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 JUNE 30, 1998
------------------------------
OR
[ ] TRANSACTION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______________________ to
COMMISSION FILE NUMBER 0-9946
GOLDEN OIL COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 84-0836562
(State or other jurisdiction of incorporation (I.R.S. Employer
or organization) Identification No.)
550 POST OAK BOULEVARD, SUITE 550, HOUSTON, TEXAS 77027
(Address of principal executive offices) (Zip Code)
(713) 622-8492
(Registrants telephone number, including area code)
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
YES NO X
As of August 1, 1998, the Registrant had outstanding 1,624,291 shares of
common stock, par value $.01 per share and 22,254 shares of Class B common
stock, par value $.01 per share.
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CONTENTS
PAGE
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
- Consolidated Statements of Operations..................... 3
- Consolidated Balance Sheets............................... 5
- Consolidated Statements of Cash Flows..................... 7
- Notes to Consolidated Financial Statements................ 9
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations................. 17
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K.............................. 27
2
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GOLDEN OIL COMPANY
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
THREE MONTHS ENDED
JUNE 30,
-----------------------------
1998 1997
----------- -----------
Revenues:
Oil and gas production .................. $ 258,523 $ 456,344
Other ................................... 6,409 6,886
----------- -----------
Total revenues ....................... 264,932 463,230
----------- -----------
Costs and expenses:
Production costs ........................ 209,649 294,431
Pit impoundment costs, net .............. -- 23,715
Depreciation, depletion and
amortization .......................... 73,554 79,343
General and administrative .............. 95,787 99,376
----------- -----------
Total costs and expenses ............. 378,990 496,865
----------- -----------
(114,058) (33,635)
Gain (loss) on sale of property,
equipment and other assets .............. 1,000 (7,552)
Interest expense, net ...................... (4,711) (4,567)
Other income (expense) ..................... (25,169) (1,220)
----------- -----------
Net earnings (loss) ........................ $ (142,938) $ (46,974)
=========== ===========
Basic and diluted (loss) per common
share ................................... $ (.09) $ (.03)
=========== ===========
Weighted average number of
common shares and common
share equivalents outstanding ........... 1,536,379 1,424,291
=========== ===========
See Notes to Consolidated Financial Statements.
3
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GOLDEN OIL COMPANY
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
SIX MONTHS ENDED
JUNE 30,
-----------------------------
1998 1997
----------- -----------
Revenues:
Oil and gas production .................. $ 533,675 $ 878,708
Other ................................... 14,391 13,222
----------- -----------
Total revenues ....................... 548,066 891,930
----------- -----------
Costs and expenses:
Production costs ........................ 473,782 578,505
Pit impoundment costs, net .............. 22,681 46,217
Depreciation, depletion and
amortization .......................... 146,613 160,906
General and administrative .............. 136,449 165,084
----------- -----------
Total costs and expenses ............. 779,525 950,712
----------- -----------
(231,459) (58,782)
Gain (loss) on sale of property,
equipment and other assets .............. (995) (7,552)
Interest expense, net ...................... (8,601) (9,643)
Other income (expense) ..................... (19,698) (1,590)
----------- -----------
Net earnings (loss) ........................ $ (260,753) $ (77,567)
=========== ===========
Basic and diluted (loss) per common
share ................................... $ (.17) $ (.05)
=========== ===========
Weighted average number of
common shares and common
share equivalents outstanding ........... 1,530,368 1,424,291
=========== ===========
See Notes to Consolidated Financial Statements.
4
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GOLDEN OIL COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JUNE 30, DECEMBER 31,
1998 1997
----------- -----------
ASSETS
Current assets:
Cash and cash equivalents ................ $ 45,044 $ 178,481
Accounts receivable, net ................. 406,060 402,512
Prepaid expenses and other ............... 26,346 39,409
----------- -----------
Total current assets ................ 477,450 620,402
----------- -----------
Property and equipment, at cost:
Oil and gas properties
(using the successful efforts
method of accounting)
Producing properties ................ 5,882,105 5,867,128
Non-producing properties ............ 105,000 105,000
----------- -----------
Total oil and gas properties ........ 5,987,105 5,972,128
----------- -----------
Pipeline, field and other well equipment ..... 241,288 225,274
Other property and equipment ................. 341,588 413,981
----------- -----------
6,569,981 6,611,383
Less accumulated depreciation,
depletion and amortization ............... (3,820,396) (3,757,030)
----------- -----------
Net property and equipment ............... 2,749,585 2,854,353
----------- -----------
Investments, real estate ..................... 196,829 192,229
Other assets ................................. 1,481 1,481
----------- -----------
$ 3,425,345 $ 3,668,465
=========== ===========
(Continued)
See Notes to Consolidated Financial Statements.
