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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
Annual Report Pursuant to Section 13 or 15(d) of
The Securities Exchange Act of 1934
For the fiscal year ended December 31, 2000 Commission File No. 0-18774
Spindletop Oil & Gas Co.
(Exact name of registrant as specified in its charter)
Texas 75-2063001
(State or other jurisdiction (IRS Employer or ID #)
of incorporation or organization)
9319 LBJ, Frwy., #205 Dallas, TX 75243
(Address of principal executive offices) (Zip Code)
Company's telephone number, including area code: (972) 644-2581
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock par value $0.01 per share
(Title of Class)
Indicate by check mark whether the Company (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 Company was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
YES X NO
As of March 31, 2001, 7,525,804 shares of the Company's common stock were issued
and outstanding, and the aggregate market value of the voting stock held by
non-affiliates of the company as of that date is not determinable since no
significant public trading market has been established for the Company's common
stock.
1
PART I
Item 1. Description of Business.
(a) General Business Development.
Spindletop Oil & Gas Co. is engaged in the exploration, development and
production of oil and natural gas; the rental of oilfield equipment; and
through one of its subsidiaries, the gathering and marketing of natural gas. The
term "Company" is used herein to refer to Spindletop Oil & Gas Co. and its
wholly owned subsidiaries, Prairie Pipeline Co. ("PPL") and Spindletop Drilling
Company ("SDC") .
The net crude oil and gas reserves of the Company as of December 31, 2000, were
18,971 barrels of oil and condensate and 2,833,123 MCF (thousand cubic feet) of
natural gas. The Company owns rental equipment, including natural gas
compressors, pumping units, natural gas dehydrators and other various pieces of
oilfield production equipment. In addition, the Company, through PPL, owns
approximately 26.1 miles of pipelines located in Texas, which are used for the
gathering of natural gas. The Company's principal executive offices are located
at 9319 LBJ Freeway, Suite #205, Dallas, Texas. The telephone number is
(972)644-2581.
BACKGROUND
The Company is a Texas Corporation. The Company was previously known as Prairie
States Energy Co. ("PSE"). On July 13, 1990, Spindletop Oil & Gas Co., a Utah
Corporation, ("SOG UTAH") merged into PSE, and the name of PSE was changed to
Spindletop Oil & Gas Co., the Company herein.
The Company was originally incorporated in Colorado as Mid-America Drilling &
Exploration, Inc., on August 9, 1978 as a wholly-owned subsidiary of Mid-America
Petroleum, Inc. ("MAP"). The principal business of the Company at that time was
contract drilling of oil and gas wells. The initial public offering of the
Company occurred by prospectus dated December 13, 1979. In January 1981, the
shares of the Company owned by MAP were distributed as a dividend to the
shareholders of MAP. The Company's name was changed to Prairie States
Exploration, Inc. on March 15, 1983. Prairie States Exploration, Inc. became
insolvent in late 1983, and filed for protection under Chapter 11 of the
Bankruptcy Code on December 14, 1983.
Prairie States Exploration, Inc. was successfully reorganized under Chapter 11
of the Bankruptcy Code, and the Bankruptcy Court approved the plan of
reorganization on September 9, 1985. Pursuant to the Plan, the Company merged
into a wholly-owned subsidiary, Prairie States Energy Co., a Texas Corporation.
The Plan of Reorganization was proposed and funded by Paul E. Cash.
Since the reorganization, the Company has engaged in the general oil and gas
business, including exploration, development, and production of oil and gas, the
rental of oilfield production equipment and the ownership and construction and
operation of pipelines for the gathering and marketing of natural gas. SOG Utah
was incorporated on August 15, 1975 as Main Street Equities, Inc., a Utah
corporation. SOG Utah sold 5,000,000 shares of common stock in a public offering
in 1976. Until 1981, the business of the company consisted of minor real estate
operations. In October 1981 the name was changed to Aledo Oil and Gas Company
and in January 1983 the name was changed to Spindletop Oil & Gas Co.
The name "Spindletop" has been used by Paul E. Cash since 1975 in conjunction
with several previous oil and gas businesses in which he was engaged.
2
On July 13, 1990, SOG Utah was merged into PSE, and the name of the surviving
company was changed to Spindletop Oil & Gas Co., a Texas corporation. In the
merger, each shareholder of PSE received one-half share of the common stock of
the surviving company, the Company, for each share of PSE owned prior to the
merger. Each shareholder of SOG Utah received one and one-half shares of the
common stock of the surviving company, for each share of SOG Utah owned prior to
the merger. After the merger, the Company had outstanding 44,922,564 shares of
common stock, 32,255,195 of which were owned by the shareholders of PSE and
12,667,369 by shareholders of SOG Utah. Shares issued to the former shareholders
of SOG Utah have not been registered with the Securities and Exchange Commission
but according to Rule 144-K these shares would automatically become free trading
three years from date of issuance. The Company's management believes that all
shares issued to the former shareholders of SOG Utah are now free trading in
accordance with Rule 144-K. On January 31, 1997, the Company effected a one for
six reverse stock split. The Company reduced the authorized common shares from
150,000,000 to 100,000,000 and increased the par value from $.001 to $.01 per
share.
Pursuant to a Stock Purchase Agreement dated December 1, 1999 between Paul E.
Cash (Mr. Cash) and Giant Energy Corp., (Giant) a Texas Corporation, on December
1, 1999, Giant purchased controlling interest in Spindletop Oil & Gas Co.
Giant purchased 5,860,889 shares of the Registrant's outstanding Common
Stock from Mr. Cash. After the transaction, Giant Energy owns 77.88 percent of
the Registrant's 7,525,804 shares of outstanding Common Stock. Giant Energy
acquired the above shares for $490,000 cash.Chris Mazzini, President of the
Company, is sole owner of Giant.
Prior to the Stock Purchase Agreement, control of the Registrant was held by Mr.
Cash, who owned 81.98 percent of the Registrant's outstanding Common Stock.
Prior to the transaction Mr. Cash was President and Chairman of the Board of the
Registrant. After the transaction, Mr. Cash resigned as President and Chairman
of the Board of Registrant, but he will remain a director of Registrant.
On December 1, 1999, Registrant acquired oil and gas properties and
equipment from Mr. Cash and Double River Investment Co. (owned 100% by Mr. Cash)
for a total purchase price of $460,885.04.
PLAN OF OPERATION
In 1995 the Company successfully concentrated its efforts on oil and gas
property acquisitions. With increased competition for oil and gas property
acquisitions and with a corresponding increase in oil and gas prices, the
Company, in 1996, returned its focus to its primary business of oil and gas
exploration and production. The Company's long-term strategy is to build an oil
and gas production company through an exploration program. Additionally, the
Company will continue to rework existing wells in an attempt to increase
production and reserves.
