary to present a fair statement of the financial
position, results of operations and cash flows for the interim periods
presented. Interim results are not necessarily indicative of a full year
of operations. Certain information and note disclosures normally included
in annual financial statements prepared in accordance with generally
accepted accounting principles have been condensed or omitted pursuant to
SEC rules and regulations; however, the Company believes that the
disclosures made are adequate to make the information presented not
misleading. These financial statements should be read in conjunction with
the financial statements and the notes thereto included in the Company's
Form 10-K for the year ended December 31, 1997.
ACCOUNTS RECEIVABLE. Amounts shown as accounts receivable are net of
$113,718 at September 30, 1998 and December 31, 1997 to reflect estimated
provisions for doubtful collection of certain non-recourse obligations
primarily in connection with certain working interest participants of
Company subsidiaries. Accounts receivable reflect net amounts due from
affiliates of $27,338 at September 30, 1998 and $17,583 at December 31,
1997.
The Company holds a limited partnership interest in its headquarters
office building. The Company accounts for this investment using the equity
method and, accordingly, the Company recognizes its pro-rata share of net
income or loss of the limited partnership in its current operating
statements.
RECLASSIFICATIONS. Certain amounts from prior periods have been
reclassified to conform to the presentation format for the 1998
Consolidated Financial Statements with no effect on reported results of
operations.
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(2) IMPAIRMENT OF LONG-LIVED ASSETS. On January 1, 1996 the Company adopted
Statement of Financial Accounting Standard ("SFAS") No. 121, "Accounting
for the Impairment of Long-lived Assets and for Long-lived Assets to be
Disposed Of." Prior to the third quarter of 1998 the adoption of this
standard had no effect on the Company's financial position, results of
operations or cash flows. However, based on the continuing and substantial
declines in oil prices that have occurred industry-wide for the past
several months and the Company's estimate of future prices it can
anticipate for its production over the next twelve months, the Company has
recorded a noncash charge to operations of $450,000 to reflect
management's estimate of future recoverable oil and gas reserves of its
San Juan Basin properties. The San Juan Basin, New Mexico properties
comprise a group of the Company's principal assets. This impairment is the
result of an industry-wide collapse in oil prices which the Company
believes could be sustained indefinitely. The Company's San Juan Basin
properties are in the latter stages of economic production and have
limited future development potential at current prices. Currently,
operations of over one-half of the Company's San Juan Basin properties
have been temporarily suspended pending an increase in prices. Unless a
substantial increase in prices occurs the Company anticipates additional
curtailments of production. Reference is made to Footnote 8 - Impact of
Industry Oil Prices and Government Regulations.
(3) CERTAIN FIXED PRICE SALE AGREEMENTS
In order to plan Company operations and as a measure of protection
against sudden declines in oil and gas prices, from time to time the
Company enters into fixed price sales contracts. Due to prices prevailing
at the time of expiration in March 1998 of its existing fixed price oil
contracts, the Company did not obtain new fixed price contracts for its
oil production. If, as and when oil prices increase from current levels
the Company anticipates that it may enter new fixed price oil contracts.
In March 1998, the Company entered into a fixed price contract for
approximately 60% of its monthly gas production in the San Juan Basin in
New Mexico. Such contract extended through October 31, 1998 at an average
price of approximately $1.99 per Mmbtu. The Company believes its fixed
price arrangements have been entered with financially capable purchasers
and does not anticipate nonperformance by counterparties to such
transactions.
(4) DEVELOPMENT OF SOUTH DOG CREEK FIELD
In March 1993, an agreement was reached between the Company and
Calumet Oil Company, the principal operators in the South Dog Creek field
in Osage County, Oklahoma. Such agreement aimed at enhancing and extending
the producing life of the field by injection of water into the
Mississippian formation in ten wells covering four separate quarter
section leases. The operators filed for a
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water injection permit with the Environmental Protection Agency ("EPA")
and, during October 1993, a field-wide water injection permit was granted
by the EPA to the Company and another interest holder and operator. During
1995 the Company initiated a limited waterflood injection program on one
of its operated leases believed to have demonstrated engineering potential
for success. Under the program certain marginal producing wells were
converted to water injectors and producing wells and well equipment were
reworked to increase the wells' fluid volume capacity. To date, the
expenditures on the waterflood project on this lease are approximately
$328,000 through September 1998, exclusive of operating fees charged by
the Company, of which the Company's share was approximately $243,000. The
Company funded its share of costs through internally generated cash flows
with the balance paid by outside working interest owners who elected to
join the project.
At current prices of oil and gas, the Company has a negative cash
flow from operations and can fund development costs only through third
party arrangements such as borrowings, asset sales, joint operations or
the like.
To date, the Osage County, Oklahoma field has not exhibited a
substantial, sustained increase in production from water injection. The
Company does not anticipate significant increases in overall production
volumes from this field unless further development can be implemented
across a more extensive area and such further development is successful.