5
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GOLDEN OIL COMPANY
CONSOLIDATED BALANCE SHEETS (CONTINUED)
(UNAUDITED)
JUNE 30, DECEMBER 31,
1998 1997
------------ ------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Notes payable and
current portion of long-term debt ......... 75,770 114,969
Accounts payable ............................ 1,135,326 1,201,629
Accrued expenses ............................ 313,578 290,362
------------ ------------
Total current liabilities .............. 1,524,674 1,606,960
------------ ------------
Long-term debt ................................. 167,360 24,091
Other liabilities .............................. 99,931 168,281
Commitments and contingencies
(See Notes 4 and 5) ............................ -- --
Stockholders' equity:
Preferred stock, par value $.01;
authorized 10,000,000 shares, none issued .. -- --
Common stock, par value $.01
authorized 15,000,000 shares,
issued and outstanding; 1,624,291
shares at June 30, 1998
and 1,524,291 at December 31, 1997 ......... 16,243 15,243
Class B common stock, par value $.01
(convertible share-for-share into common
stock); authorized 3,500,000 shares;
issued and outstanding 22,254 shares at
June 30, 1998 and December 31, 1997 ........ 223 223
Additional paid-in capital ................... 13,907,479 13,883,479
Accumulated deficit .......................... (12,270,565) (12,029,812)
------------ ------------
Total stockholders' equity ............. 1,633,380 1,869,133
------------ ------------
$ 3,425,345 $ 3,668,465
============ ============
See Notes to Consolidated Financial Statements.
6
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GOLDEN OIL COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
SIX MONTHS ENDED
JUNE 30,
-------------------------
1998 1997
--------- ---------
Cash flows from operating activities:
Net earnings (loss) ......................... $(260,753) $ (77,567)
Adjustments to reconcile net
income to net cash provided
by operating activities:
Depreciation, depletion
and amortization ......................... 146,613 160,906
Equity in net (income) loss of
investment in commercial
realty ................................... (4,600) 2,526
Loss on sale of property
and equipment ............................ 995 7,552
Guarantee fee ............................... 25,000 --
Changes in components of working
capital:
(Increase) decrease in
accounts receivable, net ................. (3,548) 79,616
(Increase) decrease in prepaid
expenses and other .................... 13,063 6,634
Increase (decrease) in accounts
payable ............................... (66,303) (168,765)
Increase (decrease) in
accrued expenses ......................... 23,216 (22,510)
Increase (decrease) in
other liabilities ..................... (68,350) 70,015
--------- ---------
Net cash provided by (used
in) operating activities ................ $(194,667) $ 58,407
========= =========
(Continued)
See Notes to Consolidated Financial Statements.
7
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GOLDEN OIL COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
(UNAUDITED)
SIX MONTHS ENDED
JUNE 30,
-------------------------
1998 1997
--------- ---------
Cash flows from investing activities:
Proceeds from sale of property
and equipment ............................. 1,174 1,803
Additions of oil and gas properties ......... (14,977) (73,810)
Additions of other property
and equipment ............................... (29,037) (4,067)
Decrease in short-term investments .......... -- (753)
--------- ---------
Net cash used in investing
activities ..................................... (42,840) (76,827)
--------- ---------
Cash flows from financing activities:
Proceeds from issuance of
long-term debt ........................... 250,000 64,566
Payment of debt .......................... (145,930) (72,915)
--------- ---------
Net cash provided by (used in)
financing activities ........................ 104,070 (8,349)
--------- ---------
Net increase (decrease) in cash
and cash equivalents ........................... (133,437) (26,769)
Cash and cash equivalents at
beginning of period ......................... 178,481 165,209
--------- ---------
Cash and cash equivalents at
end of period ............................... $ 45,044 $ 138,440
========= =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid for interest expense was $7,744 and $10,304 for the six months
ended June 30, 1998 and 1997, respectively. No cash was paid for federal income
taxes during the same corresponding periods.
See Notes to Consolidated Financial Statements
8
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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.
IMPAIRMENT OF LONG-LIVED ASSETS. On January 1, 1996 the Company
adopted Statement of Financial Accounting Standard ("SFAS") No. 121,
"Accounting for the Impairment of Long-lived Assets and for Long-lived
Assets to be Disposed Of." No effect on the financial position, results of
operations or cash flows has been recognized as a result of the adoption
of this standard. However, pursuant to SFAS No. 121, in the future
material negative adjustments to the carrying value of the Company's
producing oil and gas properties could be required should prices
obtainable for oil and/or gas production decline significantly, or if the
Company were to revise its estimates of recoverable oil and gas reserves.
Although oil prices declined very significantly during the second quarter,
the Company has not provided an impairment reserve during that period, as
management believes that price recovery is likely to occur this fall. If
price recovery has not occurred by the time to report for the third
quarter ending September 30, 1998, the Company would make a charge to
reflect impairment of the value of long-lived production assets. If the
current range of prices for oil and gas continues through the third
quarter, the additional third quarter charge for impairment would be in
the range of $150,000 to $400,000.
9
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ACCOUNTS RECEIVABLE. Amounts shown as accounts receivable are net of
$113,718 at June 30, 1998 and December 31, 1997 to reflect estimated
provisions for doubtful collection of certain non-recourse obligations
primarily in connection with certain working interest participants of
Company subsidiaries. Accounts receivable reflect net amounts due from
affiliates of $78,304 at June 30, 1998 and $17,583 at December 31, 1997.