The Company will continue to generate and evaluate prospects using its own
staff. The Company intends to fund operations primarily from cash flow generated
by operations. The Company's primary area of operation has been and will
continue to be in Texas with an emphasis in the geological provinces known as
the Ft. Worth Basin in Texas.
3
The Company will attempt to expand its pipeline system. Expansion will be
dependent upon success in its exploration programs, since the majority of its
existing pipelines are connected to wells which the Company operates. In
addition, the oilfield rental equipment and compression business will be
expanded as needed, but this segment also depends upon the success of the
exploration and development program.
The Company in 1996 expanded its current pipeline system by 6.7 miles by
acquiring, at no cost, a pipeline system in Hood County, Texas. The Company sold
this pipeline in 1998 for a price of $30,000.
(b) Financial information relating to Industry Segments
The Company has two identifiable business segments: exploration, development and
production of oil and natural gas, and gas gathering and oil field equipment
rental. Footnote 15 to the Consolidated Financial Statements filed herein sets
forth the relevant information regarding revenues, income from operations and
identifiable assets for these segments.
(c) Narrative Description of Business
The Company and SDC are engaged in the exploration, development and production
of oil and natural gas, and the rental of oil and gas production equipment. PPL
is engaged in the gathering and marketing of natural gas.
(i) Principal Products, Distribution and Availability.
The principal products marketed by the Company are crude oil and natural gas
which are sold to major oil and gas companies, brokers, pipelines and
distributors, and oil and gas properties which are acquired and sold to oil and
gas development entities. Reserves of oil and gas are depleted upon extraction,
and the Company is in competition with other entities for the discovery of new
prospects.
The Company is also engaged in the gathering and marketing of natural gas
through its subsidiary PPL. The Company owns 26.1 miles of pipelines and
currently gathers approximately 697 MCF of gas per day. Gas is gathered for a
fee. Substantially all of the gas gathered by the Company is gas produced from
wells which the Company operates and in which it owns a working interest.
The Company is also engaged in the business of rental of oilfield production
equipment. The equipment is comprised of pumping units, compressors, gas
dehydrators and related production equipment. Substantially all of such
equipment is located on wells which the Company operates and in which it owns a
working interest.
(ii) Patents, Licenses and Franchises. Oil and gas leases of the Company are
obtained from the owner of the mineral estate. The leases are generally for a
primary term of 1 to 5 years, and in some instances as long as 10 years, with
the provision that such leases shall be extended into a secondary term and will
continue during such secondary term as long as oil and gas are produced in
commercial quantities or other operations are conducted on such leases as
provided by the terms of the leases. It is generally required that a delay
rental be paid on an annual basis during the primary term of the lease unless
the lease is producing. Delay rentals are normally $1.00 to $5.00 per net
mineral acre.
The Company currently holds interests in producing and non-producing oil and gas
leases. The existence of the oil and gas leases and the terms of the oil and gas
leases are important to the business of the Company because future additions to
reserves will come from oil and gas leases currently owned by the Company, and
others that may be acquired, when they are proven to be productive. The Company
is continuing to purchase oil and gas leases in areas where it currently has
production, and also in other areas.
4
(iii) Seasonality.
The Company's oil and gas activities generally are conducted on a year round
basis with only minor interruptions caused by weather.
(iv) Working Capital Items.
The Company finances the majority of its operations, including the purchase of
oil and gas leases, the development of wells, the construction of pipelines and
acquisition of oil field rental equipment from its internal working capital as
well as some borrowings.
(v) Dependence on Customers.
The following is a summary of significant purchasers of the oil and natural gas
produced by the Company for the three year period ended December 31, 1999:
Purchaser December 31, Percent (1)
--------- ------------------------------
2000 1999 1998
----- ----- -----
TXU Processing/Cantera Resources 23% 15% 13%
Mitchell Marketing Co. 24% 23% 22%
(1) Percent of total oil and gas sales
In the past The Company sold gas under long term contracts to TXU Processing,
formerly called Lone Star Gas Company its affiliates (now Cantera Resources).
Such contracts are no longer in effect. Gas previously marketed under those
contracts is now sold to other parties under market sensitive, short-term
contracts computed on a month to month basis.
Mitchell purchases gas at spot prices which are market sensitive and computed on
a monthly basis.
(vi) Competition.
Numerous entities and individuals, many of whom have far greater financial and
other resources than the Company, are active in the exploration for and
production of oil and gas. Substantial competition exists for leases, prospects
and equipment, all of which are necessary for successful operations. Competition
is focused primarily on the discovery of new prospects, which can be developed
and made productive.
The market prices received for the Company's products depend on a number of
factors beyond the control of the Company, including consumer demand, worldwide
availability, transportation facilities, and United States and foreign
government regulation of exports, imports, production and prices. Widely
fluctuating prices for oil and gas over recent years, have had a direct effect
on the profitability of the Company's operations.
(vii) Development Activities.
The Company's primary oil and gas prospect acquisition efforts have been in
known producing areas in the United States with emphasis devoted to Texas.
5
The Company intends to use a portion of its available funds to participate in
drilling activities. Any drilling activity is performed by independent drilling
contractors. The Company does not refine or otherwise process its oil and gas
production.
Exploration for oil and gas is normally conducted with the Company acquiring
undeveloped oil and gas prospects, and carrying out exploratory drilling on the
prospect with the Company retaining a majority interest in the prospect.
Interests in the property are sometimes sold to key employees and associated
companies at cost. Also, interests may be sold to third parties with the Company
retaining an overriding royalty interest, carried working interest, or
reversionary interest.
A prospect is a geographical area designated by the Company for the purpose of
searching for oil and gas reserves and reasonably expected by it to contain at
least one oil or gas reservoir. The Company utilizes its own funds to acquire
oil and gas leases covering the lands comprising the prospects. These leases are
selected by the Company and are obtained directly from the landowners, as well
as from landmen, geologists, other oil companies, some of whom may be affiliated
with the Company, and by direct purchase, farm-in, or option agreements. After
an initial test well is drilled on a property, any subsequent development of
such prospect will normally require the Company's participation for the
development of the discovery.
(viii) Environmental Regulation.
The Company's oil and gas exploration and production activities are subject to
Federal, State and environmental quality and pollution control laws and
regulations. Such regulations restrict emission and discharge of wastes from
wells, may require permits for the drilling of wells, prescribe the spacing of
wells and rate of production, and require prevention and clean-up of pollution.
Although the Company has not in the past incurred substantial costs in complying
with such laws and regulations, future environmental restrictions or
requirements may materially increase the Company's capital expenditures, reduce
earnings, and delay or prohibit certain activities. However, such restrictions
and requirements would also apply to the Company's competitors, and it is
unlikely that compliance by the Company would adversely affect the Company's
competitive position.
(ix) Additional Government Regulation.
In addition to environmental regulations, the production and sale of oil and gas
is subject to regulation by Federal, State and local governmental authorities
and agencies. Such regulations encompass matters such as the location and
spacing of wells, the prevention of waste, the rate of production, the sale
price of certain oil and gas, conservation, and safety.