Management plans to evaluate the results of ongoing development at various
stages before determining whether or to what extent to attempt additional
development. Current rates of total water injection, including reinjected
water, total approximately 1,600 barrels per day into three injection
wells. The Company is currently reviewing the estimated costs of various
methods to acquire or develop additional sources of water needed for
injection. The availability of source water supply is not itself expected
to be a material limiting factor in the overall project. To date the
Company has injected approximately 310,000 barrels of net new water into
the producing formation. Based on current engineering projections, at
least 650,000 net new barrels will be required to reach the level at which
localized repressurization may be expected to occur. Subject to the
availability of funds and based on indications available from the
localized response to water injection to date, the Company plans to
continue a water injection program. If in the future sufficient production
response is achieved and sustained, the Company intends to pursue a
field-wide waterflood plan. The feasibility and overall scheduling of full
scale, field-wide development for water injection remain subject to, among
other things, engineering advice based on the localized injection
summarized above; actual and projected oil prices; and the availability of
additional financing.
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Due to overall oil operations being substantially uneconomic at
current oil prices, and to other variables discussed above, the Company is
not able to assure a schedule of ongoing development, nor to provide a
definitive estimate of overall projected waterflood costs. As results are
received and analyzed, the Company will continue to review the actual and
projected overall costs of the waterflood project. Subject to the
foregoing, the Company is using a working projection for its share of
overall project costs of $750,000, inclusive of $328,000 of costs already
incurred, and is projecting total 1998 capital expenditures of $20,000 for
this project. At prevailing prices, capital expenditures for ongoing
development have been significantly reduced although water injection is
continuing. Further development is subject to possible increases in oil
and gas prices and to the availability of development funds on
economically feasible terms.
(5) ENVIRONMENTAL MATTERS
In recent years the Bureau of Land Management ("BLM") of the U.S.
Department of the Interior has implemented extensive national regulations
for the handling and maintenance of produced water from well sites on all
federal lands. The stated objective of the regulations is to provide
guidance for closure of unlined surface impoundments in a manner that
assures protection of fresh waters, public health and the environment.
Such regulations require oil and gas companies to eliminate the use of
unlined surface impoundments in the operation of wells and to remediate
and replace them with lined and enclosed surface pits. Such federal
government regulations provide for implementation on a region-by-region
basis.
In January 1997, the regions designated by the federal government
were expanded to include 80 wells in the Company's field of operations on
lands of the Jicarilla Apache Nation in New Mexico. Pursuant to the
Company's operating permit from the Jicarilla Apache Indian Nation, the
Company's operating subsidiary was required to develop a plan for
remediation and improvement for every well site. In May 1997 the BLM and
the Jicarilla Environmental Protection Office ("EPO") approved the
remediation and improvement plan ("Plan"). The Plan provided for the
remediation and enclosure of surface pits at all well sites in accordance
with Ordinance 95-0-308-03. Surface pits on 62 well sites have been
enclosed and soil remediation is complete in accordance with BLM and EPO
regulations. Work is ongoing for an additional 18 well sites. Costs for
the project, including the interests of the Company and third parties,
vary substantially by well site but have ranged between $2,000 to $10,000
per site, and are approximately $270,000 in total to date.
Remediation on all 80 well sites operated by the Company in New
Mexico was required to be completed by December 31, 1998. Numerous oil and
gas
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producers in the region, including the Company, sought extensions of such
date. Total costs are subject to a number of variable expense factors
including, among others, the cost and manner of disposal of removed soil
and the amounts of soil which may be required to be removed per site. The
Plan allows relatively broad soil disposal options; however, it is
possible that even more costly soil disposal alternatives may be deemed
necessary or may be mandated by the regulatory agencies governing the
remediation and impoundment programs.
Based upon information available at this time, the Company has
estimated the total cost to complete the entire remediation and pit
impoundment program in this region to be in the range of approximately
$450,000 to $500,000. Total costs could vary significantly from such
estimate due to numerous variable expense factors as summarized above. In
recognition of the above variables the Company charged against income a
provision reflecting its preliminary net cost estimate for such work of
approximately $106,000 as of December 31, 1997 and an additional amount of
$22,681 as of September 30, 1998. The adequacy of such provision is
reviewed periodically and may be adjusted as actual costs are incurred.
Primarily as a result of negative cash flow generated currently by
oil production operations and other materially negative factors summarized
above, it is uncertain to what extent the costs to complete the federal
government's mandated pit impoundment program may be met through
internally generated cash flow. Further, the Company may be unable to
fully recover third-party working interests' portion of pit impoundment
costs on uneconomic wells in the normal course of business. In the event
that the Company can not meet such obligations from internally generated
funds, the Company would be required to look to asset sales; additional
borrowings if possible; or to third party arrangements. Reference is made
to Footnote 8 - Impact of Industry Oil Prices and Government Regulations.