The Company holds a limited partnership interest in its headquarters
office building. The Company accounts for this investment using the equity
method and, accordingly, the Company recognizes its pro-rata share of net
income or loss of the limited partnership in its current operating
statements.
RECLASSIFICATIONS. Certain amounts from prior periods have been
reclassified to conform to the presentation format for the 1998
Consolidated Financial Statements with no effect on reported results of
operations.
(2) CERTAIN FIXED PRICE SALE AGREEMENTS
In order to plan Company operations and as a measure of protection
against sudden declines in oil and gas prices, from time to time the
Company enters into fixed price sales contracts. The Company held a fixed
price oil contract for approximately 40% of its monthly oil production
through March 1, 1998 at an average price at the wellhead of approximately
$19.75 per barrel. If, as and when oil prices increase from current levels
the Company anticipates that it will enter new fixed price oil contracts.
In March 1998, the Company entered into a fixed price contract for
approximately 60% of its monthly gas production in the San Juan Basin in
New Mexico. Such contract extends through August 31, 1998 at an average
price of approximately $1.99 per Mmbtu after which gas production likely
will be sold at prevailing market rates. The Company believes the fixed
price arrangements it might typically sign are entered 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, which are the principal operators in the South Dog
Creek field in Osage County, Oklahoma, 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
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EPA to the Company and another interest holder and operator. During 1995
the Company initiated a limited waterflood injection program on one of its
operated leases believed to have demonstrated engineering potential for
success. Under the program certain marginal producing wells were converted
to water injectors and producing wells and well equipment were reworked to
increase the wells' fluid volume capacity. To date, the expenditures on
the waterflood project on this lease are approximately $313,000 through
June 1998, exclusive of operating fees charged by the Company, of which
the Company's share was approximately $232,000. The Company funded its
share of costs through internally generated cash flows with the balance
paid by outside working interest owners who elected to join the project.
At current prices of oil and gas, the Company has a negative cash
flow from operations and can fund development costs only through third
party arrangements such as borrowings, asset sales, joint operations or
the like.
To date, the Osage County, Oklahoma field has not exhibited a
substantial, sustained increase in production from water injection. The
Company does not anticipate significant increases in overall production
volumes from this field unless further development can be implemented
across a more extensive area and such further development is successful.
Management plans to evaluate the results of ongoing development at various
stages before determining whether or to what extent to attempt additional
development. Current rates of total water injection, including reinjected
water, total approximately 1,600 barrels per day into three injection
wells. The Company is currently reviewing the estimated costs of various
methods to acquire or develop additional sources of water needed for
injection. The availability of source water supply is not itself expected
to be a material limiting factor in the overall project. To date the
Company has injected approximately 310,000 barrels of net new water into
the producing formation. Based on current engineering projections, at
least 650,000 net new barrels will be required to reach the level at which
localized repressurization may be expected to occur. Subject to the
availability of funds and based on indications available from the
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localized response to water injection to date, the Company plans to
continue a water injection program. If in the future sufficient production
response is achieved and sustained, the Company intends to pursue a
field-wide waterflood plan. The feasibility and overall scheduling of full
scale, field-wide development for water injection remain subject to, among
other things, engineering advice based on the localized injection
summarized above; actual and projected oil prices; and the availability of
additional financing.
Due to the uneconomic nature of oil operations at current oil
prices, and to other variables discussed above, the Company is not able to
assure a schedule of ongoing development, nor to provide a definitive
estimate of overall projected waterflood costs. As results are received
and analyzed, the Company will continue to review the actual and projected
overall costs of the waterflood project. Subject to the foregoing, the
Company is using a working projection for its share of overall project
costs of $750,000, inclusive of $313,000 of costs already incurred, and is
projecting 1998 capital expenditures of $58,000 for this project.
(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 on
lands of the Jicarilla Apache Nation in New Mexico. Pursuant to the
Company's operating permit from the Jicarilla Apache Indian Nation, the
Company's operating subsidiary was required to develop a plan for
remediation and improvement for every well site. In May 1997 the BLM and
the Jicarilla Environmental Protection Office ("EPO") approved the
remediation and improvement plan ("Plan"). The Plan provided for the
remediation and enclosure of surface pits at all well sites in accordance
with Ordinance 95-0-308-03. Surface pits on 28 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. Costs for
the project to date, including the interests of the Company and third
parties, vary substantially by well site but have ranged between $2,000 to
$10,000 per site, and are approximately $163,000 in total.
Remediation on all 81 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; however, to date extensions have not yet been
granted. Total costs are subject to a number of variable expense factors
including, among others, the cost and manner of disposal of removed soil
and the amounts of soil which may be required to be removed per site. The
Plan allows relatively broad soil disposal options; however, it is
possible that even more costly soil disposal alternatives
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may be deemed necessary or may be mandated by the regulatory agencies
governing the remediation and impoundment programs.