Oil Price Regulation
Historically, regulatory policy affecting crude oil pricing was derived from the
Emergency Petroleum Allocation Act of 1973, as amended, which provided for
mandatory crude oil price controls until June 1, 1979, and discretionary
controls through September 30,1981. On April 5, 1979, President Carter directed
the Department of Energy to complete administrative procedures designed to phase
out, commencing June 1, 1979, price controls on all domestically produced crude
oil by October 1, 1981. However, on January 28, 1981, President Reagan ordered
the elimination of remaining federal controls on domestic oil production,
effective immediately. Consequently, oil may currently be sold at unregulated
prices.
6
Gas Price Regulation.
The Natural Gas Act of 1938 ("NGA") regulates the interstate transportation and
certain sales for resale of natural gas. The Natural Gas Policy Act of 1978
("NGPA") regulates the maximum selling prices of certain categories of gas,
whether sold in so-called "first sales" in interstate or intrastate commerce.
These statutes are administered by the Federal Energy Regulatory Commission
("FERC"). The NGPA established various categories of natural gas and provided
for graduated deregulation of price controls for first sales of several
categories of natural gas. With certain exceptions, all price deregulation
contemplated under the NGPA as originally enacted in 1978 has already taken
place. Under current market conditions, deregulated gas prices under new
contracts tend to be substantially lower than most regulated price ceilings
prescribed by the NGPA.
On July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 ("Decontrol
Act") was enacted. The Decontrol Act amended the NGPA to remove as of July 27,
1989 both price and non-price controls from natural gas not subject to a first
sale contract in effect on July 26, 1989. The Decontrol Act also provided for
the phasing out of all price regulation under the NGPA by January 1, 1993.
(x) Special Tax Provisions.
See footnote 7 to Consolidated Financial Statements
(xi) Employees.
The Company employs a total of 5 people. All are full-time employees.
(d) Financial information about foreign and domestic operations and export
sales.
All of the Company's business is conducted domestically, with no export sales.
7
Item 2. Properties
Oil and Gas Properties.
The following table sets forth pertinent data with respect to the Company-owned
oil and gas properties, all located within the continental United States, as
estimated by the Company:
Year Ended December 31,
2000 1999 1998
---------- ---------- ----------
Gas and Oil Properties (net) (1):
Proved Developed Gas Reserves-MCF (2) 2,204,137 1,683,667 1,699,425
Proved Undeveloped Gas Reserves-MCF(3) 628,986 227,077 299,112
Total Proved Gas Reserves-MCF 2,833,123 1,910,744 1,998,537
Proved Developed Crude Oil and
Condensate Reserves-Bbls (2) 18,971 22,562 33,920
Proved Undeveloped Crude Oil and
Condensate Reserves-Bbls (3) - - -
Total Proved Crude Oil and Condensate
Reserves-Bbls 18,971 22,562 33,920
Year Ended December 31,
2000 1999 1998
--------- ---------- ----------
Present Value of Estimated
Future Net Revenues
From Proved Reserves (4) (5):
Developed $ 5,254,000 $ 1,394,000 $ 1,405,000
Developed and Undeveloped 7,109,000 1,604,000 1,599,000
(1) The estimate of the net proved oil and gas reserves, future net revenues,
and the present value of future net revenues.
(2) "Proved Developed Oil and Gas Reserves" are reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods.
(3) "Proved Undeveloped Reserves" are reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion.
(4) "Estimated Future Net Revenues" are computed by applying current prices of
oil and gas, less the estimated future expenditures (based on current costs) to
be incurred in developing and producing the proved reserves.
8
(5) "Present Value of Estimated Future Net Revenues" is computed by discounting
the Estimated Future Net Revenues at the rate of ten percent (10%) per year in
accordance with the Securities and Exchange Commission Rules and Regulations.
The Company's working interests in exploration and development wells completed
during the years indicated were as follows:
Year Ended December 31,
2000 1999 1998
--------------- --------------- --------------
Gross Net Gross Net Gross Net
Exploratory wells:
Productive - - - - - -
Non-Productive - - - - - -
---- ---- ---- ---- ----- ----
Total - - - - - -
---- ---- ---- ---- ----- ----
Development wells:
Productive - - - - - -
Non-Productive - - - - - -
---- ---- ---- ---- ---- ----
Total - - - - - -
==== ==== ==== ==== ==== ====
Total Exploratory and
Development wells:
Productive - - - - - -
Non-Productive - - - - - -
---- ---- ---- ---- ---- ----
Total - - - - - -
==== ==== ==== ==== ==== ====
9
The following tables set forth additional data with respect to production from
Company-owned oil and gas properties, all located within the continental United
States:
Year Ended December 31,
------------------------------------------------
2000 1999 1998 1997 1996
--------- --------- ---------- --------- --------
Oil and Gas Production (net):
Gas-Mcf 479,769 277,834 350,566 357,166 371,074
Crude Oil and Condensate-Bbls 10,111 6,986 13,304 14,998 17,276
Average Sales Price Per
Unit Produced:
Gas-per Mcf $ 3.58 $ 2.20 $ 1.97 $ 2.66 $ 2.48
Crude Oil and Condensate-
per Bbl. $ 27.37 $ 16.70 $ 11.97 $ 20.29 $ 21.16
Average Production Cost Per
Equivalent Barrel (1) (2) $ 8.09 $ 9.59 $ 7.37 $ 8.90 $ 8.90
(1) Includes severance taxes and ad valorem taxes.
(2) Gas production is converted to equivalent barrels at the rate of six MCF per
barrel, representing the estimated relative energy content of natural gas to
oil.
The Company owns producing royalties and overriding royalties under properties
located in Texas. The revenues from these properties is not significant.
Current Activities - March 15, 2001:
- ------------------------------------
Gross Wells in Process of Drilling -0-
Net Wells in Process of Drilling -0-
Waterfloods in Process of Installation -0-
Pressure Maintenance Operations -0-
The Company is not aware of any major discovery or other favorable or adverse
event that is believed to have caused a significant change in the estimated
proved reserves since December 31, 2000.
Office Space.
The Company leases office space as follows:
Location Square Feet Lease Expires
Dallas, Texas 3,388 April 30, 2001
Pipelines.
The Company owns, through its subsidiary Prairie Pipeline Co., 26.1 miles of
natural gas pipelines in Parker, Palo Pinto and Eastland Counties, Texas. These
pipelines are steel and polyethylene and range in size from 2 inches to 6
inches. These pipelines primarily gather natural gas from wells operated by the
Company and in which the Company owns a working interest, but also for other
parties.
10
The Company normally does not purchase and resell natural gas, but gathers gas
for a fee. The fees charged in some cases are subject to regulations by the
State of Texas and the Federal Energy Regulatory Commission. Average daily
volumes of gas gathered by the pipelines owned by the Company was 697, 410 and
518 MCF per day for 2000, 1999, and 1998 respectively.
Oil Field Production Equipment.
