UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the fiscal year ended December 31, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ______________ to ___________________.
Commission File No. 0-9946
GOLDEN OIL COMPANY
(Exact name of Registrant as specified in its charter)
DELAWARE 84-0836562
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
550 POST OAK BOULEVARD, SUITE 550, HOUSTON, TEXAS 77027
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:
(713) 622-8492
Securities registered pursuant to Section 12(b) of the Act: NONE
----
Securities registered pursuant to Section 12(g) of the Act:
COMMON STOCK, $.01 PAR VALUE
(Title of Class)
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]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
As of February 13, 1998, there were outstanding 1,524,291 shares of the
Registrant's Common Stock, $.01 par value, and the aggregate market value held
by non-affiliates was approximately $336,808.
DOCUMENTS INCORPORATED BY REFERENCE
The information called for by Part III, Items 10, 11, 12 and 13 is
incorporated herein by reference to the Registrant's definitive Proxy Statement
to be filed in connection with the Registrant's 1997 Annual Meeting within 120
days from the end of the fiscal year.
1 of 48
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PART I
ITEM 1. BUSINESS.
GENERAL DEVELOPMENT OF BUSINESS
Golden Oil Company (the "Company") is a diversified business whose
current scope of operations includes oil and gas operation and development, 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, outside of the oil and gas sector, of an interest in a
commercial real estate venture. Management places strong emphasis upon further
diversification. Subject to a number of factors including the success of its
ongoing secondary recovery projects, future prices of oil and gas production and
properties; the availability of financing; and opportunities for
diversification, management anticipates that the Company will accelerate its
plans to diversify beyond the independent oil and gas sector.
Following approval by its stockholders in 1986, the Company implemented
proposals to reincorporate in Delaware, to approve issuance of a new class of
common stock ("Class B Common") and to declare a warrant dividend on its shares
of common stock ("Common Stock"). The Class B Common has certain enhanced voting
rights compared to the Common Stock. As of December 31, 1997, the Company had
outstanding 1,524,291 shares of Common Stock and 22,254 shares of Class B
Common.
During September 1989, the Company acquired two public oil and gas
exploration and production companies by merging them into Company subsidiaries.
At the Company's Annual Meeting held during December 1989, stockholders approved
a change of the parent corporation's name to Golden Oil Company. During 1992 the
Company purchased the oil and gas related assets of Cobb Resources Corporation
("Cobb"). Due to increased eligibility requirements for initial and ongoing
listing, effective December 19, 1997 the Company's stock is no longer traded on
the National Association of Securities Dealers Automated Quotation System
("NASDAQ"). The trading market for the Company's Common Stock continues through
the facilities of the Over the Counter ("OTC") Bulletin Board market service.
The OTC Bulletin Board is electronic and screen-based with trading continuing
under the symbol "GOCO".
With regard to the oil and gas sector, the Company's objectives are to
increase its net reserves, cash flow and scope of operations primarily through
development of Company-operated properties and possible acquisitions. The
Company believes that factors including price volatility and other unfavorable
economic conditions have negatively affected the independent oil and gas
industry over recent years, and have driven operators to seek economies of scale
through consolidation and administrative cost cutting, and to diversify or
reposition operations away from oil and gas exploration and production.
Management believes that such factors may continue in the future.
Currently the Company's oil and gas production is concentrated in the
San Juan Basin, New Mexico and Osage County, Oklahoma. The Company is focusing
on controlling and enhancing the operating performance of its properties. The
Company is continuing to develop the secondary reserve potential of its
waterflood project in the South Dog Creek field in Osage County, Oklahoma.
Since initial discovery and development by the Company in the late 1970s, the
South Dog Creek field has produced over 5,000,000 barrels of primary production.
Primary production of the Company's producing properties is in the
latter stages of economic operation in both Oklahoma and New Mexico. Development
of the Company's South Dog Creek
2
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secondary reserve potential, now classified as "proved undeveloped", continues
to be accorded a high operational priority. The Company has obtained permits
from the Environmental Protection Agency ("EPA") necessary for water injection
throughout the field, and is proceeding with a staged waterflood injection
program. Under the program certain marginally producing wells have been
converted to water injectors and water supply wells while other producing wells
and well equipment have been reworked to increase the wells' fluid volume
capacity. The Company is encouraged that its joint working interest owners,
which include companies sophisticated in oil and gas operations, have elected to
join such development. Initial work has been completed on the Company's
principal lease within the field, and water is being injected at gradually
increasing volumes to monitor the effect of injection pressure on the subsurface
formation. Water injection rates currently are approximately 550 barrels per
well per day. On a cumulative basis, approximately 300,000 barrels of water have
been injected into the formation under the current program. To date, the field
has not exhibited a sustained production response from water injection; however,
this is believed to be due primarily to the low fluid levels injected to date
relative to the cumulative fluid depletion of the field. Results from
development to date indicate at least moderate improvements in production
capacity at economic levels.
The Company does not anticipate significant increases in production
volumes until further development occurs. The Company plans to continue the
development of the South Dog Creek field. The timing and extent of development
of the waterflood injection project is subject to, among other factors, the
relative magnitude of production response from the development, the availability
of additional financing for future development and prices obtainable for oil and
gas production. As of December 31, 1997 a substantial majority of the Company's
total proved reserves, approximately $8,800,000 of the Company's pretax
estimated discounted future net revenues, are classified as proved undeveloped
reserves. Since most or all proved undeveloped reserves are related to the
Oklahoma waterflood project, the success or failure of the waterflood project is
of vital importance to the Company's future.
In recent years, volatility in product prices has caused substantial
fluctuation in the year end projected value of the Company's estimated future
net revenues from oil and gas production. In the opinion of management, one
result of price fluctuations has been to diminish the general attractiveness of
onshore North American exploration drilling by small independent companies.
Other factors, such as governmental tax, general regulatory and environmental
policies, also are believed to have had a negative impact. Accordingly,
management has eliminated "wildcat" exploration drilling by the Company on
unproven acreage, while emphasizing development and extension of proved reserves
and field operations. Another effect of the many adverse economic factors
impacting the small oil and gas sector has been to increase the relative
attractiveness of diversification to reposition the Company out of the oil and
gas sector.
DESCRIPTION OF BUSINESS
OIL AND GAS OPERATIONS. As part of its business activities the Company
owns, acquires and sells oil and gas leases and other mineral interests and
produces oil and gas. In addition, the Company has conducted exploration and
development activities for its own account as well as for joint venture or
partnership accounts. If exploration is undertaken, the Company generally
attempts to include third party participants. The Company has no current plans
to conduct developmental or exploratory drilling projects during 1998 other than
with respect to further development of its waterflood injection program.
GOVERNMENT REGULATION. The domestic production and sale of oil and gas
are subject to regulation by the Department of Energy. Rates of production have
for many years been subject to federal and state conservation laws, and the
petroleum industry has been subject to federal tax laws dealing specifically
with the industry. The Company is subject to various federal, state and local
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regulations regarding, among other things, environmental and ecological
matters.In connection therewith, the Company has been significantly impacted by
the implementation of environmental regulations related to the remediation and
impoundment of surface pits for all of its San Juan Basin properties. The new
regulations have required and will require expenditures during 1997 and 1998
projected to be in the range of $350,000 - $500,000 for which the Company
estimates its share to be approximately $106,000. See Note 4 to Consolidated
Financial Statements.
EMPLOYEES. As of December 31, 1997, the Company had 11 full time
employees, including field personnel. The Company also regularly employs part
time personnel and retains outside professionals who provide accounting, legal,
engineering and other services.
COMPETITION. The Company faces intense competition in the search for and
the acquisition of oil and gas reserves; in the marketing of oil and gas
production; and in the raising of funds to purchase or develop oil and gas
properties. The Company's competitors in the oil and gas sector include
companies and individuals, many of which have financial resources, staffs and
facilities substantially greater than those of the Company.
Despite negative factors such as product price fluctuations, competition
remains intense for acquisition of oil and gas prospects and properties in the
size range which is realistic for the Company to consider. The Company's ability
to sustain or increase its oil and gas operations depends primarily on the
relative success experienced with future development of its existing properties.
Competitive conditions in marketing the Company's products are
influenced by factors including the volume of production of other domestic crude
oil and of crude oil imports; the proximity of pipelines to producing
properties; the regulation by states of allowable rates of production; and the
regulation by federal authorities of the marketing of oil and natural gas. All
of the foregoing variable factors are influenced by economic and political
forces beyond the Company's control and which cannot be predicted with
assurance.
FORWARD-LOOKING STATEMENTS. This document includes "forward-looking
statements" within the meaning of Section 27A of the Securities Act and Section
21E of the Exchange Act. All statements other than statements of historical
facts included in this document, including statements regarding planned capital
expenditures, the availability of capital resources to fund capital
expenditures, estimates of proved reserves, the Company's financial position,
business strategy and other plans and objectives for future operations, are
forward-looking statements. Although the Company believes that the expectations
reflected in such forward-looking statements are reasonable, such statements are
based upon assumptions and anticipated results that are subject to numerous
uncertainties. Actual results may vary significantly from those anticipated due
to many factors, including oil and gas prices, industry conditions, the prices
of goods and services, the availability of support services and the availability
of capital resources. In addition, the production of hydrocarbons are subject to
governmental regulations and operating risks. All subsequent written and oral
forward-looking statements attributable to the Company or persons acting on its
behalf are expressly qualified in their entirety by such factors.
ADDITIONAL INFORMATION. The Company's business does not presently
require expenditure of substantial funds for research and development. Sales of
natural gas tend to be influenced by factors including local demand and the
availability of gas transportation. Both oil and gas prices tend to respond to
seasonal weather conditions, with increased sales prices generally during the
colder winter months. The Company does not believe that any other material
aspects of its business are significantly seasonal in nature. During 1997, sales
to three purchasers accounted for approximately 48%, 30%, and 18%, respectively,
of the Company's total revenues. Sales to three purchasers accounted for
approximately 46%, 34%, and 17% for the year ended December 31, 1996 and 55%,
28%, and 14% for the year ended December 31, 1995 of the Company's total
revenues. No other customer accounted for more than ten percent of the Company's
total revenues during those periods. In the opinion of management, if the
Company should lose any of its present customers, other customers for the
4
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Company's oil and gas production would be available on terms substantially
similar to those available from its major customers at this time. Due to
volatility in oil prices and the Company's vulnerability to another severe price
downturn such as the industry experienced during 1994, the Company remains alert
to opportunities to enter into fixed price oil contracts. Beginning in December
1997, the Company had approximately 40% of its estimated monthly oil production
under a fixed price arrangement with one purchaser at an average price of $19.75
per barrel through March 1, 1998.
ITEM 2. PROPERTIES.
OFFICE FACILITIES. The Company's headquarters office is located in a
commercial office building at 550 Post Oak Boulevard, Suite 550, Houston, Texas
77027. The Company holds an interest of approximately 23% of a limited
partnership which owns such building. The Company leases 3,950 square feet of
the total of approximately 54,000 square feet of office space in the building
under a six year lease through December 15, 2002.
ESTIMATED OIL AND GAS RESERVE INFORMATION. Steven A. Hiraoka &
Associates, an independent petroleum engineering firm based in Golden, Colorado,
prepared the estimated reserve information for the Company and its wholly owned
subsidiaries for the year ended December 31, 1997. The presentation conforms
with Securities and Exchange Commission ("SEC") reporting regulations, which
require projection of estimated future net revenues based on the prices in
effect at the close of the most recent fiscal year. In conformity with SEC
reporting regulations, the reserve projections at December 31, 1997 were
prepared using an oil price ranging from $16.50 to $19.25 per barrel and gas
prices ranging from $1.15 to $2.00 per Mcf. Estimates of proved reserves based
on prices in effect at December 31, 1997 have not been filed previously by the
Company with, or included in reports to, any federal authority or agency.