(6) INDEBTEDNESS
In April 1996 the Company entered into a credit agreement with a
commercial bank in Albuquerque, New Mexico under which the Company
rescheduled payments of existing borrowings which had fallen due for
repayment in full, and to increase its available credit from $150,000 to
$400,000. The loan agreement extended the maturity schedule of the
Company's debt to four years, subject to certain conditions, and provided
monthly payments totaling approximately $10,400 monthly through April
2000. As a condition to the new credit agreement, the lending bank
required the entire credit facility to be independently, personally
guaranteed by a person having financial capability acceptable to it,
particularly a member of the ongoing management of the Company. An officer
of the Company agreed to provide such unconditional
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personal guarantee for which the officer would receive fair compensation.
After having received delivery of the written opinion from an independent
investment banking advisor that such transaction was fair, from a
financial point of view, to the Company and its stockholders, the Board of
Directors approved the new credit agreement and the delivery to the
guarantor of warrants to purchase 250,000 unregistered shares of common
stock of the Company through March 2006 at an exercise price of $.20 per
share. During 1997 the guarantor exercised rights to purchase 100,000 such
shares. No rights have been exercised during 1998 to date.
During the second quarter of 1998 oil prices declined precipitously,
and have since reached extreme lows. As a result, the Company's oil
production operations thereupon became uneconomic and failed to generate
cash flow to pay costs including the U.S. government mandated pit
remediation program; monthly principal and interest charges under the bank
agreement; or costs of the Company's waterflood injection program at its
Osage County, Oklahoma field. In order to fund its obligations, the
Company obtained a new credit agreement under which the Company increased
its borrowings by approximately $150,000; extended its loan maturity to
July 1, 2001; and reduced monthly payment requirements to $8,200. The new
credit arrangement bears interest at 1% over the lending bank's prime
lending rate, adjusted periodically, an initial interest rate of 10.5% per
annum. Proceeds from the new financing have been applied primarily to fund
operating cash requirements; to continue the government mandated pit
impoundment program; and to maintain the ongoing waterflood project as
above.
In order to obtain such financing the Company was required by the
lending bank to provide an unconditional personal guarantee, having
substance acceptable to the bank, of repayment in full of all principal,
interest and related costs provided under the new agreement. At this time
the Company's management and the bank were concerned about factors
including the Company's lack of liquidity; the working capital deficit
exceeding one million dollars; and the rapid and severe declines in oil
prices, which drove current oil production operations into a negative cash
flow position. As a result of its financial postion, the Company was not
able to pay a cash fee to the personal guarantor of the proposed
financing. Instead, the Company agreed, subject to final approval of the
guarantee and performance by the bank lender, to pay the financing fee by
delivering to the guarantor 100,000 unregistered shares of its common
stock, and warrants to purchase 250,000 unregistered shares of the
Company's common stock, exerciseable in whole or in part through June 30,
2008 at an exercise price of $.15 per share. On June 19, 1998 the Board of
Directors ratified the execution by the Company of the bank credit
agreement and approved the payment and delivery to the guarantor of such
compensation. Prior to approving the agreement to obtain additional bank
credit and the related guarantee arrangements, the Board of Directors
retained an independent investment banking firm to advise concerning the
fairness to the
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Company and its stockholders, from a financial point of view, of the terms
proposed for payment for such guarantee. In the regular course of its
business, such investment banking firm renders advice and opinions
regarding mergers, acquisitions, financing arrangements, and cash and
share transactions for small capitalization natural resource companies. At
the meeting of the Board of Directors as above, the Board considered the
written opinion delivered to it by the independent investment banking
advisor that the proposed transaction was fair, from a financial point of
view, to the Company and its stockholders. The credit agreement and
guarantee fee were thereupon approved by the Board of Directors.
Subsequent to the close of the second quarter, 100,000 such shares were
delivered to the guarantor.
(7) DIVERSIFICATION OUTSIDE OF THE ENERGY SECTOR
During late 1993 and 1994, the Company diversified outside of the
energy sector through the purchase of a limited partnership interest in a
partnership ("Partnership") which owns the office building in Houston,
Texas in which the Company maintains its principal offices. While such
diversification appears to offer more attractive long-term opportunities
than are offered by the small oil and gas sector, the Company's ability to
arrange financing to enter any material transaction is subject to a number
of other factors and constraints, certain of which are difficult to
predict or are beyond management's control. Such factors include the
degree of the Company's future success in the waterflood development of
its proved undeveloped reserves; the future performance of oil and gas
prices, respectively; the extent of internal cash flow from operations;
and the availability of financing to support current or prospective
business operations of the Company. Reference is made to Footnote 8 -
Impact of Industry Oil Prices and Government Regulations.
The Partnership has recently advised that the general partner is
recommending the sale of such office building. However, if such a sale can
be achieved management does not anticipate it to occur in the near future.
