UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended MARCH 31, 1998
----------------------------------
OR
[ ] TRANSACTION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______________________ to
COMMISSION FILE NUMBER 0-9946
GOLDEN OIL COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 84-0836562
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
550 POST OAK BOULEVARD, SUITE 550, HOUSTON, TEXAS 77027
(Address of principal executive offices) (Zip Code)
(713) 622-8492
(Registrants telephone number, including area code)
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
YES NO X
As of May 1, 1998, the Registrant had outstanding 1,524,291 shares of
common stock, par value $.01 per share and 22,254 shares of Class B common
stock, par value $.01 per share.
Page 1 of 21
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CONTENTS
PAGE
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
- Consolidated Statements of Operations..................... 3
- Consolidated Balance Sheets............................... 4
- Consolidated Statements of Cash Flows..................... 6
- Notes to Consolidated Financial Statements................ 8
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations................. 14
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K.............................. 20
Page 2 of 21
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GOLDEN OIL COMPANY
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
-------------------------
1998 1997
----------- -----------
Revenues:
Oil and gas production ........................ $ 275,152 $ 422,364
Other ......................................... 7,982 6,336
----------- -----------
Total revenues ............................. 283,134 428,700
----------- -----------
Costs and expenses:
Production costs .............................. 264,133 284,074
Pit impoundment costs, net .................... 22,681 22,502
Depreciation, depletion and
Amortization ................................ 73,059 81,563
General and administrative .................... 40,662 65,708
----------- -----------
Total costs and expenses ................... 400,535 453,847
----------- -----------
(117,401) (25,147)
Gain (loss) on sale of property,
equipment and other assets .................... (1,995) --
Interest expense, net ............................ (3,890) (6,339)
Other income (expense) ........................... 5,471 893
----------- -----------
Net earnings (loss) .............................. $ (117,815) $ (30,593)
Basic and diluted (loss) per common
share ......................................... $ (.08) $ (.02)
=========== ===========
Weighted average number of
common shares and common
share equivalents outstanding ................. 1,524,291 1,424,291
=========== ===========
See Notes to Consolidated Financial Statements.
Page 3 of 21
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GOLDEN OIL COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
MARCH 31, DECEMBER 31,
1998 1997
----------- -----------
ASSETS
Current assets:
Cash and cash equivalents ................ $ 50,428 $ 178,481
Accounts receivable, net ................. 381,638 402,512
Prepaid expenses and other ............... 31,807 39,409
----------- -----------
Total current assets ................ 463,873 620,402
----------- -----------
Property and equipment, at cost:
Oil and gas properties
(using the successful efforts
method of accounting)
Producing properties ................ 5,877,511 5,867,128
Non-producing properties ............ 105,000 105,000
----------- -----------
Total oil and gas properties ........ 5,982,511 5,972,128
----------- -----------
Pipeline, field and other well
equipment ................................ 225,590 225,274
Other property and equipment ................. 341,588 413,981
----------- -----------
6,549,689 6,611,383
Less accumulated depreciation,
depletion and amortization ............... (3,756,842) (3,757,030)
----------- -----------
Net property and equipment ............... 2,792,847 2,854,353
----------- -----------
Investments, real estate ..................... 194,529 192,229
Other assets ................................. 1,481 1,481
----------- -----------
$ 3,452,730 $ 3,668,465
=========== ===========
(Continued)
See Notes to Consolidated Financial Statements.