Reserve estimates and estimated rates of production are inherently
uncertain and imprecise. Accordingly, all reserve data presented is subject to
continued evaluation and revision as additional information becomes available.
In this regard, it should be noted that since 1985 the petroleum industry has
experienced significant volatility in prices obtainable for oil and gas
production and that such price volatility directly affects the estimated
quantities of oil and gas reserves that are economically recoverable.
Based on the projected economics using prices prevailing on the closing
day of each respective year, the tables below set forth the Company's estimated
proved and proved developed oil and gas reserves owned by the Company as of the
close of the fiscal years indicated. The estimated proved and proved developed
oil and gas reserves shown below are based on economic assumptions and future
projections. The Company does not believe that such amounts necessarily
represent the reserve volumes or amounts which would be actually recoverable at
the respective dates shown. As of December 31, 1997 a substantial majority of
the Company's total proved reserves, approximately 1,500,000 barrels of the
Company's estimated proved reserves, are classified as proved undeveloped
reserves.
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PROVED
PROVED RESERVES DEVELOPED RESERVES
---------------------- ---------------------
AS OF OIL(BBLS) GAS(MCF) OIL(BBLS) GAS(MCF)
----------------- --------- --------- ------- ---------
December 31, 1997 (1) 2,148,061 911,823 608,849 911,823
December 31, 1996 (2) 1,613,995 1,462,734 593,756 1,462,734
December 31, 1995 (3) 1,298,253 880,158 432,133 880,158
(1) Amounts determined using oil prices ranging from $16.50 to $19.25 per
barrel of oil and gas prices ranging from $1.15 to $2.00 per Mcf.
Includes reserves of approximately 15,000 barrels of oil and 81,000 Mcf
of gas purchased in 1997 from interest holders in Company-operated
properties.
(2) Amounts determined using oil prices ranging from $23.30 to $24.60 per
barrel of oil and gas prices ranging from $1.89 to $2.75 per Mcf.
Includes reserves of approximately 51,000 barrels of oil and 232,000 Mcf
of gas purchased in 1996 from interest holders in Company-operated
properties.
(3) Amounts determined using oil prices ranging from $17.00 to $17.25 per
barrel of oil and gas prices ranging from $1.00 to $1.30 per Mcf.
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PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES
The present value of estimated future net revenues before income taxes
of proved reserves (which include reserves attributable to secondary waterflood
production) of the Company at the dates indicated below was computed according
to SEC reporting requirements by discounting the aggregate estimated future net
revenues using a discount factor of 10% per year. For additional information see
the supplemental unaudited oil and gas information.
The estimated proved and proved developed oil and gas reserves shown
below are based on economic assumptions and future projections. The Company does
not believe that such amounts necessarily represent the reserve volumes or
amounts which would be actually recoverable at the respective dates shown.
PRETAX ESTIMATED DISCOUNTED
FUTURE NET REVENUES
---------------------------------------------
TOTAL PROVED PROVED DEVELOPED PROVED
AS OF RESERVES PRODUCING UNDEVELOPED
----------------- ----------- ---------- -----------
December 31, 1997 (1) $11,529,350 $2,705,451 $ 8,824,082
December 31, 1996 (2) $16,758,460 $4,461,328 $12,297,132
December 31, 1995 (3) $ 9,089,704 $1,924,304 $ 7,165,400
(1) Amounts determined using oil prices ranging from $16.50 to $19.25 per
barrel of oil and gas prices ranging from $1.15 to $2.00 per Mcf.
Includes proved developed producing reserves with pretax estimated
discounted future net revenues of approximately $260,000 purchased in
1997 from interest holders in Company-operated properties.
(2) Amounts determined using oil prices ranging from $23.30 to $24.60 per
barrel of oil and gas prices ranging from $1.89 to $2.75 per Mcf.
(3) Amounts determined using oil prices ranging from $17.00 to $17.25 per
barrel of oil and gas prices ranging from $1.00 to $1.30 per Mcf.
SECONDARY RECOVERY
In accordance with professional engineering standards, secondary
recovery of oil and gas reserves projected to be obtainable through fluid
injection or other enhanced recovery techniques for supplementing primary
recovery are included as proved undeveloped reserves only after testing by a
pilot project or the operation of an installed program in the reservoir provides
support for the engineering analysis on which the project or program was based.
A preponderance of the Company's total proved reserves as projected above
consist of undeveloped reserve volumes and undeveloped reserve values
attributable to projected secondary recovery through waterflood development.
Currently, the Company's oil and gas production is concentrated in the
San Juan Basin, New Mexico and Osage County, Oklahoma. The Company is focusing
on controlling and enhancing the operating performance of its properties. The
Company is continuing to develop the secondary reserve potential of its
waterflood projects in the South Dog Creek field in Osage County, Oklahoma.
Since initial discovery and development by the Company in the late 1970s, the
South Dog Creek field has produced over 5,000,000 barrels of primary production.
Primary production of the Company's producing properties is in the
latter stages of economic operation in both Oklahoma and New Mexico. Development
of the Company's South Dog Creek secondary reserve potential, now classified as
"proved undeveloped", continues to be accorded a high operational priority. The
Company has obtained permits from the Environmental Protection Agency
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("EPA") necessary for water injection throughout the field, and is proceeding
with a staged waterflood injection program. Under the program certain marginally
producing wells have been converted to water injectors and water supply wells
while other producing wells and well equipment have been reworked to increase
the wells' fluid volume capacity. The Company is encouraged that its joint
working interest owners, which include companies sophisticated in oil and gas
operations, have elected to join such development. Initial work has been
completed on the Company's principal lease within the field, and water is being
injected at gradually increasing volumes to monitor the effect of injection
pressure on the subsurface formation. Water injection rates currently are
approximately 550 barrels per well per day. On a cumulative basis, approximately
300,000 barrels of water have been injected into the formation under the current
program. To date, the field has not exhibited a sustained production response
from water injection; however, this is believed to be due primarily to the low
fluid levels injected to date relative to the cumulative fluid depletion of the
field. Results from development to date indicate at least moderate improvements
in production capacity at economic levels.
The Company does not anticipate significant increases in production
volumes until further development occurs. The Company plans to continue the
development of the South Dog Creek field. The timing and extent of development
of the waterflood injection project is subject to, among other factors, the
relative magnitude of production response from the development, the availability
of additional financing for future development and prices obtainable for oil and
gas production. As of December 31, 1997 a substantial majority of the Company's
total proved reserves, approximately $8,800,000 of the Company's pretax
estimated discounted future net revenues, are classified as proved undeveloped
reserves. Since most or all proved undeveloped reserves are related to the
Oklahoma waterflood project, the success or failure of the waterflood project is
of vital importance to the Company's future.
PRODUCTIVE WELLS AND ACREAGE. As of December 31, 1997, the Company owned
working interests in 219 gross (112.8 net) wells of which there were 204 gross
(102.8 net) oil wells and 15 gross (10.1 net) gas wells. Additionally the
Company held approximately 11,090 gross (5,231 net) producing acres.
UNDEVELOPED ACREAGE. As of December 31, 1997, the Company held certain
undeveloped oil and gas leaseholds in New Mexico which covered approximately
4,520 gross and 4,140 net acres. The undeveloped acreage is held pursuant to
leases from landowners or governmental entities.
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PRODUCTION, UNIT PRICES AND COSTS. Information with respect to
production volumes, average unit prices and costs for the dates indicated are
set forth below:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------------------------------------------------------
1997 1996 1995
------------------------- ------------------------- -------------------------
Oil Gas Oil Gas Oil Gas
(Bbls) (Mcf) (Bbls) (Mcf) (BBLS) (MCF)
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Production ........... 60,594 185,859 60,998 239,512 58,626 232,655
Average Price ........ $ 20.90 $ 1.84 $ 19.56 $ 1.37 $ 17.12 $ 0.97
</TABLE>
The average production costs per unit of production (with oil and gas
converted to a common unit of measure based on six Mcf of gas to one barrel of
oil) were $12.38, $9.49 and $8.37 for the years ended December 31, 1997, 1996
and 1995, respectively. The increase in average production costs per unit of
production in 1997 as compared to 1996 is due to a significant increase in
workovers to bring previously shut-in wells into production and due to
substantial costs incurred with respect to the Company's pit impoundment project
(See Note 4 to Consolidated Financial Statements). Average production costs per
unit of production are expected to remain at present levels until completion of
the pit impoundment project which is required to be completed by December 31,
1998.
DRILLING ACTIVITY. The Company did not participate in the drilling of
any exploratory or development wells for the years ended December 31, 1997, 1996
and 1995.
ITEM 3. LEGAL PROCEEDINGS.
The Company has been named as a defendant in certain lawsuits arising in
the ordinary course of business. While the outcome of such lawsuits cannot be
predicted with certainty, management does not expect these matters to have a
material adverse effect on the financial position, cash flows and results of
operations of the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matters were submitted to vote by security holders during the fourth
quarter of 1997.
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
The Company's Common Stock was traded through the facilities of the
National Association of Securities Dealers, Inc. ("NASDAQ") through December 18,
1997. The ranges of reported high and low bid quotations for the Company's
Common Stock for each quarterly period within the two years ended December 31,
1997 are set forth below. Quotations through December 18, 1997 are as reported
by NASDAQ-small cap, the market on which the Company's Common Stock was
previously traded. Subsequent to December 18, 1997 quotations are as reported by
the Over The Counter ("OTC") Bulletin Board market service.
Due to increased NASDAQ eligibility requirements, the Company no longer
meets certain minimum asset and capital and surplus requirements for ongoing
listing and as a result the Company's Common Stock was no longer eligible for
NASDAQ listing as of December 19, 1997. The trading market for the Company's
Common Stock continues through the facilities of the OTC Bulletin Board market
service. The OTC Bulletin Board is electronic and screen-based with trading
continuing under the symbol "GOCO".
The quotations listed below do not necessarily represent actual
transactions, but represent quoted prices between dealers without retail markup,
markdown or commissions.
HIGH LOW
QUARTER ENDED BID BID
---------------- -------- --------
1997
December 31... $ 1.88 $ 0.13
September 30.. 0.59 0.13
June 30....... 0.50 0.25
March 31...... 0.63 0.19
1996
December 31... $ 1.19 $ 0.25
September 30.. 0.75 0.25
June 30....... 2.50 0.50
March 31...... 0.75 0.25
As of February 13, 1998 there were approximately 3,700 stockholders of
record of the Company's Common Stock. On March 13, 1998 the Common Stock was
listed at a range of approximately $0.19 low bid and $0.44 high bid.
The Company has not paid any cash dividends on its Common Stock and does
not expect to do so in the foreseeable future.
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ITEM 6. SELECTED FINANCIAL DATA.