Based upon 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 numerous variable expense factors as summarized
above. In recognition of the above variables the Company charged against
income a provision reflecting its preliminary net cost estimate for such
work of approximately $106,000 as of December 31, 1997 and an additional
amount of $22,681 as of June 30, 1998. The adequacy of such provision is
reviewed periodically and may be adjusted as actual costs are incurred.
Primarily as a result of negative cash flow generated currently by
New Mexico oil production operations at current prices and other
materially negative factors summarized above, it is uncertain to what
extent the costs to complete the federal government's mandated pit
impoundment program may be met through internally generated cash flow. In
event that the Company can not meet such obligations from internally
generated funds, the Company would be required to look to asset sales;
additional borrowings, if possible; or to third party arrangements.
(5) INDEBTEDNESS
In April 1996 the Company entered into a credit agreement with a
commercial bank in Albuquerque, New Mexico under which the Company was
able to reschedule payments of existing borrowings which had fallen due
for repayment in full, and to increase its available credit from $150,000
to $400,000. The loan agreement extended the maturity schedule of the
Company's debt to four years, subject to certain conditions, and provided
monthly payments totaling approximately $10,400 monthly through April
2000. As a condition to the new credit agreement, the lending bank
required the entire credit facility to be independently, personally
guaranteed by a person acceptable to it, particularly a member of the
ongoing management of the Company. An officer of the Company agreed to
provide such unconditional personal guarantee for which the officer would
receive fair compensation. After having received delivery of the written
opinion from an independent investment banking advisor that such
transaction was fair, from a financial point of view, to the Company and
its stockholders, the Board of Directors approved the new credit agreement
and the delivery to the guarantor of warrants to purchase 250,000
unregistered shares of common stock of the Company through March 2006 at
an exercise price of $.20 per share. During
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1997 the guarantor exercised rights to purchase 100,000 such shares. No
rights have been exercised during 1998 to date.
During the second quarter of 1998 oil prices declined precipitously,
and have since reached ten year lows. The Company's oil production
operations became uneconomic and failed to generate cash flow to pay costs
including the government mandated pit remediation program; monthly
principal and interest charges under the bank agreement; or costs of the
Company's waterflood injection program at its Osage County, Oklahoma
field. In order to fund its obligations, the Company obtained a new credit
agreement under which the Company increased its borrowings by
approximately $150,000; extended its loan maturity to July 1, 2001; and
reduced monthly payment requirements to $8,200. The new credit bears
interest at 1% over the lending bank's prime lending rate, adjusted
periodically, an initial interest rate of 10.5% per annum. Proceeds from
the new financing will be applied primarily to fund operating cash
requirements; to continue the government mandated pit impoundment program;
and to maintain the ongoing waterflood project as above.
In order to obtain the new financing the Company was required by the
lending bank to provide an unconditional personal guarantee, having
substance acceptable to the bank, of repayment in full of all principal,
interest and related costs provided under the new agreement. At this time
the Company's management and the bank were concerned about factors
including the Company's lack of liquidity; the working capital deficit
exceeding one million dollars; and the rapid and severe declines in oil
prices, which drove current oil production operations into a negative cash
flow position. As a result of its financial postion, the Company was not
able to pay a cash fee to the personal guarantor of the proposed
financing. Instead, the Company agreed, subject to final approval of the
guarantee and performance by the bank lender, to pay the financing fee by
delivering to the guarantor 100,000 unregistered shares of its common
stock, and warrants to purchase 250,000 unregistered shares of the
Company's common stock, exerciseable in whole or in part through June 30,
2008 at an exercise price of $.15 per share. On June 19, 1998 the Board of
Directors ratified the execution by the Company of the bank credit
agreement and approved the payment and delivery to the guarantor of such
compensation. Prior to approving the agreement to obtain additional bank
credit and the related guarantee arrangements, the Board of Directors
retained an independent investment banking firm to advise concerning the
fairness to the Company and its stockholders, from a financial point of
view, of the terms proposed for payment for such guarantee. In the regular
course of its business, such investment banking firm renders advice and
opinions regarding mergers, acquisitions, financing arrangements, and cash
and share transactions for small capitalization natural resource
companies. At the meeting of the Board of Directors as above, the Board
considered the written opinion delivered to it by the
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independent investment banking advisor that the proposed transaction was
fair, from a financial point of view, to the Company and its stockholders.
The credit agreement and guarantee fee were thereupon approved by the
Board of Directors. Subsequent to the close of the second quarter, 100,000
such shares were delivered to the guarantor.
(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 reserves categorized by the Company's independent
petroleum engineering firm as proved undeveloped reserves, which are
possibly recoverable by waterflood of the South Dog Creek field in
Oklahoma. In addition the Company owned proved developed production of
good quality, but having higher fixed costs of production than that of its
Oklahoma field, located in the San Juan Basin, New Mexico. However, since
the early 1990s a number of changes have occurred which have adversely
impacted the independent oil and gas industry. As a result the Company has
changed its strategic objectives. Generally, the adverse changes have
included increased price volatility; repeated periods of sharply lower,
sometimes uneconomic prices; increasing costs of operation; increased
government regulation; adverse changes in the federal and state tax
burden; and relatively less attractive opportunities to acquire oil and
gas properties or purchase other independent operators in the Company's
size range. These developments have adversely affected the independent oil
and gas industry generally. In response to the changed operating
environment, the Company has taken steps to diversify into other sectors
of operation deemed to offer greater long-term potential and is actively
considering transactions by which it may further diversify. In this
process the Company may reduce its dependence on oil and gas operations
while adding significantly to its participation in the real estate,
financial services or other sectors.