(8) IMPACT OF INDUSTRY OIL PRICES AND GOVERNMENT REGULATIONS
The Company's operations and liquidity position have been materially
adversely affected by changes in the oil and gas industry including
increased price volatility; repeated periods of sharply lower, sometimes
uneconomic prices; and increased regulatory costs such as the BLM's
required remediation project in the San Juan Basin. In the third and
fourth quarters the Company implemented certain overhead and operating
cost reductions to reduce the impact of the above factors; however, at
prices currently prevailing for both oil and gas, the Company continues to
incur cash losses from operations monthly. Unless oil and gas prices
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improve significantly, the Company will not be able to generate positive
cash flow from operations to meet its obligations as they come due.
To fund its anticipated cash losses and to improve its liquidity,
the Company is seeking to dispose of its limited partnership interest in
the office building in Houston, Texas; however, if such a sale can be
achieved management does not anticipate it to occur in the near future.
Meanwhile, the Company may seek to obtain funds through revised
arrangements with its lenders, new financings, sales of assets other than
its limited partnership interests in the office building or other means
that may be available to the Company. If oil prices do not recover
substantially in the near term; or pit impoundment costs exceed current
estimates; or the Company is unable to obtain reimbursement of third-party
working interests' share of pit impoundment costs; or the Company is
unsuccessful in obtaining other funds to cover its anticipated cash losses
and meet its obligations as they come due, the Company may not be able to
continue as a going concern. If the foregoing circumstances develop
adversely, the Company could be required to seek protection under the
bankruptcy statutes. The accompanying financial statements have been
prepared assuming that the Company will continue as a going concern and do
not include any adjustments that might result from the outcome of these
uncertainties. Should prices recover in the near term or if the Company is
successful in obtaining additional funds, it may still seek to dispose of
its interests in some or all of its oil and gas properties so as to
reposition assets and its business focus outside oil and gas production
operations and development. Further, the Company will require additional
financing or internal cash generation in order to continue its program to
develop proved undeveloped reserves by waterflood injection, or to
continue to diversify.
Notes to Consolidated Financial Statements.
16 of 29
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
LIQUIDITY AND CAPITAL RESOURCES
DIVERSIFICATION. The Company is a somewhat diversified business whose
current scope of operations includes oil and gas operation and development and
real estate investment, but with increasing emphasis on diversification into
other sectors. Over the last several years the Company has continued to develop
its properties and has expanded through corporate transactions, primarily asset
purchases and mergers, including the purchase of an interest in a commercial
real estate venture. Management places strong emphasis on further
diversification. Subject to a number of factors including future prices of oil
and gas production and properties; the success of its ongoing secondary recovery
projects; the availability of financing; and opportunities for diversification,
the Company plans to diversify from the independent oil and gas sector.
FUNDING. The Company's operations during 1997, and to date during 1998,
have been funded primarily through borrowings under credit facilities,
internally generated funds from operating activities, and from working capital.
Material adverse changes in the oil and gas industry including increased price
volatility; repeated periods of sharply lower and uneconomic prices; and
increased regulatory costs such as the BLM's required remediation project in the
San Juan Basin have adversely affected the Company's operations and its
liquidity. The Company has implemented certain overhead and operating cost
reduction programs aimed at reducing the impact of the above factors; however,
at currently prevailing prices for both oil and gas the Company continues to
incur cash losses from operations monthly. Unless oil and gas prices improve
significantly, the Company will not be able to generate positive cash flow from
operations to meet its obligations as they come due.
To fund its anticipated cash losses and to improve its liquidity, the
Company is seeking to dispose of its limited partnership interest in the office
building in Houston, Texas; however, if such a sale can be achieved management
does not anticipate it to occur in the near future. Meanwhile, the Company may
seek to obtain funds through revised arrangements with its lenders, new
financings, sales of assets other than its limited partnership interests in the
office building or other means that may be available to the Company. If oil
prices do not recover substantially in the near term; or pit impoundment costs
exceed current estimates; or the Company is unable to obtain reimbursement of
third-party working interests' share of pit impoundment costs; or the Company is
unsuccessful in obtaining other funds to cover its anticipated cash losses and
meet its obligations as they come due, the Company may not be able to continue
as a going concern. If the foregoing circumstances develop adversely, the
Company could be required to seek protection under the bankruptcy statutes. The
accompanying financial statements have been prepared assuming that the Company
will continue as a going
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<PAGE>
concern and do not include any adjustments that might result from the outcome of
these uncertainties. Should prices recover in the near term or if the Company is
successful in obtaining additional funds, it may still seek to dispose of its
interests in some or all of its oil and gas properties so as to reposition
assets and its business focus outside oil and gas production operations and
development. Further, the Company will require additional financing or internal
cash generation in order to continue its program to develop proved undeveloped
reserves by waterflood injection, or to continue to diversify.
DECLINES IN CASH FLOW. Cash flow used in operating activities was $141,465
for the first nine months of 1998 compared to cash provided by operating
activities of $19,054 for the first nine months of 1997. The decrease from the
first nine months of 1997 is due primarily to a decrease in production revenues
resulting from the industry-wide collapse in oil prices and a significant
decline in gas prices in the first nine months of 1998 compared to the prior
year period.