The Company owns various natural gas compressors, pumping units, dehydrators and
various other pieces of oil field production equipment.
Substantially all of the equipment is located on oil and gas properties in which
the Company owns a working interest and which are operated by the Company. The
rental fees are charged as lease operating fees to each property and each owner.
Item 3. Legal Proceedings
Neither the Registrant nor its subsidiaries nor any officers or directors is a
party to any material pending legal proceedings for or against the Company or
its subsidiary nor are any of their properties subject to any proceedings.
Item 4. Submission of Matters of Security Holders to a Vote
None
11
PART II
Item 5. Market for the Company's Common Stock and Related Stockholder Matters.
No significant public trading market has been established for the Company's
common stock. The common stock of the Company is traded on an occasional basis
in the over the counter market. The Company does not believe that listings of
bid and asking prices for its stock are indicative of the actual trades of its
stock, since trades are made infrequently.
There is no amount of common stock that is subject to outstanding options or
warrants to purchase, or securities convertible into, common stock of the
Company. On January 31, 1997, the Company effected a one for six reverse stock
split. At that time, the Company reduced the authorized common shares from
150,000,000 to 100,000,000 and increased the par value from $.001 to $.01 per
share.
The approximate number of record holders of the Company's Common Stock on March
26, 2001, was 641.
The Company has not paid any dividends since its reorganization and it is not
contemplated that it will pay any dividends on its Common Stock in the
foreseeable future. There are no financing agreements in place which restrict
payment of dividends.
The Registrant currently serves as its own stock transfer agent and registrar.
Item 6. Selected Financial Data
The selected financial information presented should be read in conjunction with
the consolidated financial statements and the related notes thereto.
Years Ended December 31,
2000 1999 1998 1997 1996
----------- ----------- ----------- ----------- ------------
Total Revenue $ 2,345,000 $ 1,072,000 $ 1,239,000 $ 1,685,000 $ 1,693,000
Net Income(Loss 849,000 (271,000) (229,000) 83,000 141,000
Earnings Per Share(1) .11 (.04) (.03) .01 .02
At End of Periods
Total Assets 2,909,000 1,843,000 1,793,000 2,225,000 2,154,000
Long-Term Debt 246,000 308,000 - - -
(1) After 1 for 6 stock split discussed in Note 2 to Consolidated Financial
Statements.
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Liquidity and Capital Resources
The Company's operating capital needs, as well as its capital spending program
are generally funded from cash flow generated by operations. Because future cash
flow is subject to a number of variables, such as the level of production and
the sales price of oil and natural gas, the Company can provide no assurance
that its operations will provide cash sufficient to maintain current levels of
capital spending. Accordingly, the Company may be required to seek additional
financing from third parties in order to fund its exploration and development
programs.
12
Results of Operations:
2000 Compared to 1999
- ---------------------
Oil and gas revenues increased in 2000 due to two main factors. One, properties
that the Company purchased from Paul E. Cash on December 1, 1999 were in
production for the entire year of 2000. This also was the primary reason for the
increase in lease operating expenses. The second reason oil and gas revenues
increased was due to a dramatic increase in gas prices. An increase in oil
prices also contributed to the increase.
Operator overhead decreased in 2000. Due to the purchase of properties mentioned
above, the Company now owns a large percentage of those well resulting in less
operator overhead billed out to outside third parties.
Interest income increased in 2000 due to the increase of cash on hand. This cash
is primarily in money market accounts and certificates of deposit.
General and administrative expenses decreased in 2000. Upon the change in
control of the Company at the end of 1999 there was a reduction in staff. The
resulting salary reductions and related employee benefits were the primary
reason that general and administrative expenses decreased.
1999 Compared to 1998
- ---------------------
Oil and gas revenues decreased in 1999 due to a decrease in both oil and gas
production.
Lease operating expenses decreased in 1999. No major rework was done on existing
wells as compared to prior years.
During 1999 the company invested in the stock market and experienced a loss on
sale of securities.
1998 Compared to 1997
- ---------------------
Oil and gas revenues decreased primarily because of decreases in oil and gas
prices. There was also a slight decrease in production.
Lease operating expenses decreased because of a sale some oil and gas properties
and an overall decrease in the amount of repairs and maintenance required on
existing wells in 1998.
Gas pipeline sales and gas pipeline purchases decreased because of the sale
a pipeline in 1998 for $30,000. This pipeline had been obtained at no cost. The
$30,000 gain is reflected in other income.
Certain Factors That Could Affect Future Operations
- ---------------------------------------------------
Certain information contained in this report, as well as written and oral
statements made or incorporated by reference from time to time by the Company
and its representatives in other reports, filings with the Securities and
Exchange Commission, press releases, conferences, teleconferences or otherwise,
may be deemed to be 'forward-looking statements' within the meaning of Section
21E of the Securities Exchange Act of 1934 and are subject to the 'Safe Harbor'
provisions of that section.
13
Forward-looking statements include statements concerning the Company's and
management's plans, objectives, goals, strategies and future operations and
performance and the assumptions underlying such forward-looking statements. When
used in this document, the words "anticipates," "estimates," "expects,"
"believes," "intends," "plans" and similar expressions are intended to identify
such forward-looking statements. Actual results and developments could differ
materially from those expressed in or implied by such statements due to these
and other factors.
Item 8. Consolidated Financial Statements and Schedules, index at page 20.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
The accountants for the Company are Farmer, Fuqua, Hunt & Munselle, P.C.
Certified Public Accountants, who have prepared audit reports for the years
ended December 31, 1998, 1999, and 2000.
There have been no disagreements between the Company and Farmer, Fuqua, Hunt &
Munselle, P.C. on any matter of accounting principles or practices, financial
statement disclosure, or auditing scope or procedure.
14
PART III
Item 10. Directors and Executive Officers of the Registrant
(a) and (b)The Directors and Executive Officers of the Company and certain
information concerning them is set forth below:
Name Age Position
- ---- --- -------------------------------
Chris Mazzini 43 Director, President and Chairman of the
Board
Michelle Mazzini 39 Director and Secretary
Paul E. Cash 68 Director
All directors hold office until the next annual meeting of the shareholders or
until their successors are duly elected and qualified. Officers of the Company
serve at the discretion of the board of directors.
(c) Significant employees
Not applicable
(d) Family relationships
Michelle Mazzini is the wife of Chris Mazzini
(e) Business experience
Chris Mazzini, President graduated from the University of Texas at Arlington in
1979 with a Bachelor of Science degree in geology. Mr. Mazzini founded Giant
Energy Corp (Giant) in 1985 and has served as President of Giant since then. He
has worked in the oil and gas industry since 1978. He joined the Company in
December 1999 when he purchased controlling interest from Mr. Cash.