The following selected financial information has been derived from, and
is qualified by reference to and should be read in conjunction with, the
Company's Consolidated Financial Statements and Notes thereto included elsewhere
herein, except that data relating to income statement information for the years
ended December 31, 1994 and 1993, and balance sheet information at December 31,
1995, 1994 and 1993 which have been derived from previously published financial
statements.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------------------------------------------
1997 1996 1995 1994 1993
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Revenues ............. $ 1,636,073 $ 1,536,601 $ 1,279,501 $ 1,612,917 $ 2,218,740
Net earnings (loss)
before cumulative
effect of accounting
change ............. (236,796) (186,390) (573,177) (1,307,407) (1,077,143)
Cumulative effect of
accounting change .. -- (39,770) -- -- --
Net loss ............. (236,796) (226,160) (573,177) (1,307,407) (1,077,143)
Basic and diluted
loss per
common share ....... (0.16) (0.16) (0.40) (0.93) (0.77)
Total assets ......... 3,668,465 3,895,561 3,943,770 4,601,419 6,212,368
Long-term debt
(including current
maturities) ....... 139,060 199,929 208,619 389,237 642,237
Stockholders' equity . $ 1,869,133 $ 2,085,929 $ 2,287,089 $ 2,840,266 $ 4,164,479
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
Golden Oil Company (the "Company") is a diversified business whose
current scope of operations includes oil and gas operation and development, 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, outside of the oil and gas sector, of an interest in a
commercial real estate venture. Management places strong emphasis upon further
diversification. Subject to a number of factors including the success of its
ongoing secondary recovery projects, future prices of oil and gas production and
properties; the availability of financing; and opportunities for
diversification, management anticipates that the Company will accelerate its
plans to diversify beyond the independent oil and gas sector. The Company's
current objectives in the oil and gas sector look primarily to waterflood
development of its proved reserves and to possible corporate transactions.
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<PAGE>
The Company expects, absent a continued decline in oil prices, to
generate cash flows from operations and financings during 1998 sufficient to
meet its operating and budgeted capital requirements. However, in order to
continue its project to develop reserves classified as proved undeveloped and to
further its plan for diversification and repositioning, the Company will be
required to make additional financing arrangements. In 1996, the Company was
advised by its commercial lenders that additional credit for the Company, or the
renewal and extension of existing bank credit, could not be granted to the
Company unless it could provide an independent third party guarantor. Such
guarantor was required to unconditionally and personally guarantee all principal
and interest loaned to the Company under the credit agreement. Such guarantee
was provided by a principal officer of the Company. The Company believes that in
order to obtain additional financing in the future, similar guarantees may be
required by lenders. The Company plans to restructure its existing loan and
increase its borrowings in 1998.
The Company expects to use proceeds from future borrowings to continue
development of the South Dog Creek waterflood program, to complete the pit
impoundment program, to meet working capital requirements, for purchases of
interests in the Company's principal areas of field operation and in connection
with transactions aimed at repositioning the Company. Based on the Company's
working capital position and oil and gas prices in March 1998, no assurances can
be made as to the availability or terms of new financing arrangements.
Accordingly, ongoing development of the Company's secondary reserve recovery
project could be delayed.
Prevailing prices obtainable for oil and gas production are dependent on
numerous factors beyond the Company's control including political, economic and
regulatory developments as well as competition from other sources of energy. The
energy markets are historically volatile and there can be no assurance that oil
and gas prices will not be subject to significant fluctuations in the future as
they have been in the past. Regardless of whether oil or gas prices increase or
decline, the Company may elect to enter corporate transactions to divest oil and
gas properties or interests; purchase or dispose of real estate interests;
recapitalize; reposition itself with new sectors of operation; or enter new
financing agreements.
Beginning in December 1997, the Company held a fixed price oil contract
for approximately 40% of its monthly oil production. Such contract extended
through March 1, 1998 at an average price at the wellhead of approximately
$19.75 per barrel. The Company plans to obtain new fixed price oil contracts in
the near future. The Company believes it enters into fixed price arrangements
with a financially capable purchasers and does not anticipate nonperformance by
counterparties to such transactions.
LIQUIDITY AND CAPITAL RESOURCES. The Company's operations during 1997
and 1996 were funded primarily through existing working capital, borrowings
under its credit facilities and internally generated funds from operating
activities. Management anticipates that to meet its major strategic and
operational objectives, the Company will need to arrange new financing through
joint ventures, additional borrowings, asset sales, or other means. There can be
no assurance as to the availability,
12
<PAGE>
timing or amount of additional financing arrangements, or any assurance that the
Company's objectives will be achieved.
Cash flow from operating activities was $132,072 for 1997 versus
$289,091 during 1996. The decrease is primarily due to expenditures associated
with pit closures in its San Juan Basin properties offset by increases in oil
and gas revenues. Such increase in revenues have been utilized primarily to fund
the ongoing waterflood development project in Oklahoma, purchase interests in
Company-operated properties and pit closure costs.
At December 31, 1997 the Company had a working capital deficit of
$987,000 and a current ratio of .39 to 1.00 compared to a working capital
deficit of $989,000 and a current ratio of .40 to 1.00 as of December 31, 1996.
The working capital deficit is relatively unchanged due primarily to the use of
cash generated from operating activities to fund capital expenditures for the
Company's secondary recovery project, the pit impoundment program, and to a
lesser extent, the purchases of additional interests in properties as discussed
above.
In April 1996, the Company entered into a credit agreement with a
commercial bank in Albuquerque, New Mexico ("Bank") under which the Company
obtained an extension of existing borrowings and increased the credit available
to it from $150,000 to $400,000. The maturity schedule of the Company's debt was
extended to four years, subject to certain conditions. As a condition of
extending the current maturity and obtaining additional credit, the Bank
required the entire credit facility to be independently, personally guaranteed
by a person acceptable to the Bank and to be collateralized by the Company's New
Mexico oil and gas properties. An officer of the Company provided the
independent, personal guarantee. The credit agreement bears interest at 2% over
the Bank's prime lending rate, adjusted periodically. Such interest rate was
11.5% at December 31, 1997.
Proceeds from the credit facility were utilized to refinance short-term
debt then outstanding; to acquire additional interests in Company-operated oil
and gas properties; and for working capital. At the time the new credit
agreement was obtained, the Company had a working capital deficit of
approximately $1,000,000. In order to obtain the new financing the Company was
required by the lending Bank to provide a personal guarantee from a principal
officer of the Company for repayment in full to the Bank of all principal,
interest and related costs. Due to its financial position, the Company was not
able to pay a cash fee for the personal guarantee required by the Bank as a
condition of extending credit to the Company. In lieu of cash payment, the
Company proposed to pay the guarantee fee by delivering to the guarantor
warrants to purchase unregistered shares of its common stock. On March 29, 1996
after obtaining the written opinion of fairness from independent investment
banking advisors, the Board of Directors approved the credit agreement and the
payment and delivery to the guarantor of warrants to purchase 250,000
unregistered shares of common stock of the Company through March 2006 for an
exercise price of $.20 per share. For the calendar year 1997 the guarantor
exercised rights to purchase 100,000 shares of common stock granted under the
warrants.
Under the Company's present credit agreement, the Company is required to
make monthly payments of principal and interest of approximately $10,400 through
April 2000. As of March 31, 1998, the Company had $59,000 remaining available
for purchases of oil and gas properties or other bank-approved uses under the
terms of the agreement.
The Company also maintained a credit facility in the original amount of
$100,000 with a commercial bank in Tulsa, Oklahoma and had borrowed $70,000
under such line of credit facility. In March 1996, the Company began reducing
the principal amount borrowed under this credit facility by $5,000 each month.
Such line of credit was retired in April 1997.
13
<PAGE>
In March 1993, an agreement was reached between the Company and Calumet
Oil Company, the principal operators in the South Dog Creek, Oklahoma field,
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 the fourth quarter of 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 marginally producing wells were converted to water injectors
and producing wells and well equipment were reworked to increase the wells'
fluid volume capacity. The cost of the initial phase of the waterflood project
on this lease approximated $305,000 through December 1997, exclusive of
operating fees charged by the Company, of which the Company's share was
approximately $226,000. 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. Management anticipates that future development
costs will be funded through a combination of internally generated funds and
additional financing.
The Company continues to gradually increase the rate of water injection
into the producing formation. To date, the field has not exhibited any
substantial, sustained increase in production from water injection and the
Company does not anticipate significant increases in overall production volumes
from the field unless further development is implemented across a more extensive
area and such further development is successful. Management will continue to
evaluate the results of current development before determining whether or to
what extent to undertake additional development. Currently, rates of total water
injection, including reinjected water, are approximately 1,600 barrels per day
into three injection wells. The Company is currently reviewing alternatives for
the acquisition or development of additional water sources for the Company's
injection plan; however, source water supply is not expected to be a material
limiting factor in the overall project. To date approximately 300,000 barrels of
new water have been injected into the producing formation. Based on the current
engineering projection, at least 650,000 new barrels will be required to reach
the level at which localized repressurization may be expected to occur. Based on
indications available from the localized response to water injection to date,
the Company plans to continue its injection program. If in the future sufficient
production response is achieved and sustained, the Company will pursue a
field-wide implementation of its waterflood plan. The feasibility and overall
scheduling of full scale, field-wide development for water injection remains
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. At this time, due to the variables
discussed above, the Company is not able 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 on the order of $750,000,
inclusive of $305,000 of costs already incurred. Subject to the availability of
funds, the Company is projecting capital expenditures in 1998 for this project
of $107,000.
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. The 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.
14
<PAGE>
In January 1997, the regions designated by the federal government were
expanded to include 81 wells in the Company's field of operations 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 initial phase of
the remediation and improvement plan ("Plan"). The initial phase of the Plan
provided for the remediation and enclosure of 14 surface pits located at the
well sites by June 30, 1997 in accordance with applicable Ordinance 95-0-308-03.
Surface pits on such well sites and on an additional 14 well sites have been
enclosed and soil remediation is complete in accordance with BLM and EPO
regulations. Work is ongoing for an additional 25 well sites. Total costs to
date of the project, including the Company's and all third parties interests,
vary by well site but have ranged between $2,000 to $10,000 per well site, or
approximately $110,000 of a total projected cost of $350,000 to $500,000.
Remediation on all well sites operated by the Company in New Mexico is
currently required to be completed by December 1998. Numerous oil and gas
producers in the region, including the Company, are seeking extensions of such
date but have not yet received them. The total cost of such work is 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 that may be required to be
removed. The Plan allows relatively broad soil disposal options; however, other
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 the preliminary 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 $350,000
to $500,000. Total costs could vary significantly from such estimate due to the
numerous variable factors discussed above. In recognition of the above variables
the Company has charged a provision reflecting its preliminary estimate of its
share of such costs, net of operating charges, of approximately $106,000 to
earnings as of December 31, 1997. The adequacy of such provision is periodically
reviewed and adjusted by the Company as actual costs are incurred. Costs to
complete the pit impoundment program are expected to be funded through
internally generated cash flows.
Due to factors including certain changes in tax law, 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 eliminated
exploration activities. If the Company undertakes further exploration programs
in the future, it intends to continue its policy of sharing exploration risks
with third party drilling participants. Certain of the Company's oil and gas
leases require 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 future required
drilling commitments. Capital expenditures for development of properties other
than the South Dog Creek field have been suspended pending additional financing.
The production and sale of oil and gas are subject to a variety of
federal, state and local government regulations, including regulations
concerning the prevention of waste, the discharge of materials into the
environment, the conservation of natural gas and oil, pollution, permits for
drilling operations, drilling bonds, reports concerning operations, the spacing
of wells, the unitization of pooling of properties and various other matters.
Many jurisdictions have at various times imposed limitations on the production
of gas and oil by restricting the rate of flow for gas and oil wells below the
actual capacity to produce. The Company believes it is in substantial compliance
with currently applicable
15
<PAGE>
environmental and other governmental laws and regulations. However, governmental
laws and regulations have continued to impose increasingly strict requirements
on companies for water and air pollution control and solid waste management. As
a result, it is likely that the Company will incur additional costs for
compliance with such regulations in the future.