Page 4 of 21
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GOLDEN OIL COMPANY
CONSOLIDATED BALANCE SHEETS (CONTINUED)
(UNAUDITED)
MARCH 31, DECEMBER 31,
1998 1997
-------------- ------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Notes payable and
current portion of long-term debt ........... $ 111,858 $ 114,969
Accounts payable .............................. 1,125,494 1,201,629
Accrued expenses .............................. 331,629 290,362
------------ ------------
Total current liabilities ................ 1,568,981 1,606,960
------------ ------------
Long-term debt ................................... -- 24,091
Other liabilities ................................ 132,431 168,281
Commitments and contingencies
(See also Notes 4 and 5) ......................... -- --
Stockholders' equity:
Preferred stock, par value $.01;
authorized 10,000,000 shares, none issued .... -- --
Common stock, par value $.01
authorized 15,000,000 shares,
issued and outstanding 1,524,291
shares at March 31, 1998
and December 31, 1997 ........................ 15,243 15,243
Class B common stock, par value $.01
(convertible share-for-share into common
stock); authorized 3,500,000 shares; issued
and outstanding 22,254 shares at
March 31, 1998 and December 31, 1997 ......... 223 223
Additional paid-in capital ..................... 13,883,479 13,883,479
Accumulated deficit ............................ (12,147,627) (12,029,812)
------------ ------------
Total stockholders' equity ............... 1,751,318 1,869,133
------------ ------------
$ 3,452,730 $ 3,668,465
============ ============
See Notes to Consolidated Financial Statements.
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GOLDEN OIL COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
--------------------------
1998 1997
--------- ---------
Cash flows from operating activities:
Net earnings (loss) ............................. $(117,815) $ (30,593)
Adjustments to reconcile net
income to net cash provided
by operating activities:
Depreciation, depletion
and amortization ............................. 73,059 81,563
Equity in net (income) loss of
investment in commercial realty .............. (2,300) 1,263
Loss on sale of property
and equipment ................................ 1,995 --
Changes in components of working capital:
(Increase) decrease in accounts
receivable, net ........................... 20,874 55,787
(Increase) decrease in prepaid
expenses and other ........................ 7,602 1,317
Increase (decrease) in accounts
payable ................................... (76,135) (110,725)
Increase (decrease) in accrued
expenses .................................. 41,267 (26,804)
Increase (decrease) in
other liabilities ......................... (35,850) 42,141
--------- ---------
Net cash provided by (used
in) operating activities .................... $ (87,303) $ 13,949
========= =========
(Continued)
See Notes to Consolidated Financial Statements.
Page 6 of 21
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GOLDEN OIL COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
--------------------------
1998 1997
--------- ---------
Cash flows from investing activities:
Proceeds from sale of property
and equipment ............................. $ 174 $ --
Additions of oil and gas properties ......... (10,383) (5,660)
Additions of other property and
equipment ................................ (3,339) (2,667)
Decrease in short-term investments .......... -- (480)
--------- ---------
Net cash used in investing activities .......... $ (13,548) $ (8,807)
--------- ---------
Cash flows from financing activities:
Payment of long-term debt ................ (27,202) (41,310)
--------- ---------
Net cash provided by (used in)
financing activities ........................ $ (27,202) $ (41,310)
--------- ---------
Net increase (decrease) in cash and
cash equivalents ............................ (128,053) (36,168)
Cash and cash equivalents at
beginning of period ......................... 178,481 165,209
--------- ---------
Cash and cash equivalents at
end of period ............................... $ 50,428 $ 129,041
========= =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid for interest expense was $4,055 and $5,596 for the three
months ended March 31, 1998 and 1997, respectively. No cash was paid for income
taxes during the same corresponding periods.
See Notes to Consolidated Financial Statements
Page 7 of 21
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING PRINCIPLES
For a summary of significant accounting principles, see Notes to
Consolidated Financial Statements and Note 1 thereof contained in the
Annual Report on Form 10-K of Golden Oil Company ("Golden" or "Company")
for the year ended December 31, 1997. The Company follows the same
accounting policies during interim periods as it does for annual
reporting purposes.
The accompanying consolidated financial statements are condensed
and unaudited and have been prepared pursuant to the rules and
regulations of the Securities and Exchange Commission ("SEC"). In the
opinion of management, the unaudited interim financial statements
reflect such adjustments as are necessary to present a fair statement of
the financial position, results of operations and cash flows for the
interim periods presented. Interim results are not necessarily
indicative of a full year of operations. Certain information and note
disclosures normally included in annual financial statements prepared in
accordance with generally accepted accounting principles have been
condensed or omitted pursuant to SEC rules and regulations; however, the
Company believes that the disclosures made are adequate to make the
information presented not misleading. These financial statements should
be read in conjunction with the financial statements and the notes
thereto included in the Company's Form 10-K for the year ended December
31, 1997.