Michelle Mazzini, received her Bachelor of Science Degree in Business
Administration (accounting major) from the University of Southwestern Louisiana
where she graduated magna cum laude in 1985. Ms. Mazzini earned her law degree
from Louisana State University where she graduated Order of the Coif in 1988.
Ms. Mazzini serves as Vice President and legal counsel of Giant Energy Corp.
Paul E. Cash is a graduate of The University of Texas (B.B.A.-Accounting) and is
a Certified Public Accountant. He has been active in the oil and gas industry
for over 25 years, during which time he has served as financial officer of two
publicly-owned companies, Texas Gas Producing Co. and Landa Oil Co., and also
served as president of publicly-owned Continental American Royalty Co.,
Bloomfield Royalty Co., Southern Bankers Investment Co., Spindletop Oil & Gas
Co. (a Utah Corporation), Double River Oil & Gas Co., and Loch Exploration Inc.
Mr. Cash has also been an officer and part owner of several private oil and gas
companies and partnerships. Mr. Cash also formerly served as Mayor of the City
of Sunnyvale, Texas.
(f) Involvement in certain legal proceedings.
None of the directors or executive officers of the Registrant, during the past
five years, has been involved in any civil or criminal legal proceedings,
bankruptcy filings or has been the subject of an order, judgment or decree of
any Federal or State authority involving Federal or State securities laws.
15
Item 11. Executive Compensation
(a) Cash Compensation
For the year ended December 31, 2000, Mr. Mazzini, did not take any salary from
the Company. None of the Company's executive officers were paid cash
compensation at an annual rate in excess of $100,000.
(b) Compensation Pursuant to Plan. None
(c) Other Compensation
Key employees of the Company, may sometimes be assigned overriding royalty
interests and/or carried working interest in prospects acquired by or generated
by the Company. These interests normally vary from one-half to one percent for
each employee. There is no set formula or policy for such program, and the
frequency and amounts are largely controlled by the economics of each particular
prospect.
(d) Compensation of Directors
Directors are not currently compensated nor are there plans to compensate them
for their services on the board.
(e) Termination of Employment and Change of Control Arrangement
There are no plans or arrangements for payment to officers or directors upon
resignation or a change in control of the Registrant.
16
Item 12. Security Ownership of Certain Beneficial Owners and Management.
(a) & (b) Security ownership of certain beneficial owners and managers
The table below sets forth the information indicated regarding the ownership of
the Registrant's common stock, $.01 par value, the only outstanding voting
securities, as of December 31, 1999 with respect to: (i)any person who is known
to the Registrant to be the owner of more than five percent (5%) of the
Registrant's common stock;(ii) the common stock of the Registrant beneficially
owned by each of the directors of the Registrant and, (iii) by all officers and
directors as a group. Each person has sole investment and voting power with
respect to the shares indicated, except as otherwise set forth in the footnotes
to the table.
%BASED ON
NATURE OF OUTSTANDING
NAME AND ADDRESS NUMBER OF BENEFICIAL PERCENT OF
OF BENEFICIAL OWNER SHARES OWNERSHIP CLASS
- --------------------- --------- ----------- -----------
Chris Mazzini 5,898,543 Direct 78%
9319 LBJ Frwy, Suite 205
Dallas, TX 75243
Paul E. Cash 308,468 Direct 4%
9319 LBJ Frwy, Suite 205
Dallas, TX 75243
All officers and directors
as a group 6,207,011 82%
(c) Changes in control
The Company is not aware of any arrangements or pledges with respect to its
securities which may result in a change in control of the Company.
Item 13. Certain Relationships and Related Transactions (a) Transactions with
management and others.
None
(b) Certain Business Relationships
Key employees of the Company, may sometimes be assigned overriding royalty
interests and/or carried working interests in prospects acquired by or generated
by the Company. These interests normally vary from one-half to one percent for
each employee. There is no set formula or policy for such program, and the
frequency and amounts are largely controlled by the economics of each particular
prospect.
17
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
PART IV
(a) The following documents filed as part of this Report
1. Independent Auditors' Report
Consolidated Balance Sheets at December 31, 2000 and 1999
Consolidated Statements of Income (Loss) for the years
ended December 31, 2000, 1999, and 1998
Consolidated Statements of Changes in Shareholders' Equity for the years
ended December 31, 2000, 1999, and 1998
Consolidated Statements of Cash Flows for the years ended
December 31, 2000, 1999, and 1998
Notes to Consolidated Financial Statements
2. Financial Statement Schedules required to be filed by Item 8 and
Paragraph (d) of this Item 14
Schedule II Valuation and Qualifying Accounts All other schedules
have been omitted because they are not applicable or required under the
rules of Regulation S-X or the information has been supplied in the
consolidated financial statements or notes thereto.
Such schedules and reports are at page 40 of this Report.
3. The Exhibits are listed in the index of Exhibits Required by Item 601 of
Regulation S-K at Item (c) below and included at page 41.
(b) No Form 8-K was filed during the period covered by this Report.
(c) The Index of Exhibits is included following the Financial Statement
Schedules beginning at page 41 of this Report.
(d) The Index to Consolidated Financial Statements and Supplemental
Schedules is included following the signatures, beginning at page 20 of this
Report.
18
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Company has duly caused this Report to be signed on its behalf
by the undersigned, thereunto duly authorized.
SPINDLETOP OIL & GAS CO.
Dated March 29, 2001
By ______________________
Chris Mazzini
President, Director
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report
has been signed below by the following on behalf of the Company and in the
capacities and on the dates indicated.
Signatures Capacity Date
Principal Executive Officers:
President, Director March 29, 2001
- -----------------
Chris Mazzini
- ----------------- Secretary, Director March 29, 2001
Michelle Mazzini
- ----------------- Director March 29, 2001
Paul E. Cash
Principal Accounting Officer:
- ----------------- Controller March 29, 2001
Gary D. Goodnight
19
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
Index to Consolidated Financial Statements and Schedules
Page
----
Independent Auditors' Report............................................21
Consolidated Balance Sheets - December 31, 2000
and 1999.............................................................22-23
Consolidated Statements of Income (Loss) for the years
ended December 31, 2000, 1999 and 1998..................................24
Consolidated Statements of Changes in Shareholders'
Equity for the years ended December 31, 2000,
1999, and 1998..........................................................25
Consolidated Statements of Cash Flows for the
years ended December 31, 2000, 1999
and 1998................................................................26
Notes to Consolidated Financial Statements..............................27
Schedules for the years ended December 31, 2000,
1999 and 1998
II - Valuation and Qualifying Accounts.........................40
All other schedules have been omitted because they are not applicable, not
required, or the information has been supplied in the consolidated financial
statements or notes thereto.
20
INDEPENDENT AUDITORS' REPORT
Board of Directors and Shareholders
Spindletop Oil & Gas Co.