RESULTS OF OPERATIONS
1997 COMPARED TO 1996. For the year ended December 31, 1997, oil and gas
revenues from production totaled $1,608,583 compared to $1,507,407 for the
previous year, a net increase of $101,176 or approximately 6.7%. The increase in
oil and gas revenue is primarily attributable to an increase in average oil
price of $1.34 per barrel from $19.56 per barrel during 1996 to $20.90 per
barrel during 1997. Additionally, average gas prices increased $0.47 per Mcf
from $1.37 per Mcf during 1996 to $1.84 per Mcf during 1997. Production volumes
for oil remained relatively unchanged at 60,594 barrels in 1997 compared to
60,998 in 1996 due to purchases of interests in Company-operated properties
offset by natural production declines. Gas volumes decreased 53,653 Mcf from
239,512 Mcf in 1996 to 185,859 Mcf in 1997 due to production downtime on certain
gas-producing wells and a significant production decline on certain high-rate
gas producing wells.
Production costs totaled $1,133,547 during 1997 compared to $957,443 in
1996, an increase of $176,104 or approximately 18.4%. Such increase is primarily
due to the production costs associated with the purchases of additional
interests in Company-operated properties, increased operating costs related to
the waterflood project in Oklahoma and an above average number of well workovers
in its San Juan Basin field in New Mexico. Pit impoundment costs, net to Golden,
to date were $105,837.
During 1997, the Company's depreciation, depletion and amortization
expense decreased to $299,709 compared to $325,502 for the prior year. Depletion
expense per equivalent unit of production increased to $2.99 per barrel in 1997
from $2.89 per barrel in 1996.
During 1997, general and administrative expenses were $332,695 compared
to $387,464 for the prior year, a decrease of $54,769 or 14.1%. The decrease is
primarily due to increased operating fees allocable to outside interest owners
in the Company's Oklahoma and New Mexico field operations.
The Company reported a net gain on the disposition of oil and gas
properties, equipment, inventory and other assets of $19,715 during 1997
compared to a net loss on the disposition of oil and gas properties, equipment,
inventory and other assets of $12,023 during 1996. The 1997 gain arose from the
sale of certain non-strategic wells and well equipment. The 1996 loss arose from
the writedown to market value of certain field equipment.
Interest expense decreased to $19,937 in 1997 compared to $24,777 in
1996 due to reductions in average principal amounts of debt outstanding during
1997.
Primarily reflecting the factors discussed above, the Company reported a
net loss for the year ended December 31, 1997 of $236,796 compared to a net loss
of $226,160 for the prior year.
1996 COMPARED TO 1995. For the year ended December 31, 1996, oil and gas
revenues from production totaled $1,507,407 compared to $1,245,986 for the
previous year, a net increase of $261,421 or approximately 21.0%. The increase
in oil and gas revenue is primarily attributable to an increase in average oil
price of $2.44 per barrel from $17.12 per barrel during 1995 to $19.56 per
barrel during 1996. Additionally, average gas prices increased $0.40 per Mcf
from $0.97 during 1995 to $1.37 during 1996. Gas production volumes increased
approximately 6,900 Mcf and oil production volumes increased approximately 2,400
barrels during 1996 compared to 1995 reflecting the effects of
16
<PAGE>
field management, weather and production from additional purchases of interests
in leases operated by the Company.
Production costs totaled $957,443 during 1996 compared to $814,841 in
1995, an increase of $142,602 or approximately 17.5%. Oil production volumes
increased to 60,998 barrels during 1996 compared to production volumes of 58,626
barrels in 1995. Gas production volumes increased to 239,512 Mcf during 1996
compared to production volumes of 232,655 in 1995. The increases in both
production costs and volumes produced are attributable to purchases of
additional interests in Company operated properties in New Mexico partially
offset by natural production decline. Production costs per barrel of oil
equivalent increased as a result of increased well maintenance costs incurred in
1996.
During 1996, the Company's depreciation, depletion and amortization
expense decreased to $325,502 compared to $508,745 for the prior year. The
decrease is primarily attributable to upward revisions of reserve estimates due
to increases in oil and gas prices and the Company changing its depletion method
on producing oil and gas properties from the property-by-property basis to the
field basis of applying the unit-of-production method. The cumulative effect of
the Company changing its method of accounting for depletion reduced income for
the year ended December 31, 1996 by $39,770. See Note 1 to the Consolidated
Financial Statements for a discussion of the change in accounting method for
depletion. Depletion expense per equivalent unit of production decreased to
$2.89 per barrel in 1996 from $4.83 per barrel in 1995.
During 1996, general and administrative expenses were $387,464 compared
to $431,701 for the prior year, a decrease of $44,237 or 10.0%. The decrease is
attributable to continuing reductions in corporate fixed costs and increases in
operating fees charged to outside working interests in Company operated
properties.
The Company reported a net loss on the disposition of oil and gas
properties, equipment, inventory and other assets of $12,023 during 1996
compared to a net gain on the disposition of oil and gas properties, equipment,
inventory and other assets of $12,576 during 1995. The 1996 loss arose from the
writedown to market value of certain field equipment. The 1995 gain arose from
the sale of non-strategic properties which the Company elected to sell due to
marginal production and limited development potential. Additionally, the Company
charged to operations in the prior year $66,142 for previously deferred property
acquisition costs.
Interest expense decreased to $24,777 in 1996 compared to $31,416 in
1995 due to reductions in average principal amounts of debt outstanding during
1996. Other income (expense) in 1996 primarily reflects the accrual of $25,000
for a guarantee fee in connection with the Company's new credit facility. See
Note 6 to the Consolidated Financial Statements.
Primarily reflecting the factors discussed above, the Company reported a
net loss for the year ended December 31, 1996 of $226,160 compared to a net loss
of $573,177 for the prior year.
RECENTLY ISSUED ACCOUNTING PRONOUCEMENTS
In June 1997, the FASB issued Statement of Financial Accounting
Standards No. 130, "Reporting Comprehensive Income" ("Statement No. 130"). The
statement establishes standards for reporting and display of comprehensive
income and its components. In June 1997, the FASB also issued Statement of
Financial Accounting Standards No. 131, "Disclosures About Segments of an
Enterprise and Related Information" ("Statement No.131"). The statement
specifies revised guidelines for determining an entity's operating and
geographic segments and the type and level of financial
17
<PAGE>
information about those segments to be disclosed. The Company will adopt the
provisions of Statements No. 130 and 131 in its 1998 financial statements.
YEAR 2000 ISSUES
Year 2000 issues result from the inability of computer programs or
computerized equipment to accurately calculate, store or use a date subsequent
to December 31, 1999. The erroneous date can be interpreted in a number of
different ways; the year 2000 may be represented as the year 1900. This could
result in a system failure or miscalculations causing disruptions of operations,
including among other things, a temporary inability to process transactions,
send invoices or engage in similar normal business.
The Company has recently completed an assessment of its financial and
operational software systems to ensure compliance. The estimated cost of
compliance is expected to be immaterial to results of operations and cash flows.
The Company believes that the potential impact, if any, of these systems not
being Year 2000 compliant will at most require employees to manually complete
otherwise automated tasks or calculations and it should not impact the Company's
ability to continue exploration, drilling, production or sales activities.
The Company plans to initiate communication with its significant
suppliers, business partners and customers to determine the extent to which the
Company is vulnerable to those third parties' failure to correct their own Year
2000 issues. There can be no guarantee, however, that the systems of other
companies on which the Company's systems rely will be timely converted, or that
a failure to convert by another company, or a conversion that is incompatible
with the Company's systems would not have a material adverse effect on the
Company. The Company has not determined its contingencies related to the Year
2000 issue with respect to products sold to third parties.
The Company has and will utilize both internal and external resources to
complete tasks and perform testing necessary to address the Year 2000 issue. The
Company does not anticipate that it will incur any significant costs relating to
the assessment and remediation of Year 2000 issues.
18
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
PAGE
----
Report of Independent Accountants ......................................... 20
Consolidated Balance Sheets ............................................... 21
Consolidated Statements of Operations ..................................... 23
Consolidated Statements of Stockholders' Equity ........................... 24
Consolidated Statements of Cash Flows ..................................... 25
Notes to Consolidated Financial Statements ................................ 28
19
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and
Stockholders of Golden Oil Company:
We have audited the consolidated financial statements and financial
statement schedule of Golden Oil Company as listed in Item 14(a) of this Form
10-K. These financial statements and financial statement schedule are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements and financial statement schedule based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the consolidated financial position of Golden
Oil Company as of December 31, 1997 and 1996, and the consolidated results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1997 in conformity with generally accepted accounting
principles. In addition, in our opinion, the financial statement schedule
referred to above, when considered in relation to the basic financial statements
taken as a whole, presents fairly, in all material respects, the information
required to be included therein.
As described in Note 1 to Consolidated Financial Statements, the Company
changed its method of accounting for depletion of its oil and gas producing
properties effective January 1, 1996.
COOPERS & LYBRAND L.L.P.
Houston, Texas
March 31, 1998
20
<PAGE>
GOLDEN OIL COMPANY
Consolidated Balance Sheets
DECEMBER 31,
----------------------------
1997 1996
----------- -----------
ASSETS
Current assets:
Cash and cash equivalents ................. 178,481 165,209
Short-term investments .................... -- 25,000
Accounts receivable:
Oil and gas sales ....................... 181,746 290,210
Joint interest operations ............... 190,677 94,111
(including allowance for
doubtful accounts of $113,718
in 1997 and $91,718 in 1996)
Affiliates and other .................... 30,089 55,903
Prepaid expenses and other ................ 39,409 35,997
----------- -----------
Total current assets .................... 620,402 666,430
----------- -----------
Property and equipment, at cost:
Oil and gas properties
(using the successful efforts
method of accounting)
Producing properties ...................... 5,867,128 5,781,349
Undeveloped leasehold costs ............... 105,000 105,000
----------- -----------
Total oil and gas properties ............ 5,972,128 5,886,349
Pipeline, field and other well
equipment ............................... 225,274 242,902
Other property and equipment .............. 413,981 468,911
----------- -----------
6,611,383 6,598,162
Less accumulated depreciation,
depletion and amortization ................ (3,757,030) (3,566,746)
----------- -----------
Net property and equipment .............. 2,854,353 3,031,416
----------- -----------
Investment, real estate ...................... 192,229 196,234
Other assets ................................. 1,481 1,481
----------- -----------
$ 3,668,465 $ 3,895,561
=========== ===========
See Notes to Consolidated Financial Statements.
21
<PAGE>
GOLDEN OIL COMPANY
Consolidated Balance Sheets (Continued)
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1997 1996
------------ ------------
<S> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Notes payable and current portion of long-term debt $ 114,969 $ 130,546
Accounts payable:
Joint interest operations ....................... 931,111 901,644
Production and other ............................ 270,518 491,340
Accrued expenses .................................. 290,362 131,496
------------ ------------
Total current liabilities ....................... 1,606,960 1,655,026
------------ ------------
Long-term debt ....................................... 24,091 69,383
Other liabilities .................................... 168,281 85,223
Commitments and contingencies (Notes 4, 9 and 10) .... -- --
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 1,524,291 shares in 1997
and 1,424,291 in 1996 ........................... 15,243 14,243
Class B convertible common stock,
par value $.01 (convertible share-for-share into
common stock); authorized 3,500,000 shares;
issued and outstanding 22,254 shares in 1997
and 1996 ........................................ 223 223
Additional paid-in capital ........................ 13,883,479 13,864,479
Accumulated deficit ............................... (12,029,812) (11,793,016)
------------ ------------
Total stockholders' equity ...................... 1,869,133 2,085,929
------------ ------------
$ 3,668,465 $ 3,895,561
============ ============
</TABLE>
See Notes to Consolidated Financial Statements.