FIXED PRICE CONTRACTS. In order to plan Company operations and as a
measure of protection against sudden declines in oil and gas prices, from time
to time the Company enters into fixed price sales contracts. Due to prices
prevailing at the time of expiration in March 1998 of its existing fixed price
oil contracts, the Company did not obtain new fixed price contracts for its oil
production. If, as and when oil prices increase from current levels the Company
anticipates that it may enter new fixed price oil contracts. In March 1998, the
Company entered into a fixed price contract for approximately 60% of its monthly
gas production in the San Juan Basin in New Mexico. Such contract extended
through October 31, 1998 at an average price of approximately $1.99 per Mmbtu.
The Company believes its fixed price arrangements have been entered with
financially capable purchasers and does not anticipate nonperformance by
counterparties to such transactions.
WATERFLOOD DEVELOPMENT. In March 1993, an agreement was reached between
the Company and Calumet Oil Company, the principal operators in the South Dog
Creek field in Osage County, Oklahoma. Such agreement aimed at enhancing and
extending the producing life of the field by injection of water into the
Mississippian formation in ten wells covering four separate quarter section
leases. The operators filed for a water injection permit with the Environmental
Protection Agency ("EPA") and, during October 1993, a field-wide water injection
permit was granted by the EPA to the Company and another interest holder and
operator. During 1995 the Company initiated a limited waterflood injection
program on one of its operated leases believed to have demonstrated engineering
potential for success. Under the program certain marginal producing wells were
converted to water injectors and producing wells and well equipment were
reworked to increase the wells' fluid volume capacity. To date, the expenditures
on the waterflood project on this lease are approximately $328,000 through
September 1998, exclusive of operating fees charged by the Company, of which the
Company's share was approximately $243,000. The Company funded its share of
costs through internally
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<PAGE>
generated cash flows with the balance paid by outside working interest owners
who elected to join the project.
At current prices of oil and gas, the Company has a negative cash flow
from operations and can fund development costs only through third party
arrangements such as borrowings, asset sales, joint operations or the like.
To date, the Osage County, Oklahoma field has not exhibited a
substantial, sustained increase in production from water injection. The Company
does not anticipate significant increases in overall production volumes from
this field unless further development can be implemented across a more extensive
area and such further development is successful. Management plans to evaluate
the results of ongoing development at various stages before determining whether
or to what extent to attempt additional development. Current rates of total
water injection, including reinjected water, total approximately 1,600 barrels
per day into three injection wells. The Company is currently reviewing the
estimated costs of various methods to acquire or develop additional sources of
water needed for injection. The availability of source water supply is not
itself expected to be a material limiting factor in the overall project. To date
the Company has injected approximately 310,000 barrels of net new water into the
producing formation. Based on current engineering projections, at least 650,000
net new barrels will be required to reach the level at which localized
repressurization may be expected to occur. Subject to the availability of funds
and based on indications available from the localized response to water
injection to date, the Company plans to continue a water injection program. If
in the future sufficient production response is achieved and sustained, the
Company intends to pursue a field-wide waterflood plan. The feasibility and
overall scheduling of full scale, field-wide development for water injection
remain subject to, among other things, engineering advice based on the localized
injection summarized above; actual and projected oil prices; and the
availability of additional financing.
Due to overall oil operations being substantially uneconomic at current
oil prices, and to other variables discussed above, the Company is not able to
assure a schedule of ongoing development, nor to provide a definitive estimate
of overall projected waterflood costs. As results are received and analyzed, the
Company will continue to review the actual and projected overall costs of the
waterflood project. Subject to the foregoing, the Company is using a working
projection for its share of overall project costs of $750,000, inclusive of
$328,000 of costs already incurred, and is projecting total 1998 capital
expenditures of $20,000 for this project. At prevailing prices, capital
expenditures for ongoing development have been significantly reduced although
water injection is continuing. Further development is subject to possible
increases in oil and gas prices and to the availability of development funds on
economically feasible terms.
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<PAGE>
CREDIT AGREEMENTS. In April 1996 the Company entered into a credit
agreement with a commercial bank in Albuquerque, New Mexico under which the
Company rescheduled payments of existing borrowings which had fallen due for
repayment in full, and to increase its available credit from $150,000 to
$400,000. The loan agreement extended the maturity schedule of the Company's
debt to four years, subject to certain conditions, and provided monthly payments
totaling approximately $10,400 monthly through April 2000. As a condition to the
new credit agreement, the lending bank required the entire credit facility to be
independently, personally guaranteed by a person having financial capability
acceptable to it, particularly a member of the ongoing management of the
Company. An officer of the Company agreed to provide such unconditional personal
guarantee for which the officer would receive fair compensation. After having
received delivery of the written opinion from an independent investment banking
advisor that such transaction was fair, from a financial point of view, to the
Company and its stockholders, the Board of Directors approved the new credit
agreement and the delivery to the guarantor of warrants to purchase 250,000
unregistered shares of common stock of the Company through March 2006 at an
exercise price of $.20 per share. During 1997 the guarantor exercised rights to
purchase 100,000 such shares. No rights have been exercised during 1998 to date.