We have audited the accompanying consolidated balance sheets of Spindletop Oil &
Gas Co. (a Texas Corporation) and subsidiaries as of December 31, 2000 and 1999,
and the related consolidated statements of income (loss), changes in
shareholders' equity and cash flows for each of the three years in the period
ended December 31, 2000. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the consolidated financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the consolidated financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the consolidated financial position of
Spindletop Oil & Gas Co. and subsidiaries as of December 31, 2000 and 1999, and
the consolidated results of their operations and their cash flows for each of
the three years in the period ended December 31, 2000, in conformity with
generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the basic
consolidated financial statements taken as a whole. The schedules listed in the
index of consolidated financial statements are presented for purposes of
complying with the Securities and Exchange Commission's rules and are not part
of the basic consolidated financial statements. These schedules have been
subjected to the auditing procedures applied in the audits of the basic
consolidated financial statements and, in our opinion, fairly state, in all
material respects, the financial data required to be set forth therein in
relation to the basic consolidated financial statements taken as a whole.
FARMER, FUQUA, HUNT & MUNSELLE, P.C.
Dallas, Texas
March 27, 2001
21
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31,
2000 1999
------------ -----------
ASSETS
Current Assets
Cash $ 1,585,000 $ 284,000
Accounts receivable 340,000 267,000
Accounts receivable, related parties 8,000 59,000
------------ -----------
Total Current Assets 1,933,000 610,000
------------ -----------
Property and Equipment - at cost
Oil and gas properties (full cost method) 3,202,000 3,205,000
Rental equipment 405,000 405,000
Gas gathering systems 145,000 145,000
Other property and equipment 53,000 180,000
------------ -----------
3,805,000 3,935,000
Accumulated depreciation and amortization (2,829,000) (2,714,000)
------------ ------------
976,000 1,221,000
------------ ------------
Other Assets, net of accumulated amortization
of $101,000 at December 31,1999 - 12,000
------------ ------------
Total Assets $ 2,909,000 $ 1,843,000
============ ============
The accompanying notes are an integral part of these statements.
22
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - (Continued)
December 31,
2000 1999
------------- -------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities $ 472,000 $ 439,000
Notes payable, related party 92,000 -
Income tax payable 60,000 -
Tax savings benefit payable 97,000 97,000
------------ -------------
Total Current Liabilities 721,000 536,000
------------ -------------
Notes payable, related party 246,000 308,000
Deferred income tax payable 94,000 -
Shareholders' Equity
Common stock, $.01 par value;100,000,000
shares authorized;7,525,804 shares
issued and outstanding at December 31,
2000 and 1999) 75,000 75,000
Additional paid-in capital 733,000 733,000
Retained earnings 1,040,000 191,000
------------ ------------
1,848,000 999,000
------------ ------------
Total Liabilities And Shareholders' Equity $ 2,909,000 $ 1,843,000
=========== ===========
The accompanying notes are an integral part of these statements.
23
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
Years ended December 31,
2000 1999 1998
------------- ------------- -------------
Revenues
Oil and gas revenues $ 1,994,000 $ 729,000 $ 850,000
Revenue from lease operations 93,000 158,000 176,000
Gas pipeline sales - - 35,000
Gas gathering, compression and
equipment rental 161,000 128,000 138,000
Interest income 36,000 2,000 5,000
Other 61,000 55,000 35,000
----------- ------------ -------------
2,345,000 1,072,000 1,239,000
----------- ------------ -------------
Expenses
Pipeline and rental operations 29,000 50,000 86,000
Gas pipeline purchases - - 19,000
Lease operations 729,000 457,000 529,000
Depreciation and amortization 244,000 207,000 260,000
General and administrative 310,000 551,000 574,000
Loss on sale of securities - 78,000 -
Interest expense 30,000 - -
----------- ------------ -------------
1,342,000 1,343,000 1,468,000
----------- ------------ -------------
Income (Loss) Before Income Taxes 1,003,000 (271,000) (229,000)
Current income tax provision 60,000 - -
Deferred income tax provision 94,000 - -
---------- ----------- ------------
154,000 - -
---------- ----------- ------------
Net Income (Loss) $ 849,000 $ (271,000) $ (229,000)
=========== =========== ===========
Earnings (Loss)Per Share Of
Common Stock $ 0.11 $ (0.04) $ (0.03)
======= ======= ========
Weighted average shares outstanding 7,525,804 7,525,804 7,525,804
========= ========= =========
The accompanying notes are an integral part of these statements.
24
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2000, 1999, and 1998
Additional
Common Stock Paid-in Retained
Shares Amount Capital Earnings
-------- -------- ----------- ----------
Balance January 1, 1998 7,525,804 $ 75,000 $ 733,000 $ 691,000
Net income - - - (229,000)
---------- --------- ---------- -----------
Balance December 31, 1998 7,525,804 75,000 733,000 462,000
Net loss - - - (271,000)
---------- --------- ---------- -----------
Balance December 31, 1999 7,525,804 75,000 733,000 191,000
Net income - - - 849,000
---------- --------- ---------- ----------
Balance December 31, 2000 7,525,804 $ 75,000 $ 733,000 $ 1,040,000
========== ========= ========== ==========
The accompanying notes are an integral part of these statements.
25
SPINDLETOP OIL & GAS CO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31,
2000 1999 1998
---- ---- ----
Cash Flows from Operating Activities
Net Income (Loss) $ 849,000 $ (271,000) $ (229,000)
Reconciliation of net income (loss)
to net cash provided by (used for)
operating activities:
Depreciation and amortization 244,000 207,000 260,000
Amortization of note discount 30,000 - -
Other 10,000 (4,000) -
(Increase) decrease in accounts receivable (22,000) (1,000) 137,000
(Increase) decrease in inventory - - 8,000
Increase in current taxes payable 60,000 - -
Increase in deferred taxes payable 94,000 - -
Increase (decrease) in accounts payable 33,000 13,000 (202,000)
---------- ---------- ----------
Net cash provided by (used for)
operating activities 1,298,000 (56,000) (26,000)
---------- ---------- ----------
Cash Flows from Investing Activities
Capitalized acquisition, exploration
and development costs (61,000) - (188,000)
Proceeds from sale of properties 64,000 44,000 -
Proceeds from sale of other assets - 16,000 -
Proceeds from sale of property equipment - - 69,000
Purchase of property and equipment - (8,000) (9,000)
---------- --------- ----------
Net cash provided by (used for)
investing activities 3,000 52,000 (128,000)
---------- --------- ----------
Cash Flows from Financing Activities
Repayment of notes payable - - (1,000)
Advances to shareholder - - (5,000)
----------- --------- ----------
Net cash used for financing activities - - (6,000)
----------- --------- ----------
Increase (decrease) in cash 1,301,000 (4,000) (160,000)
Cash at beginning of period 284,000 288,000 448,000
----------- --------- ----------
Cash at end of period $ 1,585,000 $ 284,000 $ 288,000
========== =========== ==========
The accompanying notes are an integral part of these statements.