22
<PAGE>
GOLDEN OIL COMPANY
Consolidated Statements of Operations
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------------
1997 1996 1995
----------- ----------- -----------
<S> <C> <C> <C>
Revenues:
Oil and gas production ............. $ 1,608,583 $ 1,507,407 $ 1,245,986
Other .............................. 27,490 29,194 33,515
----------- ----------- -----------
Total revenues ................... 1,636,073 1,536,601 1,279,501
----------- ----------- -----------
Costs and expenses:
Production costs ................... 1,133,547 957,443 814,841
Pit impoundment costs, net ......... 105,837 -- --
Depreciation, depletion and
amortization ..................... 299,709 325,502 508,745
General and administrative ......... 332,695 387,464 431,701
----------- ----------- -----------
Total costs and expenses ......... 1,871,788 1,670,409 1,755,287
----------- ----------- -----------
(235,715) (133,808) (475,786)
Gain (loss) on disposition of property,
equipment and other assets ......... 19,715 (12,023) 12,576
Equity in net loss of investments ..... (4,005) (9,614) (22,228)
Property acquisition costs ............ -- -- (66,142)
Interest income ....................... 641 1,254 1,092
Interest expense ...................... (19,937) (24,777) (31,416)
Other income (expense) ................ 2,505 (7,422) 8,727
----------- ----------- -----------
Net earnings (loss) before cumulative
effect of accounting change ........ (236,796) (186,390) (573,177)
Cumulative effect of accounting
change ............................. -- (39,770) --
----------- ----------- -----------
Net earnings (loss) ................... $ (236,796) $ (226,160) $ (573,177)
=========== =========== ===========
Per share data:
Basic and diluted (loss) per
common share before cumulative
effect of accounting change .... (0.16) (0.13) (0.40)
Cumulative effect of accounting
change ......................... -- (0.03) --
----------- ----------- -----------
Basic and diluted (loss) per common
share .......................... $ (0.16) $ (0.16) $ (0.40)
=========== =========== ===========
Weighted average number of
common shares outstanding ............. 1,451,140 1,424,291 1,417,606
=========== =========== ===========
</TABLE>
See Notes to Consolidated Financial Statements.
23
<PAGE>
GOLDEN OIL COMPANY
Consolidated Statements of Stockholders' Equity
<TABLE>
<CAPTION>
COMMON STOCK CLASS B COMMON STOCK ADDITIONAL TOTAL
--------------------- ---------------- PAID-IN ACCUMULATED STOCKHOLDERS'
SHARES AMOUNT SHARES AMOUNT CAPITAL DEFECIT EQUITY
---------- ------- ------- ---- ----------- ------------ -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at December 31, 1994 .......... 1,404,291 $14,043 22,254 $223 $13,819,679 $(10,993,679) $ 2,840,266
Net earnings (loss) ................... -- -- -- -- -- (573,177) (573,177)
Common stock issued to
Directors in lieu of cash ........... 20,000 200 -- -- 19,800 -- 20,000
---------- ------- ------- ---- ----------- ------------ -----------
Balance at December 31, 1995 .......... 1,424,291 14,243 22,254 223 13,839,479 (11,566,856) 2,287,089
Net earnings (loss) ................... -- -- -- -- -- (226,160) (226,160)
Warrants issued in lieu of cash ....... -- -- -- -- 25,000 -- 25,000
---------- ------- ------- ---- ----------- ------------ -----------
Balance at December 31, 1996 .......... 1,424,291 14,243 22,254 223 13,864,479 (11,793,016) 2,085,929
Net earnings (loss) ................... -- -- -- -- -- (236,796) (236,796)
Warrants exercised by Director ........ 100,000 1,000 -- -- 19,000 -- 20,000
---------- ------- ------- ---- ----------- ------------ -----------
Balance at December 31, 1997 .......... 1,524,291 $15,243 22,254 $223 $13,883,479 $(12,029,812) $ 1,869,133
========== ======= ======= ==== =========== ============ ===========
</TABLE>
See Notes to Consolidated Financial Statements.
24
<PAGE>
GOLDEN OIL COMPANY
Consolidated Statements of Cash Flows
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------------------------
1997 1996 1995
--------- --------- ---------
<S> <C> <C> <C>
Cash flows from operating activities:
Net earnings (loss) ........................................... $(236,796) $(226,160) $(573,177)
Adjustments to reconcile net
loss to net cash provided
by (used in) operating activities:
Depreciation, depletion
and amortization ............................................ 299,709 325,502 508,745
Equity in net loss of investment
in commercial realty ....................................... 4,005 9,614 22,228
Charge for deferred property
acquisition costs ........................................... -- -- 66,142
(Gain) loss on sale of
property and equipment ...................................... 10,285 12,023 (12,576)
Gain on sale of producing
properties ................................................. (30,000) -- --
Guarantee fee ................................................. -- 25,000 --
Cumulative effect of accounting
change ...................................................... -- 39,770 --
Changes in components of working
capital (Increase) decrease in
accounts receivable, net .................................. 37,712 (51,529) (15,693)
(Increase) decrease in
prepaid expenses and other ................................ (3,412) (6,770) 14,956
Increase (decrease) in
accounts payable .......................................... (191,355) 158,510 100,674
Increase (decrease) in
accrued expenses .......................................... 158,866 5,121 34,090
Increase (decrease) in other
liabilities ............................................... 83,058 (1,990) 50,000
--------- --------- ---------
Net cash provided by
operating activities ...................................... $ 132,072 $ 289,091 $ 195,389
--------- --------- ---------
</TABLE>
See Notes to Consolidated Financial Statements.
25
<PAGE>
GOLDEN OIL COMPANY
Consolidated Statements of Cash Flows (Continued)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------------------------------
1997 1996 1995
--------- --------- ---------
<S> <C> <C> <C>
Cash flows from investing activities:
Proceeds from sale of
property and equipment ................................... $ 11,814 $ 13,621 $ 27,579
Proceeds from sale of
producing properties ..................................... 30,000 -- --
Additions to oil and gas
properties ............................................... (136,798) (187,087) (59,344)
Additions to other property and
equipment ................................................ (7,947) (8,589) (7,280)
(Increase) decrease in
short-term investments ................................... 25,000 (736) (736)
--------- --------- ---------
Net cash used in
investing activities ................................. (77,931) (182,791) (39,781)
--------- --------- ---------
Cash flows from financing activities:
Proceeds from issuance of
short-term debt .......................................... -- 8,467 --
Proceeds from issuance of
long-term debt ........................................... 64,567 118,693 86,540
Payment of debt ............................................ (125,436) (135,850) (267,158)
Proceeds from the exercise of
stock warrants .......................................... 20,000 -- --
--------- --------- ---------
Net cash used in
financing activities ................................. (40,869) (8,690) (180,618)
--------- --------- ---------
Net increase (decrease) in cash
and cash equivalents ..................................... 13,272 97,610 (25,010)
Cash and cash equivalents at
beginning of year ........................................ 165,209 67,599 92,609
--------- --------- ---------
Cash and cash equivalents at
end of year .............................................. $ 178,481 $ 165,209 $ 67,599
========= ========= =========
</TABLE>
See Notes to Consolidated Financial Statements.
26
<PAGE>
GOLDEN OIL COMPANY
Consolidated Statements of Cash Flows (Continued)
Supplemental Disclosure of Cash Flow Information:
During 1995 the Company paid Director fees of $20,000 by issuing shares
of the Company's Common Stock in lieu of cash payment.
Interest charges of $20,296, $26,187 and $37,762 were paid in cash
during 1997, 1996 and 1995, respectively. The Company has a net operating loss
carryforward and was not required to make cash payments for federal income taxes
during 1997, 1996 or 1995.
27
<PAGE>
GOLDEN OIL COMPANY
Notes to Consolidated Financial Statements
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION. The consolidated financial statements of
Golden Oil Company (the "Company") include its wholly owned subsidiaries Regal
Petroleum, Ltd. ("Regal"); Spur Petroleum, Inc. ("Spur"); Golden Oil Holding
Corporation ("Holding"); and Golden Resources, Inc. ("GRI"). The Company
accounts for its commercial real estate investment under the equity method of
accounting. All significant intercompany accounts and transactions have been
eliminated in consolidation.
OIL AND GAS PROPERTIES. The Company follows the successful efforts
method of accounting for its oil and gas properties. Under the successful
efforts method, costs associated with the acquisition, drilling and equipping of
successful exploratory wells and all developmental costs, including
developmental dry holes, are capitalized and amortized using the
unit-of-production method. Geological and geophysical costs, delay rentals and
drilling costs of unsuccessful exploratory wells are charged to expense as
incurred. In the event of a substantial downturn in prices obtainable for either
oil or gas, whether temporary or permanent, the Company would be required to
provide an impairment on the carrying value of its oil and gas properties.
Proceeds from the sale of an interest in an oil and gas property are
credited to the asset account until all capitalized costs are recovered relative
to that property.
PROPERTY AND EQUIPMENT. Property and equipment are depreciated over
their estimated useful lives which range from three to ten years using the
straight line method. Expenditures for maintenance and repairs which do not
improve or extend the useful lives are charged to operations as incurred, while
expenditures for major renewals and betterments are capitalized. Dispositions of
assets are reflected at their historical cost less accumulated depreciation,
with the resulting net gain or loss reflected in operations currently.
INCOME TAXES. The Company and its wholly owned subsidiaries join in
filing consolidated federal income tax returns. Investment tax credits are
accounted for by the flow-through method.
The Company recognizes deferred income tax assets and liabilities based
on the expected future tax consequences of temporary differences between the
income tax and financial reporting carrying amounts of assets and liabilities.
CASH EQUIVALENTS. For purposes of financial statement presentation,
highly liquid instruments purchased with an original maturity of three months or
less are shown as cash equivalents.
FAIR VALUE OF FINANCIAL INSTRUMENTS. The Company's Notes to Consolidated
Financial Statements include information on fair value of its financial
instruments when such value is different from the book value. The carrying value
of cash and cash equivalents, receivables and accounts payable approximate fair
value due to the short-term maturities of these instruments. The carrying value
of the Company's credit agreements approximate fair value as the interest rates
on such instruments are variable, based on current market.
28
<PAGE>
Notes to Consolidated Financial Statements
(Continued)
SHORT-TERM INVESTMENTS. At December 31, 1997, the Company had no
short-term investments. The Company's short-term investments at December 31,
1996 consisted of 6 month certificates of deposit in federally insured banks for
which cost approximated fair market value.
PER SHARE DATA. Effective December 31, 1997, the Company retroactively
adopted the provisions of SFAS No. 128 for all periods presented. Basic earnings
per common share ("EPS") is computed by dividing net income by the
weighted-average number of common shares outstanding for the period. Diluted EPS
reflects the potential dilution that could occur if securities were exercised or
converted to common stock. Potential common shares have not been added to
compute diluted EPS as this inclusion would be antidilutive.