RECLASSIFICATIONS
Certain amounts from prior periods have been reclassified to
conform to the presentation format for the 1998 Consolidated Financial
Statements with no effect on reported results of operations.
ACCOUNTS RECEIVABLE
Amounts shown as accounts receivable are net of $113,718 at March
31, 1998 and December 31, 1997 to reflect estimated provisions for
doubtful collection of certain non-recourse obligations primarily in
connection with certain working interest participants of Company
subsidiaries. Accounts receivable reflect net amounts due from
affiliates of $50,063 at March 31, 1998 and $17,583 at December 31,
1997.
The Company holds a limited partnership interest in its
headquarters office building. The Company accounts for this investment
using the equity method and, accordingly, the Company recognizes its
pro-rata share of net income or loss of the limited partnership in its
current operating statements.
Page 8 of 21
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(2) CERTAIN FIXED PRICE SALE AGREEMENTS
In order to plan Company operations and to provide protection
against sudden declines in oil and gas prices, from time to time the
Company enters into fixed price sales contracts. 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 financially capable purchasers and does not anticipate
nonperformance by counterparties to such transactions.
(3) DEVELOPMENT OF SOUTH DOG CREEK FIELD
In March 1993, an agreement was reached between the Company and
Calumet Oil Company, the principal operators in the South Dog Creek,
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 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 $307,000 through March 1998,
exclusive of operating fees charged by the Company, of which the
Company's share was approximately $227,000. 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
Page 9 of 21
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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 $307,000 of costs already incurred. Subject to
the availability of funds, the Company is projecting capital
expenditures in 1998 for this project of $107,000.
(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 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 35 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
$129,000 to date.
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
Page 10 of 21
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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 and $22,681 as of March 31, 1998. 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 and additional financing.
(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, adjusted periodically. Such
interest rate was 11.5% per annum at March 31, 1998.
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
Page 11 of 21
<PAGE>
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 this credit agreement, the Company was required to make
monthly payments of principal and interest of approximately $10,400
through April 2000. In May 1998, the Company extended and increased this
credit agreement. The credit agreement was increased from its current
balance of $102,000 to $250,000 and extended through June 2001. The new
credit agreement provides for payments of approximately $8,200 each
month and bears interest at 1% over the Bank's prime lending rate,
adjusted periodically. The initial rate of interest is 10.5% per annum.
In connection with the additional loan and guarantee
arrangements, the Company expects to provide the guarantor compensation.
Such compensation is expected to be structured by the Board of Directors
primarily using non-cash consideration so as to provide liquidity for the
Company.
The guarantee, which is required to be made by an officer and
stockholder of the Company, is subject to completion and approval of
compensation arrangements by no later than June 15, 1998.
(6) STRATEGIC CONSIDERATIONS
In earlier stages of its development, the Company's strategic
emphasis focused on oil and gas production and development, particularly
of the substantial potential value possibly recoverable by waterflood of
the South Dog Creek field in Oklahoma and of the high quality but higher
fixed cost production in the San Juan Basin, New Mexico. The Company has
acquired and plans to continue to acquire interests in oil and gas
properties within its areas of operation which are offered to it on
economically attractive terms. However, in the early 1990s the Company
believed that a number of material adverse changes were occurring in the
independent oil and gas industry, including price volatility, increasing
costs of operation and a relatively less attractive ratio of risk to
potential revenue in both the acquisition of oil and gas properties or
the potential purchase of other independent oil and gas companies. These
adverse developments have affected, in particular, small oil and gas
companies whose operations were not diversified into other business
sectors. In response to the changed operating environment, the Company
is actively considering transactions by which its operations may be
further diversified. In this process the Company may reduce its oil and
gas operations while adding significantly to its participation in real
estate, financial services or other sectors.
During late 1993 and 1994, the Company diversified outside of the
energy sector through acquisition of ownership interests in the
commercial real estate sector, in particular the office building in
Houston, Texas where the Company maintains its principal offices. The
Company is actively reviewing transactions outside the energy sector.