During late 1993 and 1994, the Company diversified outside of the
energy sector through purchase of a limited partnership interest in a
partnership ("Partnership") which owns the office building in Houston,
Texas in which the Company maintains its principal offices. The Company is
actively reviewing other possible 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 any material transaction
is subject to a number of other factors and constraints, certain of which
are difficult to predict or are beyond management's control. Such factors
include the degree of the Company's future success in the waterflood
development of its proved undeveloped reserves; the future performance of
oil and gas prices,
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respectively; the extent of internal cash flow from operations; and the
availability of financing to support current or prospective business
operations of the Company.
The Partnership has recently advised that, primarily to achieve
greater diversification, the general partner is recommending the sale of
such office building. Based on current market indications, the Company
expects to recognize a gain on disposition of its ownership interest;
however, arrangements for sale are not expected to be at a definitive
stage until approximately the fall of the current year.
Management is actively considering investment in other real estate
interests as well as other diversification. While the long-term prospects
of real estate sector may be considered attractive compared to those of
the small independent oil and gas sector, the Company is constrained by
its limited financial resources. Accordingly, unless oil prices increase
greatly above current levels or the Company's asset base or capitalization
is restructured, its ability to achieve significant diversification could
be limited.
End of Notes to Consolidated Financial Statements.
16
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
LIQUIDITY AND CAPITAL RESOURCES
DIVERSIFICATION. The Company is a somewhat diversified business whose
current scope of operations includes oil and gas operation and development, but
with increasing emphasis on diversification into other sectors. Over the last
several years the Company has continued to develop its properties and has
expanded through corporate transactions, primarily asset purchases and mergers,
including the purchase of an interest in a commercial real estate venture.
Management places strong emphasis on further diversification. Subject to a
number of factors including 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, the Company
plans to diversify from the independent oil and gas sector.
FUNDING. The Company's operations during 1997, and to date during 1998,
have been funded primarily through borrowings under credit facilities,
internally generated funds from operating activities, and from working capital.
Unless oil prices continue at current levels, management anticipates that the
Company will meet ordinary operating needs for working capital from external
financing now in place and from internal sources. However, the Company will
require additional financing or internal cash generation in order to continue
its program to develop proved undeveloped reserves by waterflood injection, or
to continue to diversify. Management believes that it may be possible for the
Company to diversify and to obtain additional financing through issuance of
securities, asset sales, joint ventures, or other means. In this connection, the
Company recognizes a significant need to improve its current working capital
position.
DECLINES IN CASH FLOW. Cash flow used in operating activities was $194,667
for the first six months of 1998 compared to cash provided by operating
activities of $58,407 for the first six months of 1997. The decrease from the
first six months of 1997 is due primarily to a decrease in production revenues
resulting from the collapse in oil prices and a significant decline in gas
prices in the first six months of 1998 compared to the prior year period.
FIXED PRICE CONTRACTS. In order to plan Company operations and as a
measure of protection against sudden declines in oil and gas prices, from time
to time the Company enters into fixed price sales contracts. The Company held a
fixed price oil contract for approximately 40% of its monthly oil production
through March 1, 1998 at an average price at the wellhead of approximately
$19.75 per barrel. If, as and when oil prices increase from current levels the
Company anticipates that it will enter new fixed price oil contracts. In March
1998, the Company entered into a fixed price contract for approximately 60% of
its monthly gas production in the San Juan Basin in New Mexico.
17
<PAGE>
Such contract extends through August 31, 1998 at an average price of
approximately $1.99 per Mmbtu after which gas production likely will be sold at
prevailing market rates. The Company believes the fixed price arrangements it
might typically sign are entered with financially capable purchasers and does
not anticipate nonperformance by counterparties to such transactions.
WATERFLOOD DEVELOPMENT. In March 1993, an agreement was reached between
the Company and Calumet Oil Company, which are the principal operators in the
South Dog Creek field in Osage County, Oklahoma, aimed at enhancing and
extending the producing life of the field by injection of water into the
Mississippian formation in ten wells covering four separate quarter section
leases. The operators filed for a water injection permit with the Environmental
Protection Agency ("EPA") and, during October 1993, a field-wide water injection
permit was granted by the EPA to the Company and another interest holder and
operator. During 1995 the Company initiated a limited waterflood injection
program on one of its operated leases believed to have demonstrated engineering
potential for success. Under the program certain marginal producing wells were
converted to water injectors and producing wells and well equipment were
reworked to increase the wells' fluid volume capacity. To date, the expenditures
on the waterflood project on this lease are approximately $313,000 through June
1998, exclusive of operating fees charged by the Company, of which the Company's
share was approximately $232,000. The Company funded its share of costs through
internally generated cash flows with the balance paid by outside working
interest owners who elected to join the project.