ACCOUNTING FOR STOCK-BASED COMPENSATION In October 1995, the FASB issued
SFAS No. 123, "Accounting for Stock-Based Compensation" which encourages, but
does not require, employers to adopt a fair value method of accounting for
employee stock-based compensation, and requires increased disclosures if expense
recognition is not adopted. The Company adopted SFAS 123 in 1996 and did not
elect expense recognition for stock options and therefore implementation of SFAS
No. 123 did not have an effect on the Company's operating results or financial
condition.
USE OF ESTIMATES. The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
See Supplemental Oil and Gas Information (Unaudited) and Note 4.
RECLASSIFICATIONS. Certain amounts from prior periods have been
reclassified to conform to the presentation format for the Company's 1997
Consolidated Financial Statements with no effect on reported results of
operations or cash flows.
ACCOUNTING CHANGE. Effective January 1, 1996 the Company changed its
depletion method on producing oil and gas properties from the
property-by-property basis to the field basis of applying the unit-of-production
method. The field basis provides for the aggregation of wells that have a common
geological reservoir or field. The Company believes that the field basis
provides a better matching of expenses with revenues over the productive life of
the properties and, therefore, that the new method is preferable to the
property-by-property basis. The cumulative effect of this change in accounting
method of $39,770 ($.03 per share) is reported in the accompanying consolidated
statements of operations. This method of computing depletion expense would have
had an immaterial impact on results of operations for the year ended December
31, 1995 had it been applied during that year.
29
<PAGE>
Notes to Consolidated Financial Statements
(Continued)
(2) OIL AND GAS PRODUCING ACTIVITIES
Shown below are the historical net capitalized costs and related
accumulated depreciation, depletion and amortization for the Company's oil and
gas properties at the dates indicated. The Company's oil and gas operations are
conducted entirely in the United States.
AT DECEMBER 31,
-----------------------------------------
1997 1996 1995
----------- ----------- -----------
Oil and gas properties:
Producing ...................... $ 5,867,128 $ 5,781,349 $ 5,847,201
Non-producing .................. 105,000 105,000 105,000
----------- ----------- -----------
5,972,128 5,886,349 5,952,201
Less accumulated depreciation,
depletion and amortization ..... (3,258,377) (3,035,795) (2,957,112)
----------- ----------- -----------
Net oil and gas properties ..... $ 2,713,751 $ 2,850,554 $ 2,995,089
=========== =========== ===========
Costs incurred in the Company's oil and gas operations and related
accumulated depletion, depreciation and amortization per equivalent unit of
production are shown below. For purposes of determining the equivalent unit of
production, six Mcf of gas production is assumed to be equivalent to production
of one barrel of oil.
AT DECEMBER 31,
----------------------------------
1997 1996 1995
-------- -------- --------
Property acquisition costs:
Producing ............................ $ 57,009 $ 88,355 $ --
Non-producing ........................ -- -- --
-------- -------- --------
57,009 88,355 --
======== ======== ========
Exploration costs ....................... -- -- --
======== ======== ========
Development costs ....................... 79,789 98,732 59,344
======== ======== ========
Depletion ............................... 273,601 291,852 470,369
======== ======== ========
Depletion per
equivalent unit of production ........ $ 2.99 $ 2.89 $ 4.83
======== ======== ========
30
<PAGE>
Notes to Consolidated Financial Statements
(Continued)
The Company's current oil and gas activities consist primarily of the
operation and development of oil and gas properties in Oklahoma and New Mexico.
At December 31, 1997 and 1996 the Company's accounts receivable, which generally
are not collateralized, were primarily from entities and individuals involved in
the oil and gas industry. The Company sells its oil and gas production on
currently available markets pursuant to contracts with various purchasers.
Generally, the purchasers of the Company's production volumes are established
oil and gas and industrial companies. The Company does not anticipate
nonperformance by the counterparties under such contracts. Beginning in December
1997, the Company had approximately 40% of its estimated monthly oil production
under fixed price arrangements with one purchaser at an average price of $19.75
per barrel through March 1, 1998. As of March 31, 1998, the Company held a fixed
price gas contract for approximately 80% of its monthly gas production at a
price of $1.99 per Mcf through August 31, 1998. During 1997 sales to three
purchasers accounted for approximately 48%, 30% and 18%, respectively, of the
Company's total revenues. For each of the two previous years, sales to three
purchasers accounted for approximately 46%, 34%, and 17% for the year ended
December 31, 1996 and 55%, 28%, and 14% for the year ended December 31, 1995 of
the Company's total revenues. No other customer accounted for more than ten
percent of the Company's total revenues during those periods.
(3) AGREEMENTS TO PURCHASE OIL AND GAS PROPERTIES
In 1993 the Company entered into an agreement to purchase proved
producing reserves in oil and gas properties in New Mexico's San Juan Basin
under which it paid a nonrefundable deposit of $42,000. Due to subsequent
declines in oil and gas prices, environmental and operational factors related to
these prospective acquisitions, the Company elected not to close on the
transaction. Accordingly, in 1995, the Company charged approximately $24,000 of
acquisition-related costs and the $42,000 deposit to operations.
(4) 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. The 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 so designated by the federal government
were expanded to include 81 wells in the Company's field of operations 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 initial phase of
the remediation and improvement plan ("Plan"). The initial phase of the Plan
provided for the remediation and enclosure of 14 surface pits located at the
well sites by June 30, 1997 in accordance with applicable Ordinance 95-0-308-03.
Surface pits on such well sites and on an additional 14 well sites have been
31
<PAGE>
Notes to Consolidated Financial Statements
(Continued)
enclosed and soil remediation is complete in accordance with BLM and EPO
regulations. Work is ongoing for an additional 25 well sites. Total costs to
date of the project including the Company's and all third parties interest vary
by well site but have ranged between $2,000 to $10,000 per well site, or
approximately $110,000 of a total projected cost of $350,000.
Remediation on all well sites operated by the Company in New Mexico is
currently required to be completed by December 1998. Numerous oil and gas
producers in the region, including the Company, are seeking extensions of such
date but have not yet received them. The total cost of such work is 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 that may be required to be
removed. The Plan allows relatively broad soil disposal options; however, other
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 the preliminary information available at this time, the
Company has estimated the total cost to complete the entire remediation and pit
enclosure program in the this region to be in the range of approximately
$350,000 to $500,000. Total costs could vary significantly from such estimate
due to the numerous variable factors discussed above. In recognition of the
above variables the Company has charged a provision reflecting its preliminary
estimate of its share of such costs, net of operating charges, of appproximately
$106,000 to earnings as of December 31, 1997. The adequacy of such provision is
periodically reviewed and adjusted by the Company as actual costs are incurred.
(5) INDEBTEDNESS
In April 1996, the Company entered into a credit agreement with a
commercial bank in Albuquerque, New Mexico ("Bank") under which the Company
obtained an extension of existing borrowings and increased the credit available
to it from $150,000 to $400,000. The maturity schedule of the Company's debt was
extended to four years, subject to certain conditions. As a condition of
extending the current maturity and obtaining additional credit, the Bank
required the entire credit facility to be independently, personally guaranteed
by a person acceptable to the Bank and to be collateralized by the Company's New
Mexico oil and gas properties. An officer of the Company provided the
independent, personal guarantee. The credit agreement bears interest at 2% over
the bank's prime lending rate, and adjusted periodically. Such interest rate was
11.5% at December 31, 1997.
Proceeds from the credit facility were utilized to refinance short-term
debt then outstanding; to acquire additional interests in Company-operated oil
and gas properties; and for working capital. At the time the new credit
agreement was obtained, the Company had a working capital deficit of
approximately $1,000,000. In order to obtain the new financing the Company was
required by the lending Bank to provide a personal guarantee from a principal
officer of the Company for repayment in full to the Bank of all principal,
interest and related costs. Due to its financial position, the Company was not
able to pay a cash fee for the personal guarantee required by the Bank as a
condition of extending credit to the Company. In lieu of cash payment, the
Company proposed to
32
<PAGE>
Notes to Consolidated Financial Statements
(Continued)
pay the guarantor fee by delivering to the guarantor warrants to purchase
unregistered shares of its common stock. On March 29, 1996 after obtaining the
written opinion of fairness from independent investment banking advisors, the
Board of Directors approved the credit agreement and the payment and delivery to
the guarantor of warrants to purchase 250,000 unregistered shares of common
stock of the Company through March 2006 for an exercise price of $.20 per share.
For the calendar year 1997 the guarantor exercised rights to purchase 100,000
shares of common stock granted under the warrants.
Under the Company's present credit agreement, the Company is required to
make monthly payments of principal and interest of approximately $10,400 through
April 2000. As of March 31, 1998, the Company had $59,000 remaining available
for purchases of oil and gas properties or bank-approved uses under the terms of
the agreement.
The Company also maintained a credit facility in the original amount of
$100,000 with a commercial bank in Tulsa, Oklahoma and had borrowed $70,000
under such line of credit facility. The line of credit bears interest at 2% over
the bank's prime lending rate, adjusted periodically. In March 1996, the Company
began reducing the principal amount borrowed under this credit facility by
$5,000 each month. Such line of credit was retired in April 1997.
(6) CAPITAL STOCK
STOCK OPTIONS. The Company has a stock option plan for key employees
(the "Employee Plan"). The Employee Plan is administered by the Stock Option
Committee which is appointed by the Board of Directors. During 1989 the Stock
Option Committee granted options covering 147,000 shares to the Company's
Chairman at an initial exercise price of $1.79 per share and exercisable in
whole or in part through December 21, 1999. During 1990 the Stock Option
Committee granted 49,000 options to other eligible employees at the same initial
exercise price and exercisable in whole or in part through April 16, 2000. No
options were granted or exercised during the years 1997, 1996 or 1995.
The Company also has a stock option plan covering 14,000 shares for the
Company's non-employee directors (the "Directors' Plan"). Under the Directors'
Plan, each non-employee director will be granted 1,400 shares per year, subject
to prior approval by the Board of Directors, at the market price on the date of
grant. Options covering such shares may be exercised any time from the date of
grant and all optioned shares must be exercised within five years from the date
of grant. No such options were granted or exercised during the years ended
December 31, 1997, 1996 or 1995.
STOCK WARRANTS. In connection with the credit arrangement executed in
April 1996 the commercial bank required the Company to provide a third party
guarantor satisfactory to the Bank as a condition of extending credit (See Note
5). As compensation, the Company issued stock warrants to the guarantor, an
officer of the Company, to purchase 250,000 unregistered shares of common stock
at $0.20 per share in lieu of cash payment to provide a personal guarantee for
the entire debt, including associated interest and other costs. The grant date
of such warrants was March 29, 1996 and they were fully vested at the date of
grant. The fair value of the warrants, estimated to be $25,000, was reflected as
additional paid-in capital and other income (expense) during 1996. As of
December 31, 1997, the guarantor had
33
<PAGE>
Notes to Consolidated Financial Statements
(Continued)
exercised rights to purchase 100,000 shares of common stock available under the
warrants for which the Company received $20,000.
CLASS B COMMON STOCK. During 1986, the stockholders of the Company
approved the issuance of a new class of common stock designated Class B Common
Stock ("Class B Common"). The holders of Class B Common, voting as a separate
class, have the right to elect a simple majority of the Board of Directors and
vote as a separate class on major corporate transactions. Holders of the Class B
Common also vote share-for-share with holders of the Common Stock. Class B
Common shares are not publicly traded, and are only transferable to persons
within defined categories of "permitted transferees", but may be converted into
Common Stock at any time on a share-for-share basis.
PREFERRED STOCK. The Company also has an authorized class of Preferred
Stock, par value $.01, of which there are currently 10,000,000 shares
authorized, with none currently issued or outstanding.