During the second quarter of 1998 oil prices declined precipitously, and
have since reached extreme lows. As a result, the Company's oil production
operations thereupon became uneconomic and failed to generate cash flow to pay
costs including the U.S. government mandated pit remediation program; monthly
principal and interest charges under the bank agreement; or costs of the
Company's waterflood injection program at its Osage County, Oklahoma field. In
order to fund its obligations, the Company obtained a new credit agreement under
which the Company increased its borrowings by approximately $150,000; extended
its loan maturity to July 1, 2001; and reduced monthly payment requirements to
$8,200. The new credit arrangement bears interest at 1% over the lending bank's
prime lending rate, adjusted periodically, an initial interest rate of 10.5% per
annum. Proceeds from the new financing have been applied primarily to fund
operating cash requirements; to continue the government mandated pit impoundment
program; and to maintain the ongoing waterflood project as above.
In order to obtain such financing the Company was required by the lending
bank to provide an unconditional personal guarantee, having substance acceptable
to the bank, of repayment in full of all principal, interest and related costs
provided under the new agreement. At this time the Company's management and the
bank were concerned about factors including the Company's lack of liquidity; the
working capital deficit exceeding one million dollars; and the rapid and severe
declines in oil prices, which drove current oil production operations into a
negative cash flow position. As a result of its financial postion, the Company
was not able to pay a cash fee to the personal guarantor of the proposed
financing. Instead, the Company agreed, subject to final approval of the
guarantee and performance by the bank lender, to pay the financing fee by
delivering to
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<PAGE>
the guarantor 100,000 unregistered shares of its common stock, and warrants to
purchase 250,000 unregistered shares of the Company's common stock, exerciseable
in whole or in part through June 30, 2008 at an exercise price of $.15 per
share. On June 19, 1998 the Board of Directors ratified the execution by the
Company of the bank credit agreement and approved the payment and delivery to
the guarantor of such compensation. Prior to approving the agreement to obtain
additional bank credit and the related guarantee arrangements, the Board of
Directors retained an independent investment banking firm to advise concerning
the fairness to the Company and its stockholders, from a financial point of
view, of the terms proposed for payment for such guarantee. In the regular
course of its business, such investment banking firm renders advice and opinions
regarding mergers, acquisitions, financing arrangements, and cash and share
transactions for small capitalization natural resource companies. At the meeting
of the Board of Directors as above, the Board considered the written opinion
delivered to it by the independent investment banking advisor that the proposed
transaction was fair, from a financial point of view, to the Company and its
stockholders. The credit agreement and guarantee fee were thereupon approved by
the Board of Directors. Subsequent to the close of the second quarter, 100,000
such shares were delivered to the guarantor.
In recent years the Bureau of Land Management ("BLM") of the U.S.
Department of the Interior has implemented extensive national regulations for
the handling and maintenance of produced water from well sites on all federal
lands. The stated objective of the regulations is to provide guidance for
closure of unlined surface impoundments in a manner that assures protection of
fresh waters, public health and the environment. Such regulations require oil
and gas companies to eliminate the use of unlined surface impoundments in the
operation of wells and to remediate and replace them with lined and enclosed
surface pits. Such federal government regulations provide for implementation on
a region-by-region basis.
In January 1997, the regions designated by the federal government were
expanded to include 80 wells in the Company's field of operations on lands of
the Jicarilla Apache Nation in New Mexico. Pursuant to the Company's operating
permit from the Jicarilla Apache Indian Nation, the Company's operating
subsidiary was required to develop a plan for remediation and improvement for
every well site. In May 1997 the BLM and the Jicarilla Environmental Protection
Office ("EPO") approved the remediation and improvement plan ("Plan"). The Plan
provided for the remediation and enclosure of surface pits at all well sites in
accordance with Ordinance 95-0-308-03. Surface pits on 62 well sites have been
enclosed and soil remediation is complete in accordance with BLM and EPO
regulations. Work is ongoing for an additional 18 well sites. Costs for the
project, including the interests of the Company and third parties, vary
substantially by well site but have ranged between $2,000 to $10,000 per site,
and are approximately $270,000 in total to date.
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<PAGE>
Remediation on all 80 well sites operated by the Company in New Mexico
was required to be completed by December 1998. Numerous oil and gas producers in
the region, including the Company, sought extensions of such date. Total costs
are subject to a number of variable expense factors including, among others, the
cost and manner of disposal of removed soil and the amounts of soil which may be
required to be removed per site. The Plan allows relatively broad soil disposal
options; however, it is possible that even more costly soil disposal
alternatives may be deemed necessary or may be mandated by the regulatory
agencies governing the remediation and impoundment programs.