At current prices of oil and gas, the Company has a negative cash flow
from operations and can fund development costs only through third party
arrangements such as borrowings, asset sales, joint operations or the like.
To date, the Osage County, Oklahoma field has not exhibited a substantial,
sustained increase in production from water injection. The Company does not
anticipate significant increases in overall production volumes from this field
unless further development can be implemented across a more extensive area and
such further development is successful. Management plans to evaluate the results
of ongoing development at various stages before determining whether or to what
extent to attempt additional development. Current rates of total water
injection, including reinjected water, total approximately 1,600 barrels per day
into three injection wells. The Company is currently reviewing the estimated
costs of various methods to acquire or develop additional sources of water
needed for injection. The availability of source water supply is not itself
expected to be a material limiting factor in the overall project. To date the
Company has injected approximately 310,000 barrels of net new water into the
producing formation. Based on current engineering projections, at least 650,000
net new barrels will be required to reach the level at which localized
repressurization may be expected to occur. Subject to the availability of funds
and based on indications available from the
18
<PAGE>
localized response to water injection to date, the Company plans to continue a
water injection program. If in the future sufficient production response is
achieved and sustained, the Company intends to pursue a field-wide waterflood
plan. The feasibility and overall scheduling of full scale, field-wide
development for water injection remain subject to, among other things,
engineering advice based on the localized injection summarized above; actual and
projected oil prices; and the availability of additional financing.
Due to the uneconomic nature of oil operations at current oil prices, and
to other variables discussed above, the Company is not able to assure a schedule
of ongoing development, nor to provide a definitive estimate of overall
projected waterflood costs. As results are received and analyzed, the Company
will continue to review the actual and projected overall costs of the waterflood
project. Subject to the foregoing, the Company is using a working projection for
its share of overall project costs of $750,000, inclusive of $313,000 of costs
already incurred, and is projecting 1998 capital expenditures of $58,000 for
this project.
CREDIT AGREEMENTS. In April 1996 the Company entered into a credit
agreement with a commercial bank in Albuquerque, New Mexico under which the
Company was able to reschedule payments of existing borrowings which had fallen
due for repayment in full, and to increase its available credit from $150,000 to
$400,000. The loan agreement extended the maturity schedule of the Company's
debt to four years, subject to certain conditions, and provided monthly payments
totaling approximately $10,400 monthly through April 2000. As a condition to the
new credit agreement, the lending bank required the entire credit facility to be
independently, personally guaranteed by a person acceptable to it, particularly
a member of the ongoing management of the Company. An officer of the Company
agreed to provide such unconditional personal guarantee for which the officer
would receive fair compensation. After having received delivery of the written
opinion from an independent investment banking advisor that such transaction was
fair, from a financial point of view, to the Company and its stockholders, the
Board of Directors approved the new credit agreement and the delivery to the
guarantor of warrants to purchase 250,000 unregistered shares of common stock of
the Company through March 2006 at an exercise price of $.20 per share. During
1997 the guarantor exercised rights to purchase 100,000 such shares. No rights
have been exercised during 1998 to date.
During the second quarter of 1998 oil prices declined precipitously,
and have since reached ten year lows. The Company's oil production operations
became uneconomic and failed to generate cash flow to pay costs including the
government mandated pit remediation program; monthly principal and interest
charges under the bank agreement; or costs of the Company's waterflood injection
program at its Osage County, Oklahoma field. In order to fund its obligations,
the Company obtained a new credit agreement under which the Company increased
its borrowings by approximately $150,000;
19
<PAGE>
extended its loan maturity to July 1, 2001; and reduced monthly payment
requirements to $8,200. The new credit bears interest at 1% over the lending
bank's prime lending rate, adjusted periodically, an initial interest rate of
10.5% per annum. Proceeds from the new financing will be applied primarily to
fund operating cash requirements; to continue the government mandated pit
impoundment program; and to maintain the ongoing waterflood project as above.
In order to obtain the new financing the Company was required by the
lending bank to provide an unconditional personal guarantee, having substance
acceptable to the bank, of repayment in full of all principal, interest and
related costs provided under the new agreement. At this time the Company's
management and the bank were concerned about factors including the Company's
lack of liquidity; the working capital deficit exceeding one million dollars;
and the rapid and severe declines in oil prices, which drove current oil
production operations into a negative cash flow position. As a result of its
financial postion, the Company was not able to pay a cash fee to the personal
guarantor of the proposed financing. Instead, the Company agreed, subject to
final approval of the guarantee and performance by the bank lender, to pay the
financing fee by delivering to the guarantor 100,000 unregistered shares of its
common stock, and warrants to purchase 250,000 unregistered shares of the
Company's common stock, exerciseable in whole or in part through June 30, 2008
at an exercise price of $.15 per share. On June 19, 1998 the Board of Directors
ratified the execution by the Company of the bank credit agreement and approved
the payment and delivery to the guarantor of such compensation. Prior to
approving the agreement to obtain additional bank credit and the related
guarantee arrangements, the Board of Directors retained an independent
investment banking firm to advise concerning the fairness to the Company and its
stockholders, from a financial point of view, of the terms proposed for payment
for such guarantee. In the regular course of its business, such investment
banking firm renders advice and opinions regarding mergers, acquisitions,
financing arrangements, and cash and share transactions for small capitalization
natural resource companies. At the meeting of the Board of Directors as above,
the Board considered the written opinion delivered to it by the independent
investment banking advisor that the proposed transaction was fair, from a
financial point of view, to the Company and its stockholders. The credit
agreement and guarantee fee were thereupon approved by the Board of Directors.