(7) EMPLOYEE BENEFIT PLAN
Effective October 12, 1997 the Company implemented a Simple Individual
Retirement Account ("IRA") Retirement Plan to all employees of the Company.
Employees may contribute up to 6% (limited to $6,000) of their gross salary and
the Company matches up to 3% (limited to $3,000) of an employee's salary,
subject to limitations imposed by the Internal Revenue Service. The Company's
contribution to the Simple IRA Retirement Plan was $6,264 for the year ended
December 31, 1997.
(8) INCOME TAXES
At December 31, 1997 the Company had aggregate net operating loss
carryforwards of approximately $10,000,000 which expire at various dates through
the year 2012, and net investment tax credit carryforwards of approximately
$170,000 which expire at various dates through the year 2000. In connection with
ownership changes resulting from certain transactions, the utilization of the
net operating loss and net investment tax credit carryforwards are limited under
Sections 382 and 383 of the Internal Revenue Code to a maximum of approximately
$7,625,000. Certain other restrictions may also exist as to the utilization of
such carryforwards. At December 31, 1997 the Company also has available federal
statutory depletion and capital loss carryforwards.
34
<PAGE>
Notes to Consolidated Financial Statements
(Continued)
The components of the Company's deferred tax assets and liabilities at
December 31, 1997 and 1996 are as follows:
DEFERRED TAX
ASSETS (LIABILITIES)
------------------------------
1997 1996
----------- -----------
Accounts receivable ...................... $ 38,664 $ 33,332
Oil and gas properties (net) ............. (390,678) (377,493)
Investment in real estate ................ 45,510 44,148
Net operating losses ..................... 3,407,707 3,680,175
Capital losses ........................... 335,504 335,504
Investment tax credit .................... 57,670 77,788
Percentage depletion ..................... 1,089,064 1,096,443
----------- -----------
Deferred tax asset ....................... 4,583,441 4,889,897
Valuation allowance ...................... (4,583,441) (4,889,897)
----------- -----------
Deferred tax assets, net ................. -- --
----------- -----------
The Company's valuation allowance increased (decreased) by approximately
($306,000), ($39,000), and $96,000 for 1997, 1996 and 1995, respectively. The
decrease in the valuation allowance in 1997 is attributable to the expiration of
prior year tax loss carryforwards partially offset by current year net operating
loss carryforwards.
(9) CERTAIN TRANSACTIONS
The Company holds as a long-term investment approximately a 23% interest
in a real estate limited partnership ("Partnership") which owns a 54,000 square
foot commercial office building. In connection with this investment, in October
1996, the Company provided its pro rata share of $25,000 as collateral under a
$100,000 standby letter of credit. Other investors, including an officer of the
Company with an ownership interest in the Partnership, provided the remaining
$75,000 collateral guarantee under such standby letter of credit. This letter of
credit was required by the Partnership's first mortgage lender as a condition to
extension and modification of the mortgage term to provide time to execute a new
mortgage agreement with a new institutional lender. A new mortgage agreement was
completed in May 1997 and the Company's collateral was released in full.
The Company leases approximately 3,950 square feet of office space in
the building of the total of approximately 54,000 square feet under a six year
lease through December 15, 2002.
In connection with establishment of an electronic data processing and
management reporting system, the Company is jointly and severally liable for a
computer hardware and software lease together with a related party that is also
jointly and severally liable for the lease obligation. The lease has a term of
five years through January, 1999 and provides for monthly payments of $3,050, of
which one-half will be paid by the Company. The Company anticipates that it will
share use of the hardware and additional software throughout such term.
35
<PAGE>
Notes to Consolidated Financial Statements
(Continued)
(10) COMMITMENTS AND CONTINGENCIES
At December 31, 1997 the aggregate future minimum lease payments under
the Company's noncancellable operating leases are:
1998 ............................... $ 68,235
1999 ............................... 51,735
2000 ............................... 50,235
2001 ............................... 50,235
2002 ............................... 48,142
Thereafter ......................... --
--------
Total .......................... $268,582
========
Rent expense for the years ended December 31, 1997, 1996 and 1995 was
$54,500, $55,500 and $57,900.
(11) UNAUDITED QUARTERLY INFORMATION
Amounts previously reported in the Company's 10-Q were restated to
accurately account for the Company's purchase of properties in New Mexico. Oil
and gas production revenues, production costs, and producing properties were
previously reported as $456,344, $551,956, and $5,855,159, respectively, as of
June 30, 1997 and for the three and six month periods then ended. These amounts
have been restated to $415,799, $525,822, and $5,840,748, respectively. The
amounts reported in the Company's 10-Q filed as of September 30, 1997 and for
the nine months then ended included the restated amounts.
End of Notes to Consolidated Financial Statements
36
<PAGE>
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
The following quantity and discounted estimates of future net cash flows
are based on prices as of the respective year ends. No price escalation was
assumed. Operating costs, production taxes, royalties and estimated future
capital expenditures to complete development of the proved reserves were
deducted in determining the quantity and discounted estimates of future net cash
flows. Such costs were estimated based on current costs and were not adjusted to
anticipate increases due to inflation or other factors. No deductions were made
for general overhead, depreciation or other indirect costs. The following table
reflects estimated quantities of proved oil and gas reserves. These reserves
have been reduced for royalty interests owned by others. These reserves are all
located in the United States and have been estimated by the Company's petroleum
engineers. The Company considers such estimates to be reasonable; however, due
to inherent uncertainties, estimates of underground reserves are imprecise and
subject to change over time as additional information becomes available.
37
<PAGE>
The estimated proved and proved developed oil and gas reserves shown
below are based on economic assumptions and future projections. The Company does
not believe that such amounts necessarily represent the reserve volumes or
amounts which would be actually recoverable at the respective dates shown.
ANALYSIS OF CHANGES IN PROVED RESERVES
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------------------------------------------------------
1997 1996 1995
---------------------- ---------------------- ---------------------
OIL GAS OIL GAS OIL GAS
(BBLS) (MCF) (BBLS) (MCF) (BBLS) (MCF)
PROVED DEVELOPED AND
UNDEVELOPED RESERVES:
<S> <C> <C> <C> <C> <C> <C>
Beginning of year ........... 1,613,995 1,462,734 1,298,253 880,158 1,477,446 1,209,079
Revisions of previous
estimates ................... 579,260 (446,352) 325,640 589,788 (120,367)(4) (96,266)
Sales of minerals in place .. -- -- -- -- (200) --
Extensions, discoveries and
other additions ............. -- -- -- -- -- --
Production .................. (60,594) (185,859) (60,998) (239,512) (58,626) (232,655)
Purchase of minerals in place 15,400 81,300 51,100 232,300 -- --
---------- ---------- ---------- ---------- ---------- ----------
End of year ................. 2,148,061(1) 911,823(1) 1,613,995(2) 1,462,734(2) 1,298,253(3) 880,158(3)
========== ========== ========== ========== ========== ==========
PROVED DEVELOPED
RESERVES:
Beginning of year ........... 593,756 1,462,734 432,133 880,158 611,326 1,209,079
========== ========== ========== ========== ========== ==========
End of year ................. 608,849(1) 911,823(1) 593,756(2) 1,462,734(2) 432,133(3) 880,158(3)
========== ========== ========== ========== ========== ==========
</TABLE>
(1) Amounts computed using oil prices ranging from $16.50 to $19.25 per
barrel and gas prices ranging from $1.15 to $2.00 per Mcf. Oil prices at
December 31, 1997 were higher than currently prevailing prices and, in
management's opinion were not indicative of prices likely to prevail
throughout 1998. As of March 15, 1998, the Company is obtaining a price
of approximately $13.00 to $14.50 per barrel of oil on sales of oil not
subject to fixed price contracts. Use of such March 15, 1998 prices in
the above projections would have decreased total reserves recoverable as
of December 31, 1997.
(2) In accordance with the reporting regulations of the SEC, total estimated
reserves at December 31, 1996 reflect oil and gas prices prevailing at
year end ranging from $23.30 to $24.60 per barrel of oil and $1.89 to
$2.75 per Mcf of gas. Oil prices at December 31, 1996 were higher than
currently prevailing prices and, in management's opinion, were not
indicative of prices likely to prevail throughout 1997. As of March 15,
1997, the Company is obtaining a price of approximately $21.00 per
barrel of oil on sales of oil not subject to fixed price contracts. Use
of such March 15, 1997 prices in the above projections would have
decreased total reserves recoverable as of December 31, 1996.
(3) Amounts computed using oil prices ranging from $17.00 to $17.25
per barrel and gas prices ranging from $1.00 to $1.30 per Mcf.
(4) In 1995, the Company made certain revisions to estimated future lease
operating expenses.
38
<PAGE>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET
CASH FLOWS AND CHANGES THEREIN
The standardized measure of discounted future net cash flows and changes
therein relating to proved oil and gas reserves is as follows:
DECEMBER 31,
-------------------------------------------------
1997 1996 1995
------------ ------------ -----------
Future cash inflows ...... $ 42,622,350 $ 43,560,590 $ 23,201,780
Future production and
development costs ..... (12,964,878) (14,541,524) (8,143,653)
Future income tax expenses (7,167,123) (6,265,135) (3,161,915)
------------ ------------ -----------
Future net cash flows .... 22,490,349 22,753,931 11,896,212
10% annual discount for
estimated timing of
cash flows .......... (13,236,249) (8,517,599) (4,690,122)
------------ ------------ -----------
Standardized measure of
discounted future net
cash flows ........... 9,254,100(1) $ 14,236,332(2)(4) $ 7,206,090(3)
============ ============ ===========
Future net cash flows were computed using year-end prices and costs, and
year end statutory tax rates that relate to existing proved oil and gas
reserves.
(1) Amounts computed using oil prices ranging from $16.50 to $19.25 per
barrel and gas prices ranging from $1.15 to $2.00 per Mcf. Oil prices at
December 31, 1997 were higher than currently prevailing prices and, in
management's opinion were not indicative of prices likely to prevail
throughout 1998. As of March 15, 1998, the Company is obtaining a price
of approximately $13.00 to $14.50 per barrel of oil on sales of oil not
subject to fixed price contracts. Use of such March 15, 1998 prices in
the above projections would have decreased total reserves recoverable as
of December 31, 1997.
(2) In accordance with the reporting regulations of the SEC, total estimated
reserves at December 31, 1996 reflect oil and gas prices prevailing at
year end ranging from $23.30 to $24.60 per barrel of oil and $1.89 to
$2.75 per Mcf of gas. Oil prices at December 31, 1996 were higher than
currently prevailing prices and, in management's opinion, were not
indicative of prices likely to prevail throughout 1997. As of March 15,
1997, the Company is obtaining a price of approximately $21.00 per
barrel of oil on sales of oil not subject to fixed price contracts. Use
of such March 15, 1997 price in the above projections would have
decreased estimated future net cash flows as of December 31, 1996.
(3) Amounts computed using oil prices ranging from $17.00 to $17.25
per barrel and gas prices ranging from $1.00 to $1.30 per Mcf.
(4) The realization of the discounted cash flows associated with the
Company's proved undeveloped reserves in the South Dog Creek field are
dependent on, among other things, the availability of financing to
complete development and the success of production response from the
waterflood injection program.