26
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION AND ORGANIZATION
Merger and Basis of Presentation
On July 13, 1990, Prairie States Energy Co., a Texas corporation, (the
Company) merged with Spindletop Oil & Gas Co., a Utah corporation (the Acquired
Company). The name of Prairie States Energy Co. was changed to Spindletop Oil &
Gas Co. at the time of the merger.
Organization and Nature of Operations
The Company was organized as a Texas Corporation in September 1985, in
connection with the Plan of Reorganization (the Plan), effective September 9,
1985, of Prairie States Exploration, Inc., (Exploration), a Colorado
Corporation, which had previously filed for Chapter 11 bankruptcy. In connection
with the Plan, Exploration was merged into the Company, with the Company being
the surviving corporation. After giving effect to the stock split discussed in
Note 2, up to a total of 166,667 of the Company's common shares may be issued to
Exploration's former shareholders. As of December 31, 2000, 1999, and 1998,
122,436 shares have been issued to former shareholders in connection with the
Plan.
Spindletop Oil & Gas Co. is engaged in the exploration, development and
production of oil and natural gas; the rental of oilfield equipment; and
through one of its subsidiaries, the gathering and marketing of natural gas.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A summary of the significant accounting policies consistently applied in the
preparation of the accompanying financial statements follows:
Consolidation
The consolidated financial statements include the accounts of Spindletop Oil
& Gas Co. and its wholly-owned subsidiaries, Prairie Pipeline Co. and Spindletop
Drilling Company. All significant intercompany transactions and accounts have
been eliminated.
Oil and Gas Properties
The Company follows the full cost method of accounting for its oil and gas
properties. Accordingly, all costs associated with acquisition, exploration and
development of oil and gas reserves are capitalized and accounted for in cost
centers, on a country-by-country basis. If unamortized costs within a cost
center exceed the cost center ceiling (as defined), the excess is charged to
expense during the year in which the excess occurs.
Depreciation and amortization for each cost center are computed on a composite
unit-of-production method, based on estimated proved reserves attributable to
the respective cost center. All costs associated with oil and gas properties are
currently included in the base for computation and amortization. Such costs
include all acquisition, exploration and development costs. All of the Company's
oil and gas properties are located within the continental United States.
Gains and losses on sales of oil and gas properties are treated as adjustments
of capitalized costs. Gains or losses on sales of property and equipment, other
than oil and gas properties, are recognized as part of operations. Expenditures
for renewals and improvements are capitalized, while expenditures for
maintenance and repairs are charged to operations as incurred.
27
Property and Equipment
The Company, as operator, leases equipment to owners of oil and gas wells, on a
month-to-month basis.
The Company, as operator, transports gas through its gas gathering systems, in
exchange for a fee.
Depreciation is provided in amounts sufficient to relate the cost of depreciable
assets to operations over their estimated service lives (5 to 10 years for
rental equipment and gas gathering systems, 4 to 5 years for other property and
equipment). The straight-line method of depreciation is used for financial
reporting purposes, while accelerated methods are used for tax purposes.
Inventory
Inventory consists of oil field materials and supplies, stated at the lower of
average cost or market.
Goodwill
The goodwill resulting from the contingent consideration, as discussed in Note
7, is being amortized over the remaining life of the net operating loss existing
at the time of the Plan discussed in Note 1, which expires in 2000.
Income Taxes
The Company accounts for income taxes pursuant to Statement of Financial
Accounting Standards No. 109 "Accounting for Income Taxes" (SFAS 109), which
requires the recognition of deferred tax liabilities and assets for the expected
future tax consequences of events that have been recognized in the Company's
financial statements or tax returns. Under this method, deferred tax liabilities
and assets are determined based on the difference between the financial
statement carrying amounts and tax bases of assets and liabilities, using
enacted tax rates in effect in the years in which the differences are expected
to reverse. The temporary differences primarily relate to depreciation,
depletion and intangible drilling costs.
Investment Tax Credits
Investment tax credits are accounted for by the "flow-through" method which
recognizes the credits as a reduction of income tax expense in the year the
credit is utilized.
Use of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
Stock Split
In December 1996 the Board of Directors declared a 1-for-6 reverse stock split
on the Company's common stock. The record date was January 31, 1997. All share
and per share data as appropriate, reflect this split.
28
3. ACCOUNTS RECEIVABLE
December 31,
2000 1999
-------------- -------------
Trade $ 44,000 $ 378,000
Accrued receivable 324,000 187,000
Other 2,000 2,000
------------ -------------
370,000 567,000
Less allowance for losses (30,000) (300,000)
------------ -------------
$ 340,000 $ 267,000
============ ============
4. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
December 31,
2000 1999
---- ----
Trade payables $ 190,000 $ 56,000
Production proceeds payable 103,000 253,000
Accrued production taxes - 4,000
Other 179,000 126,000
-------- ----------
$ 472,000 $ 439,000
======== ==========
5. NOTES PAYABLE-RELATED PARTY
December 31,
2000 1999
------------ -----------
Non-interest bearing note to Paul Cash,
due in minimum monthly installments of
$3,333 beginning January, 2001, with
unpaid principal due November, 2008
($384,000 face value less amortized
discount of $143,000 and $120,000
at December 31, 2000 and 1999, respectively,
based on an effective interestrate of 8.50%).
The note is uncollateralized. (1) 264,000 241,000
Non-interest bearing note to Paul Cash,
due June, 2001 ($77,000 face value less
amortized discount of $10,000 and $3,000
at December 31, 2000 and 1999 respectively,
based on an effective interest rate of 8.50%).
The note is uncollateralized. 74,000 67,000
----------- ---------
338,000 308,000
Less current maturities 92,000 -
----------- ----------
$ 246,000 $ 308,000
=========== ==========
(1) This non-interest bearing note is payable in monthly installments of
$3,333 or 10 percent of net oil and gas revenues, whichever is greater.
Management can't possibly determine the actual monthly amounts due and
payable because of variables that affect net oil and gas revenues such as
price and production. For purposes of calculating the principal
maturities below the Company is using the required minimum payments of
$3,333.
29
Principal maturities of notes payable as of December 31, 2000 are
as follows:
Year Ended
December 31, Amount
--------------- ------------
2001 $ 92,000
2002 20,000
2003 22,000
2004 24,000
2005 26,000
Thereafter 154,000
------------
$ 338,000
=============
6. RELATED PARTY TRANSACTIONS
From March 1994 until 1998, the Company provided various personnel, office
space, supplies and other administrative services to a related company, Double
River Oil & Gas Co. (Double River) for a fee of $575 per month.
At December 31, 2000, and 1999, approximately $2,000 is due from Double River.
Beginning December 1, 1999 Giant Energy charged the Company $6,000 per month
management fee. Giant Energy loaned personnel to the Company and the management
fee was charged to recoup some of costs associated with work performed for the
Company.