Subsequent to the close of the second quarter, 100,000 such shares were
delivered to the guarantor.
In recent years the Bureau of Land Management ("BLM") of the U.S.
Department of the Interior has implemented extensive national regulations for
the handling and maintenance of produced water from well sites on all federal
lands. The stated objective of the regulations is to provide guidance for
closure of unlined surface impoundments in a manner that assures protection of
fresh waters, public health and the environment. 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
20
<PAGE>
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 on lands of
the Jicarilla Apache Nation in New Mexico. Pursuant to the Company's operating
permit from the Jicarilla Apache Indian Nation, the Company's operating
subsidiary was required to develop a plan for remediation and improvement for
every well site. In May 1997 the BLM and the Jicarilla Environmental Protection
Office ("EPO") approved the remediation and improvement plan ("Plan"). The Plan
provided for the remediation and enclosure of surface pits at all well sites in
accordance with Ordinance 95-0-308-03. Surface pits on 28 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. Costs for the
project to date, including the interests of the Company and third parties, vary
substantially by well site but have ranged between $2,000 to $10,000 per site,
and are approximately $163,000 in total.
Remediation on all 81 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; however, to date extensions have not yet been granted. Total costs are
subject to a number of variable expense factors including, among others, the
cost and manner of disposal of removed soil and the amounts of soil which may be
required to be removed per site. The Plan allows relatively broad soil disposal
options; however, it is possible that even more costly soil disposal
alternatives may be deemed necessary or may be mandated by the regulatory
agencies governing the remediation and impoundment programs.
Based upon 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 numerous variable
expense factors as summarized above. In recognition of the above variables the
Company charged against income a provision reflecting its preliminary net cost
estimate for such work of approximately $106,000 as of December 31, 1997 and an
additional amount of $22,681 as of June 30, 1998. The adequacy of such provision
is reviewed periodically and may be adjusted as actual costs are incurred.
Primarily as a result of negative cash flow generated currently by New
Mexico oil production operations at current prices and other materially negative
factors summarized above, it is uncertain to what extent the costs to complete
the federal government's mandated pit impoundment program may be met through
internally generated cash flow. In event that the Company can not meet such
obligations from internally generated funds,
21
<PAGE>
the Company would be required to look to asset sales; additional borrowings, if
possible; or to third party arrangements.
At June 30, 1998, the Company had a working capital deficit of $1,047,224
compared to a working capital deficit of $986,558 at December 31, 1997, and a
current ratio of .31 to 1.00 as of June 30, 1998 compared to a current ratio of
.39 to 1.00 as of December 31, 1997. The increase in the working capital deficit
at June 30, 1998 primarily reflects reduced short-term debt resulting from
refinancing the short-term debt then outstanding offset by a decrease in
production revenues due to a collapse in oil prices and a significant decline in
gas prices in the first six months of 1998.
On January 1, 1996 the Company adopted Statement of Financial Accounting
Standard ("SFAS") No. 121, "Accounting for the Impairment of Long-lived Assets
and for Long-lived Assets to be Disposed Of." No effect on the financial
position, results of operations or cash flows has been recognized as a result of
the adoption of this standard. However, pursuant to SFAS No. 121, in the future
material negative adjustments to the carrying value of the Company's producing
oil and gas properties could be required should prices obtainable for oil and/or
gas production decline significantly, or if the Company were to revise its
estimates of recoverable oil and gas reserves. Although oil prices declined very
significantly during the second quarter, the Company has not provided an
impairment reserve during that period, as management believes that price
recovery is likely to occur this fall. If price recovery has not occurred by the
time to report for the third quarter ending September 30, 1998, the Company
would make a charge to reflect impairment of the value of long-lived production
assets. If the current range of prices for oil and gas continues through the
third quarter, the additional third quarter charge for impairment would be in
the range of $150,000 to $400,000.
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.
22
<PAGE>
RESULTS OF OPERATIONS
COMPARISON OF THE THREE MONTHS ENDED JUNE 30, 1998 WITH THE THREE MONTHS ENDED
JUNE 30, 1997.