While such diversification appears to offer more attractive long-term
opportunities than are offered by the small oil and gas sector, the
Company's ability to arrange financing to enter into any material
transaction is subject to a number of other
Page 12 of 21
<PAGE>
factors, certain of which are difficult to predict or are beyond
management's control. Such factors include the degree of the Company's
future success in development of its proved undeveloped reserves; the
respective future performance of oil and gas prices; and the
availability to the Company of financing for existing or other
businesses.
End of Notes to Consolidated Financial Statements.
Page 13 of 21
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
LIQUIDITY AND CAPITAL RESOURCES
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 operations during 1997, and to date during 1998, have been
funded primarily through internally generated funds from operating activities,
and from existing working capital and borrowings under its credit facilities.
Management anticipates that the Company will meet ordinary operating needs for
working capital from internal sources. However, the Company will require
additional financing in order to complete development of its proved undeveloped
reserves, or to make acquisitions either within or outside of the oil and gas
sector. The Company may arrange new financing through public or private
offerings of the Company's securities, asset sales, joint ventures, or other
means. If the Company is successful in its financing efforts, a significant use
of proceeds will be to improve its current working capital position.
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% per annum at March 31, 1998.
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
Page 14 of 21
<PAGE>
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 this credit agreement, the Company was required to make monthly
payments of principal and interest of approximately $10,400 through April 2000.
In May 1998, the Company extended and increased this credit agreement. The
credit agreement was increased from its current balance of $102,000 to $250,000
and extended through June 2001. The new credit agreement provides for payments
of approximately $8,200 each month and bears interest at 1% over the Bank's
prime lending rate, adjusted periodically. The initial rate of interest is 10.5%
per annum.
In connection with the additional loan and guarantee arrangements, the
Company expects to provide the guarantor compensation. Such compensation is
expected to be structured by the Board of Directors primarily using non-cash
consideration so as to provide liquidity for the Company.
The guarantee, which is required to be made by an officer and stockholder
of the Company, is subject to completion and approval of compensation
arrangements by no later than June 15, 1998.
Cash flow used in operating activities was $87,303 for the first three
months of 1998 compared to cash flow provided by operating activities of $13,949
for the first three months of 1997. The decrease from the first three months of
1997 is primarily due to a decrease in production revenues resulting from a
substantial decline in oil and gas prices in the first quarter of 1998 compared
to the prior year period.
In order to plan Company operations and to provide protection against
sudden declines in oil and gas prices, from time to time the Company enters into
fixed price sales contracts. 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 financially capable purchasers and does not anticipate
nonperformance by counterparties to such transactions.
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
Page 15 of 21
<PAGE>
1993, a field-wide water injection permit was granted by the EPA to the Company
and another interest holder and operator. During 1995 the Company initiated a
limited waterflood injection program on one of its operated leases believed to
have demonstrated engineering potential for success. Under the program certain
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 $307,000 through March 1998, exclusive of operating fees charged by
the Company, of which the Company's share was approximately $227,000. 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 $307,000 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
Page 16 of 21
<PAGE>
and to remediate and replace them with lined and enclosed surface pits. Such
federal government regulations provide for implementation on a region-by-region
basis.
In January 1997, the regions designated by the federal government were
expanded to include 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 35 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 $129,000 to date.
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 and $22,681 as of March 31, 1998. 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 and additional financing.
At March 31, 1998, the Company had a working capital deficit of
$1,105,108 compared to a working capital deficit of $986,558 at December 31,
1997, and a current ratio of .30 to 1.00 as of March 31, 1998 compared to a
current ratio of .39 to 1.00 as of December 31, 1997. The increase in the
working capital deficit at March 31, 1998 primarily reflects a decrease in
production revenues due to a substantial decline in oil and gas prices in the
first quarter of 1998.
On January 1, 1996 the Company adopted Statement of Financial Accounting
Standard ("SFAS") No. 121, "Accounting for the Impairment of Long-lived Assets
and for Long-lived Assets to be Disposed Of." There was no effect on the
financial position, results of operations or cash flows from the adoption of
this standard. In the future, however, pursuant to SFAS No.