Based upon information available at this time, the Company has estimated
the total cost to complete the entire remediation and pit impoundment program in
this region to be in the range of approximately $450,000 to $500,000. Total
costs could vary significantly from such estimate due to numerous variable
expense factors as summarized above. In recognition of the above variables the
Company charged against income a provision reflecting its preliminary net cost
estimate for such work of approximately $106,000 as of December 31, 1997 and an
additional amount of $22,681 as of September 30, 1998. The adequacy of such
provision is reviewed periodically and may be adjusted as actual costs are
incurred.
Primarily as a result of negative cash flow generated currently by oil
production operations and other materially negative factors summarized above, it
is uncertain to what extent the costs to complete the federal government's
mandated pit impoundment program may be met through internally generated cash
flow. Further, the Company may be unable to fully recover third-party working
interests' portion of pit impoundment costs on uneconomic wells in the normal
course of business. In the event that the Company can not meet such obligations
from internally generated funds, the Company would be required to look to asset
sales; additional borrowings, if possible; or to third party arrangements.
Reference is made to Footnote 8 - Impact of Industry Oil Prices and Government
Regulations.
At September 30, 1998, the Company had a working capital deficit of
$1,171,387 compared to a working capital deficit of $986,558 at December 31,
1997, and a current ratio of .30 to 1.00 as of September 30, 1998 compared to a
current ratio of .39 to 1.00 as of December 31, 1997. The increase in the
working capital deficit at September 30, 1998 primarily reflects reduced
short-term debt resulting from refinancing the short-term debt then outstanding
offset by an increase in vendor payables resulting from a decrease in production
revenues due to the industry-wide collapse in oil prices and a significant
decline in gas prices in the first nine months of 1998.
On January 1, 1996 the Company adopted Statement of Financial Accounting
Standard ("SFAS") No. 121, "Accounting for the Impairment of Long-lived Assets
and for Long-lived Assets to be Disposed Of." Prior to the third quarter of 1998
the adoption
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<PAGE>
of this standard had no effect on the Company's financial position, results of
operations or cash flows. However, based on the continuing and substantial
declines in oil prices that have occurred industry-wide for the past several
months and the Company's estimate of future prices it can anticipate for its
production over the next twelve months, the Company has recorded a noncash
charge to operations for $450,000 to reflect management's estimate of future
recoverable oil and gas reserves of its San Juan Basin properties which comprise
a group of the Company's principal assets. This impairment is the result of an
industry-wide collapse in oil prices which the Company believes could be
sustained through the majority of 1999. Further, the Company's San Juan Basin
properties are in the latter stages of economic production and have limited
future development potential at current prices. Currently, operations of over
one-half of the Company's San Juan Basin properties have been temporarily
suspended pending an increase in prices. The Company anticipates additional
curtailments of production unless a substantial increase in prices occurs.
Reference is made to Footnote 8 - Impact of Industry Oil Prices and Government
Regulations.
Due to factors including changes in tax laws, adverse changes in the
economics of exploration drilling and the availability to the Company of
alternative uses of capital, during the late 1980s the Company curtailed
exploration activities. If the Company commences such programs in the future, it
intends to continue its previous policy of sharing exploration risks with third
party drilling participants. Certain of the Company's oil and gas leases provide
for ongoing drilling arrangements for periodic development of proved reserves.
The Company's principal development obligations under such agreements have been
suspended pending clarification of title assignments on certain federal leases.
The Company expects to obtain drilling participation from industry partners so
as to reduce the amount of the Company's required drilling commitments.
23 of 29
<PAGE>
RESULTS OF OPERATIONS
COMPARISON OF THE THREE MONTHS ENDED SEPTEMBER 30, 1998 WITH THE THREE MONTHS
ENDED SEPTEMBER 30, 1997.
REVENUES
Revenues from oil and gas production decreased from $383,254 during the
third quarter of 1997 to $204,013 in the comparable 1998 quarter, a decrease of
$179,241. The decrease is primarily attributable to a decrease in average oil
prices of $7.76 per barrel from $20.20 per barrel during the third quarter of
1997 to $12.44 per barrel during the third quarter of 1998. Fourth quarter oil
prices may be as low or lower than average prices obtained during the third
quarter. Additionally, average gas prices decreased $0.49 per mcf from $1.74 per
mcf during the third quarter of 1997 to $1.25 per mcf during the third quarter
of 1998.
Other revenues were $5,659 for the third quarter of 1998 compared to
$6,488 for the comparable period in 1997.
COSTS AND EXPENSES
Oil and gas production costs decreased by $93,191 from $323,077 for the
third quarter of 1997 to $229,886 for the same period in 1998. Such decrease is
due primarily to reduced production costs for well workovers during 1998
compared to the workover costs in the San Juan field in New Mexico during the
third quarter of 1997. Pit impoundment costs were $4,743, net of operating
charges, during the third quarter of 1997. General and administrative expenses
increased by $5,444 from $65,506 for the third quarter of 1997 to $70,950 for
the same period in 1998.