REVENUES
Revenues from oil and gas production decreased from $456,344 during the
second quarter of 1997 to $258,523 in the comparable 1998 quarter, a decrease of
$197,821. The decrease is primarily attributable to a decrease in average oil
prices of $6.79 per barrel from $21.56 per barrel during the second quarter of
1997 to $14.77 per barrel during the second quarter of 1998. Third quarter oil
prices may be as low or lower than average prices obtained during the second
quarter. Additionally, average gas prices decreased $0.05 per mcf from $1.39 per
mcf during the second quarter of 1997 to $1.34 per mcf during the second quarter
of 1998. As a result of the collapse of oil prices, the Company has temporarily
shut-in certain high cost, marginally producing wells in New Mexico, resulting
in a 26% decrease in the Company's total production volumes compared to the same
period in 1997.
Other revenues were $6,409 for the second quarter of 1998 compared to
$6,886 for the comparable period in 1997.
COSTS AND EXPENSES
Oil and gas production costs decreased by $84,782 from $294,431 for the
second quarter of 1997 to $209,649 for the same period in 1998. Such decrease is
due primarily to reduced production costs for well workovers during 1998
compared to the workover costs in the San Juan field in New Mexico during the
second quarter of 1997. Pit impoundment costs were $23,715, net of operating
charges, during the second quarter of 1997. General and administrative expenses
decreased by $3,589 from $99,376 for the second quarter of 1997 to $95,787 for
the same period in 1998.
Depreciation, depletion and amortization expenses decreased from $79,343
for the second quarter of 1997 to $73,554 for the comparable period of 1998.
Loss on sale of property and equipment during the second quarter of 1997
of $7,552 and gain on sale of property and equipment of $1,000 in the comparable
1998 quarter reflects the sale of field equipment.
Interest expense increased by $144 from $4,567 for the second quarter of
1997 to $4,711 for the same period in 1998 reflecting increased average
borrowings outstanding.
23
<PAGE>
Other expense during the second quarter of 1998 of $25,169 primarily
represents a guarantee fee of $25,000 for the Company's bank credit agreement.
Primarily reflecting the factors discussed above, the Company reported a
net loss for the three months ended June 30, 1998 of $142,938 compared to a net
loss of $46,974 for the same period of 1997.
24
<PAGE>
RESULTS OF OPERATIONS
COMPARISON OF THE SIX MONTHS ENDED JUNE 30, 1998 WITH THE SIX MONTHS ENDED JUNE
30, 1997.
REVENUES
Revenues from oil and gas production decreased from $878,708 during the
first six months of 1997 to $533,675 in the comparable 1998 period, a decrease
of $345,033. The decrease is primarily attributable to a decrease in average oil
prices of $6.76 per barrel from $22.19 per barrel during the first six months of
1997 to $15.43 per barrel during the first six months of 1998. Additionally,
average gas prices decreased $0.55 per mcf, from $1.90 per mcf during the first
six months of 1997 to $1.35 per mcf during the first six months of 1998. As a
result of the collapse of oil prices, the Company has temporarily shut-in
certain high cost, marginally producing wells in New Mexico, resulting in a 18%
decrease in the Company's total production volumes compared to the same period
in 1997.
Other revenues were $14,391 for the first six months of 1998 compared to
$13,222 for the comparable period in 1997.
COSTS AND EXPENSES
Oil and gas production costs decreased by $104,723 from $578,505 for the
first six months of 1997 to $473,782 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 six months of 1997. Pit impoundment costs were $46,217, net
of operating charges, during the first six months of 1997 compared to $22,681
for the same period in 1998. General and administrative expenses decreased by
$28,635 from $165,084 for the first six months of 1997 to $136,449 for the same
period in 1998.
Depreciation, depletion and amortization expenses decreased from $160,906
for the first six months of 1997 to $146,613 for the comparable period of 1998.
Loss on sale of property and equipment for the first six months of 1997
and 1998 of $7,552 and $995, respectively, reflects the sale of property and
field equipment.
Interest expense decreased by $1,042 from $9,643 for the first six months
of 1997 to $8,601 for the same period in 1998 due to a decrease in average
outstanding borrowings.
25
<PAGE>
Other expense during the first six months of 1998 of $19,698 primarily
represents a guarantee fee of $25,000 for the Company's bank credit agreement.
Primarily reflecting the factors discussed above, the Company reported a
net loss for the six months ended June 30, 1998 of $260,753 compared to a net
loss of $77,567 for the same period of 1997.
26
<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.
27
<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: August 14, 1998 By: /s/ RALPH T. MCELVENNY, JR.
---------------------------
Chief Executive Officer
By: /s/ JEFFREY V. HOUSTON
---------------------------
Chief Financial and Accounting
Officer
28
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<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> JUN-30-1998
<CASH> 45,044
<SECURITIES> 0
<RECEIVABLES> 406,060
<ALLOWANCES> 0
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<CURRENT-ASSETS> 477,450
<PP&E> 6,569,981
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<TOTAL-ASSETS> 3,425,345
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<COMMON> 16,466
<OTHER-SE> 1,616,914
<TOTAL-LIABILITY-AND-EQUITY> 3,425,345
<SALES> 533,675
<TOTAL-REVENUES> 548,066
<CGS> 496,463
<TOTAL-COSTS> 779,525
<OTHER-EXPENSES> 20,693
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 8,601
<INCOME-PRETAX> (260,753)
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