Page 17 of 21
<PAGE>
121, material negative adjustments to the carrying value of the Company's
producing oil and gas properties could be required should prices for oil and gas
decline significantly or if the Company were to revise its estimates of
recoverable oil and gas reserves. No adjustment was required during the three
months ended March 31, 1998.
Due to factors including changes in tax laws, adverse changes in the
economics of exploration drilling and the availability to the Company of
alternative uses of capital, during the late 1980s the Company curtailed
exploration activities. If the Company commences such programs in the future, it
intends to continue its previous policy of sharing exploration risks with third
party drilling participants. Certain of the Company's oil and gas leases provide
for ongoing drilling arrangements for periodic development of proved reserves.
The Company's principal development obligations under such agreements have been
suspended pending clarification of title assignments on certain federal leases.
The Company expects to obtain drilling participation from industry partners so
as to reduce the amount of the Company's required drilling commitments.
Page 18 of 21
<PAGE>
RESULTS OF OPERATIONS
COMPARISON OF THE THREE MONTHS ENDED MARCH 31, 1998 WITH THE THREE MONTHS ENDED
MARCH 31, 1997.
REVENUES
--------
Revenues from oil and gas production decreased from $422,364 during the
first quarter of 1997 to $275,152 in the comparable 1998 quarter, a decrease of
$147,212. The decrease is primarily attributable to a decrease in average oil
prices of $6.93 per barrel from $23.00 per barrel during the first quarter of
1997 to $16.07 per barrel during the first quarter of 1998. Additionally,
average gas prices decreased $1.27 per mcf from $2.63 per mcf during the first
quarter of 1997 to $1.36 per mcf during the first quarter of 1998.
Other revenues was $7,982 for the first quarter of 1998 compared to
$6,336 for the comparable period in 1997, primarily due to an increase in gas
gathering and operating fees charged to third parties.
COSTS AND EXPENSES
------------------
Oil and gas production costs decreased by $19,941 from $284,074 for the
first quarter of 1997 to $264,133 for the same period in 1998. Such decrease is
primarily due to production costs associated with an above-average number of
well workovers on Company-operated properties in its San Juan field in New
Mexico in the first quarter of 1997. Pit impoundment costs were $22,502, net of
operating charges, during the first quarter of 1997 compared to $22,681 for the
same period in 1998. General and administrative expenses decreased by $25,046
from $65,708 for the first quarter of 1997 to $40,662 for the same period in
1998. This decrease is primarily attributable to reductions in personnel and
corporate overhead.
Depreciation, depletion and amortization expenses decreased from $81,563
for the first quarter of 1997 to $73,059 for the comparable period of 1998.
Interest expense decreased by $2,449 from $6,339 for the first quarter
of 1997 to $3,890 for the same period in 1998 due to a decrease in average
outstanding borrowings.
Primarily reflecting the factors discussed above, the Company reported a
net loss for the three months ended March 31, 1998 of $117,815 compared to a net
loss of $30,593 for the same period of 1997.
Page 19 of 21
<PAGE>
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (MATERIAL EVENT).
(a) Exhibits
None.
(b) Reports on Form 8-K
None.
Page 20 of 21
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
GOLDEN OIL COMPANY
Date: May 15, 1998 By: /s/ RALPH T. MCELVENNY, JR.
---------------------------
Chief Executive Officer
By: /s/ JEFFREY V. HOUSTON
---------------------------
Chief Financial and Accounting
Officer
Page 21 of 21
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<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> MAR-31-1998
<CASH> 50,428
<SECURITIES> 0
<RECEIVABLES> 381,638
<ALLOWANCES> 0
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<PP&E> 6,549,689
<DEPRECIATION> (3,756,842)
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<CGS> 286,814
<TOTAL-COSTS> 400,535
<OTHER-EXPENSES> (3,476)
<LOSS-PROVISION> 0
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<INCOME-PRETAX> (117,815)
<INCOME-TAX> 0
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<NET-INCOME> (117,815)
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