Impairment loss reflects a noncash reduction of $450,000 in the carrying
value of the Company's San Juan Basin, New Mexico properties to reflect
management's estimate based on currently prevailing prices, and in accordance
with SFAS No. 121 (Accounting for the Impairment of Long-lived Assets and for
Long-lived Assets to be Disposed of), of future recoverable oil and gas reserves
of its San Juan Basin properties. Depreciation, depletion and amortization
expenses decreased from $79,020 for the third quarter of 1997 to $73,955 for the
comparable period of 1998.
Gain on sale of property and equipment during the third quarter of 1997 of
$30,000 reflects the sale of certain non-strategic wells.
Interest expense increased by $229 from $5,841 for the third quarter of
1997 to $6,070 for the same period in 1998 reflecting increased average
borrowings outstanding.
24 of 29
<PAGE>
Primarily reflecting the factors discussed above, the Company reported a
net loss for the three months ended September 30, 1998 of $618,571 compared to a
net loss of $59,055 for the same period of 1997.
25 of 29
<PAGE>
RESULTS OF OPERATIONS
COMPARISON OF THE NINE MONTHS ENDED SEPTEMBER 30, 1998 WITH THE NINE MONTHS
ENDED SEPTEMBER 30, 1997.
REVENUES
Revenues from oil and gas production decreased from $1,221,417 during the
first nine months of 1997 to $737,688 in the comparable 1998 period, a decrease
of $483,729. The decrease is primarily attributable to a decrease in average oil
prices of $7.04 per barrel from $21.57 per barrel during the first nine months
of 1997 to $14.53 per barrel during the first nine months of 1998. Additionally,
average gas prices decreased $0.54 per mcf, from $1.86 per mcf during the first
nine months of 1997 to $1.32 per mcf during the first nine months of 1998. As a
result of the collapse of oil prices, the Company has temporarily shut-in
certain high cost, marginally producing wells in New Mexico, resulting in a 8%
decrease in the Company's total production volumes compared to the same period
in 1997.
Other revenues were $20,050 for the first nine months of 1998 compared to
$19,710 for the comparable period in 1997.
COSTS AND EXPENSES
Oil and gas production costs decreased by $145,231 from $848,899 for the
first nine months of 1997 to $703,668 for the same period in 1998. Such decrease
is primarily due to production costs associated with an above-average number of
well workovers on Company-operated properties in its San Juan field in New
Mexico in the first nine months of 1997. Pit impoundment costs were $77,509, net
of operating charges, during the first nine months of 1997 compared to $22,681
for the same period in 1998. General and administrative expenses decreased by
$23,191 from $230,590 for the first nine months of 1997 to $207,399 for the same
period in 1998.
Impairment loss reflects a noncash reduction of $450,000 in the carrying
value of the Company's San Juan Basin, New Mexico properties to reflect
management's estimate based on currently prevailing prices, and in accordance
with SFAS No. 121 (Accounting for the Impairment of Long-lived Assets and for
Long-lived Assets to be Disposed of), of future recoverable oil and gas reserves
of its San Juan Basin properties. Depreciation, depletion and amortization
expenses decreased from $239,926 for the first nine months of 1997 to $220,568
for the comparable period of 1998.
Gain on sale of property and equipment for the first nine months of 1997
of $22,448 reflects the sale of certain non-strategic wells. Loss on sale of
property and
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<PAGE>
equipment for the first nine months of 1998 of $995 reflects the sale of
property and field equipment.
Interest expense decreased by $813 from $15,484 for the first nine months
of 1997 to $14,671 for the same period in 1998 due to a decrease in average
outstanding borrowings.
Other expense during the first nine months of 1998 of $17,080 primarily
represents a guarantee fee of $25,000 for the Company's bank credit agreement.
Primarily reflecting the factors discussed above, the Company reported a
net loss for the nine months ended September 30, 1998 of $879,324 compared to a
net loss of $151,033 for the same period of 1997.
27 of 29
<PAGE>
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (MATERIAL EVENT).
(a) Exhibits
None.
(b) Reports on Form 8-K
None.
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<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
GOLDEN OIL COMPANY
Date: November 16, 1998 By: /s/ RALPH T. MCELVENNY, JR.
---------------------------
Chief Executive Officer
By: /s/ JEFFREY V. HOUSTON
---------------------------
Chief Financial and Accounting
Officer
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<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> SEP-30-1998
<CASH> 58,980
<SECURITIES> 0
<RECEIVABLES> 416,208
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 512,408
<PP&E> 6,591,013
<DEPRECIATION> (4,344,350)
<TOTAL-ASSETS> 2,959,681
<CURRENT-LIABILITIES> 1,683,795
<BONDS> 0
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<COMMON> 16,466
<OTHER-SE> 998,343
<TOTAL-LIABILITY-AND-EQUITY> 2,959,681
<SALES> 737,688
<TOTAL-REVENUES> 757,738
<CGS> 726,349
<TOTAL-COSTS> 1,604,316
<OTHER-EXPENSES> 18,075
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 14,671
<INCOME-PRETAX> (879,324)
<INCOME-TAX> 0
<INCOME-CONTINUING> (879,324)
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