39
<PAGE>
The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
YEAR ENDED DECEMBER 31,
----------------------------------------------
1997 1996 1995
------------ ------------ -----------
Standardized measure of
discounted future net
cash flows, beginning of
year .................. $ 14,236,332 $ 7,206,090 $ 8,099,847
Sale of oil and gas
produced, net of
production costs ........ (369,199) (549,964) (413,988)
Net changes in prices and
production costs .......... (3,816,308) 3,338,005 (443,613)
Purchases of minerals in
place ..................... 250,378 1,082,136 --
Sales of minerals in place ... -- -- (2,339)
Revisions of previous quantity
estimates ................. (3,007,168)(4) 5,752,713 (1,051,461)
Net change in income taxes ... 536,432 (3,313,257) 207,659
Accretion of discount ........ 1,423,633 720,609 809,985
------------ ------------ -----------
Standardized measure of
discounted future net
cash flows, end of year $ 9,254,100(1) $ 14,236,332(2) $ 7,206,090(3)
============ ============ ===========
Future net cash flows were computed using year end prices and costs, and
year end statutory tax rates that relate to existing proved oil and gas
reserves.
40
<PAGE>
(1) Amounts computed using oil prices ranging from $16.50 to $19.25 per
barrel and gas prices ranging from $1.15 to $2.00 per Mcf. Oil prices at
December 31, 1997 were higher than currently prevailing prices and, in
management's opinion were not indicative of prices likely to prevail
throughout 1998. As of March 15, 1998, the Company is obtaining a price
of approximately $13.00 to $14.50 per barrel of oil on sales of oil not
subject to fixed price contracts. Use of such March 15, 1998 prices in
the above projections would have decreased total reserves recoverable as
of December 31, 1997.
(2) In accordance with the reporting regulations of the SEC, total estimated
reserves at December 31, 1996 reflect oil and gas prices prevailing at
year end ranging from $23.30 to $24.60 per barrel of oil and $1.89 to
$2.75 per Mcf of gas. Oil prices at December 31, 1996 were higher than
currently prevailing prices and, in management's opinion, were not
indicative prices likely to prevail in 1997. As of March 15, 1997, the
Company is obtaining a price of approximately $21.00 per barrel of oil
on sales of oil not subject to fixed price contracts. Use of such March
15, 1997 price in the above projections would have decreased estimated
future net cash flows as of December 31, 1996.
(3) Amounts computed using oil prices ranging from $17.00 to $17.25 per
barrel and gas prices ranging from $1.00 to $1.30 per Mcf.
(4) Estimated proved reserve volumes increased 534,066 barrels from
1,613,995 barrels in 1996 to 2,148,061 barrels in 1997. However, the
discounted future net cash flows pertaining to revisions of previous
quantity estimates decreased as a result of revisions in the timing of
production. Such revisions in the timing of production are related to
proved undeveloped reserves of the waterflood project.
41
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The definitive Proxy Statement in connection with the 1997 Annual
Meeting of Stockholders to be filed by the Company pursuant to Regulation 14A of
the Securities Exchange Act of 1934 is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION.
The definitive Proxy Statement in connection with the 1997 Annual
Meeting of Stockholders to be filed by the Company pursuant to Regulation 14A of
the Securities Exchange Act of 1934 is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The definitive Proxy Statement in connection with the 1997 Annual
Meeting of Stockholders to be filed by the Company pursuant to Regulation 14A of
the Securities Exchange Act of 1934 is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The definitive Proxy Statement in connection with the 1997 Annual
Meeting of Stockholders to be filed by the Company pursuant to Regulation 14A of
the Securities Exchange Act of 1934 is incorporated herein by reference.
42
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
PAGE
----
(a) 1. The following consolidated financial statements are
included in Part II, Item 8:
Report of Independent Accountants......................... 20
CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Balance Sheets as of
December 31, 1997 and 1996.................................. 21
Consolidated Statements of Operations for the
years ended December 31, 1997, 1996 and 1995................ 23
Consolidated Statements of Stockholders' Equity
for the years ended December 31, 1997, 1996 and
1995........................................................ 24
Consolidated Statements of Cash Flows for the
years ended December 31, 1997, 1996 and 1995................ 25
Notes to Consolidated Financial Statements.................. 28
2. FINANCIAL STATEMENT SCHEDULES:
Schedule II Valuation and Qualifying Accounts............... 46
All other schedules are omitted because they are not
applicable or the information is included in the financial
statements and notes included herewith.
(b) REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the Company's
last fiscal quarter of 1997.
(c) EXHIBITS
3. The following exhibits are filed as part of this report.
Where such filing is made by incorporation by reference to
a previously filed statement or report, such statement or
report is identified in parenthesis.
ARTICLES OF INCORPORATION AND BYLAWS
3.1 Articles of Incorporation (incorporated by reference to Exhibit
3 of Form 10-K for the year ended December 31, 1985).
3.2 Bylaws (incorporated by reference to Exhibit 3 of Form 10-K
for the year ended December 31, 1985).
10. MATERIAL CONTRACTS
43
<PAGE>
10.1 Pinnacle Petroleum, Inc. Amended and Restated Employees' Stock
Option Plan (incorporated by reference from Exhibit I to
Pinnacle Petroleum, Inc. Proxy Statement dated November 29,
1989).
10.2 Directors' Stock Option Plan (incorporated by reference from
Exhibit II to Pinnacle Petroleum, Inc. Proxy Statement dated
November 29, 1989).
10.3 Agreement and Plan for Merger by and between Golden Oil Company,
Golden Oil Holding Corporation and Cobb Resources Corporation
dated November 28, 1990 (incorporated by reference from Exhibit
1 to Form 8-K dated November 28, 1990).
10.4 Stock Option Agreement between Golden Oil Company and Cobb
Resources Corporation dated November 28, 1990 (incorporated by
reference from Exhibit 2 to Form 8-K dated November 28, 1990).
10.5 Directors Agreement among George O. Lotspeich, B. W. Miller,
Malcolm G. Colberg, William J. Mayhew, Frank J. Yeager, Ralph T.
McElvenny, Jr., Anthony B. Petrelli and Golden Oil Company dated
November 28, 1990 (incorporated by reference from Exhibit 4 to
Form 8-K dated November 28, 1990).
10.6 Asset Purchase Agreement, dated April 5, 1991, by and between
Golden Oil Company, Cobb Resources Corporation and Chace Oil
Company, Inc. (incorporated by reference from Exhibit 10.13 to
Cobb Resources Corporation Form 10-K for the year ended June 30,
1991).
10.7 Shareholders Agreement, dated as of April 5, 1991, between
Golden Oil Company, Cobb Resources Corporation, Horace F. McKay,
Jr. George O. Lotspeich and Frank J. Yeager (incorporated by
reference from Exhibit 10.15 to Cobb Resources Corporation Form
10-K for the year ended June 30, 1991).
10.8 Amendment No. 1 to Directors Agreement, dated as of April 5,
1991, between Golden Oil Company and Malcolm G. Colberg, George
O. Lotspeich, William J. Mayhew, Ralph T. McElvenny, Jr., B. W.
Miller, Anthony B. Petrelli and Frank J. Yeager (incorporated by
reference from Exhibit 10.17 to Cobb Resources Corporation Form
10-K for the year ended June 30, 1991).
10.9 Amendment No. 1 to Asset Purchase Agreement, dated June 25,
1991, by and between Golden Oil Company, Cobb Resources
Corporation and Chace Oil Company, Inc. (incorporated by
reference from Exhibit 10.14 to Cobb Resources Corporation Form
10-K for the year ended June 30, 1991).
10.10 Amendment No. 2 to Asset Purchase Agreement, dated as of
September 30, 1991, by and between Golden Oil Company, Cobb
Resources Corporation and Chace Oil Company, Inc. (incorporated
by reference from Exhibit 10.18 to Cobb Resources Corporation
10-K for the year ended June 30, 1991).
10.11 Stock Purchase Agreement, dated October 16, 1992, by and between
Golden Oil Company, Cobb Resources Corporation, and Charles Cobb
IV (incorporated by reference from Exhibit 10.11 to Form 10-K
for the year ended December 31, 1992).
10.12 Warrant to Purchase Shares of Common Stock, dated March 29, 1996
by and between Golden Oil Company and Ralph T. McElvenny, Jr.
(filed herewith).
44
<PAGE>
10.13. Note Agreement dated April 12, 1996 by and between Golden Oil
Company, Ralph T. McElvenny, Jr. and Western Bank of
Albuquerque, New Mexico (filed herewith).
22.1 SUBSIDIARIES OF THE COMPANY (filed herewith).
45
<PAGE>
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
<TABLE>
<CAPTION>
ADDITIONS ADDITIONS
BALANCE AT CHARGED TO CHARGED TO BALANCE
BEGINNING COSTS AND OTHER AT END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS (1) PERIOD
----------- --------- -------- -------- -------------- ------
<S> <C> <C> <C>
Year Ended December 31, 1995
Allowance for doubtful
accounts ....................$ 89,363 -- -- (16,245) $ 73,118
------ ------ -------- ------- --------
Year Ended December 31, 1996
Allowance for doubtful
accounts ....................$ 73,118 22,153 -- (3,553) $ 91,718
------ ------ -------- ------- --------
Year Ended December 31, 1997
Allowance for doubtful
accounts ....................$ 91,718 22,000 -- -- $113,718
------ ------ -------- ------- --------
</TABLE>
(1) Accounts written off, net of recoveries and allowance adjustment.
46
<PAGE>
GOLDEN OIL COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Company has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
GOLDEN OIL COMPANY
Date: March 31, 1998 By: /s/ RALPH T. McELVENNY, JR.
---------------------------
Ralph T. McElvenny, Jr.,
Director
Chief Executive Officer
Date: March 31, 1998 By: /s/ JEFFREY V. HOUSTON
-----------------------
Jeffrey V. Houston
Principal Financial and
Accounting Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Company and in the capacities and on the dates indicated.
Date: March 31, 1998 By: /s/ DARRYL L. EMMERT
---------------------
Darryl L. Emmert, Director
Date: March 31, 1998 By: /s/ RALPH T. McELVENNY, JR.
---------------------------
Ralph T. McElvenny, Jr.,
Director
Chief Executive Officer
Date: March 31, 1998 By: /s/ FRANK J. YEAGER
-------------------
Frank J. Yeager, Director
47
GOLDEN OIL COMPANY
EXHIBIT 22.1
NAME OF SUBSIDIARY STATE OF INCORPORATION
- ------------------ ----------------------
Golden Oil Holding Corporation Delaware
Golden Resources, Inc. Delaware
Regal Petroleum, Ltd. Delaware
Spur Petroleum, Inc. Texas
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THE FINANCIAL DATA SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION
EXTRACTED FROM FORM 10K FOR THE FISCAL YEAR ENDED 12/31/97
AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 178,481
<SECURITIES> 0
<RECEIVABLES> 402,512
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 620,402
<PP&E> 6,611,383
<DEPRECIATION> (3,757,030)
<TOTAL-ASSETS> 3,668,465
<CURRENT-LIABILITIES> 1,606,690
<BONDS> 0
0
0
<COMMON> 15,466
<OTHER-SE> 1,853,667
<TOTAL-LIABILITY-AND-EQUITY> 3,668,465
<SALES> 1,608,583
<TOTAL-REVENUES> 1,636,073
<CGS> 1,239,384
<TOTAL-COSTS> 1,871,788
<OTHER-EXPENSES> (18,856)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 19,937
<INCOME-PRETAX> (236,796)
<INCOME-TAX> 0
<INCOME-CONTINUING> (236,796)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (236,796)
<EPS-PRIMARY> (.16)
<EPS-DILUTED> (.16)
</TABLE>