Included in the accompanying balance sheets are the following amounts related
to Mr. Cash:
December 31,
2000 1999
--------- -----------
Notes payable, non-interest bearing $ 338,000 $ 308,000
7. INCOME TAXES
The Company accounts for income taxes pursuant to Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS 109). SFAS 109
utilizes the liability method of computing deferred income taxes.
In connection with the Plan discussed in Note 1, the Company agreed to pay, in
cash, to Exploration's unsecured creditors, as defined, one-half of the future
reductions of Federal income taxes which were directly related to any allowed
carryovers of Exploration's net operating losses and investment tax credits.
Such payments are to be made on a pro-rata basis. Amounts incurred under this
agreement, which are considered contingent consideration under APB No. 16,
totaled $ -0-, $ -0-, and $-0- in 2000, 1999 and 1998, respectively, and have
been recorded as goodwill. As of December 31, 2000 the Company has not received
a ruling from the Internal Revenue Service concerning the net operating loss and
investment credit carryovers. Until the tax savings which result from the
utilization of these carryforwards is assured, the Company will not pay to
Exploration's unsecured creditors any of the tax savings benefit. As of December
31, 2000 and 1999, the Company owes $97,000 and $97,000 respectively to
Exploration's unsecured creditors.
30
In calculating tax savings benefits described above, consideration was given to
the alternative minimum tax, where applicable, and the tax effects of temporary
differences, as shown below:
2000 1999 1998
------------ ----------- -----------
Intangible drilling costs $ - $ (4,000) $ (175,000)
Differences between book and tax
depreciation, depletion and amortization - 4,000 36,000
Income tax differed from the amounts computed by applying the U.S. federal
income tax rate of 35% to pretax income in 2000, 1999 and 1998 as a result
of the following:
2000 1999 1998
--------- --------- ---------
Computed expected tax expense $ 351,000 $ - $ -
Miscellaneous timing diferences (18,000) - -
Net operating loss carryforward (273,000) - -
-------- --------- ---------
$ 60,000 $ - $ -
========= ========= =========
Deferred income taxes reflect the effects of temporary differences between the
tax bases of assets and liabilities and the reported amounts of those assets and
liabilities for financial reporting purposes. Deferred income taxes also reflect
the value of net operating losses, investment tax credits and an offsetting
valuation allowance. The Company's total deferred tax assets and corresponding
valuation allowance at December 31, 2000 and 1999 consisted of the following:
December 31,
2000 1999
----------- -----------
Deferred tax assets
Net operating loss carryforwards $ - $ 209,000
Investment tax credit carryforwards 1,000 1,000
Depreciation, depletion and amortization 149,000 140,000
Other, net 7,000 7,000
------------ ------------
Total 157,000 357,000
Deferred tax liabilities
Expired leasehold (23,000) -
Intangible drilling costs (228,000) (229,000)
------------ -------------
Net deferred tax asset (94,000) 128,000
Less valuation allowance - (128,000)
------------ -------------
Net deferred tax asset (liability) $ (94,000) $ -
============ =============
31
SFAS 109 requires that a valuation allowance be recorded against tax assets
which are not likely to be realized. The Company's carryforwards expire at
specific future dates and utilization of certain carryforwards is limited to
specific amounts each year. However, due to the uncertain nature of their
ultimate realization based upon past performance and expiration dates, the
Company has established a full valuation allowance against the carryforward
benefits and is recognizing the benefits only as reassessment demonstrates they
are realizable. Realization is entirely dependent upon future earnings in
specific tax jurisdictions. While the need for this valuation allowance is
subject to periodic review, if the allowance is reduced, the tax benefits of the
carryforwards arising prior to reorganization will be credited to additional
paid-in capital, because they bear no relationship to current operations, while
the tax benefits of carryforwards arising after reorganization will be recorded
in future operations as a reduction of the Company's income tax expense.
9. CASH FLOW INFORMATION
The Company does not consider any of its assets to meet the definition of a cash
equivalent.
Net cash provided by operating activities includes cash payments for interest
of $ -0-, $ -0- and $ -0- in 2000, 1999, and 1998, respectively.
Excluded from the Consolidated Statements of Cash Flows were the effects of
certain non-cash investing and financing activities, as follows:
2000 1999 1998
------------ ---------- ----------
Purchase of equipment for note payable $ - $ 67,000 $ -
Purchase of oil and gas properties
for note payable - 240,000 -
Retirement of fixed assets 121,000 - -
10. EARNINGS PER SHARE
Earnings per share EPS) are calculated in accordance with Statement of Financial
Accounting Standards No. 128, Earnings per Share (SFAS 128), which was adopted
in 1997 for all years presented. Basic EPS is computed by dividing income
available to common shareholders by the weighted average number of common shares
outstanding during the period. Diluted EPS does not apply to the Company due to
the absence of dilutive potential common shares. All calculations have been
adjusted for the effects of the stock split discussed in Note 2. The adoption of
SFAS 128 had no effect on previously reported EPS.
11. CONCENTRATIONS OF CREDIT RISK
As of December 31, 2000, the Company had approximately $334,000 and $1,250,000
in checking accounts at two banks, respectively.
Most of the Company's business activity is in Texas. Accounts receivable as of
December 31, 2000 and 1999 are due from both individual and institutional owners
of joint interests in oil and gas wells. A portion of the Company's ability to
collect these receivables is dependent upon revenues generated from sales of oil
and gas produced by the related wells.
32
12. FINANCIAL INSTRUMENTS
The estimated fair value of the Company's financial instruments at
December 31, 2000 and 1999 follow:
2000 1999
Carrying Fair Carrying Fair
Amount Value Amount Value
----------- ----------- ---------- -----------
Cash $ 1,585,000 $ 1,585,000 $ 284,000 $ 284,000
Accounts receivable 340,000 340,000 267,000 267,000
Accounts receivable, related
parties 8,000 8,000 59,000 59,000
Notes payable 338,000 338,000 308,000 308,000
The fair value amounts for each of the financial instruments listed above
approximate carrying amounts due to the short maturities of these instruments.
13. COMMITMENTS AND CONTINGENCIES
In connection with the Plan of Reorganization discussed in Note 1, the Company
agreed to pay, in cash, to Exploration's unsecured creditors, as defined,
one-half of the future reduction of Federal income taxes which were directly
related to any allowed carryovers of Exploration's net operating losses and
investment tax credits existing at the time of the reorganization. These net
operating losses expired in 1998 and investment tax credits expired in 1997.
In June 1993, Spindletop Drilling Company entered into an agreement with Loch
Exploration, Inc., whereby the parties agreed to combine their talents and
resources to evaluate and acquire producing and non-producing oil and gas
properties at various auctions. Any such properties acquired under the terms of
this agreement are to be acquired by initial assignment to the Company. The
Company has agreed to provide Loch with a recordable assignment of its interest,
such interest to be determined by the proportionate share of monies expended for
the acquisition of said properties. All costs are to be borne by the Company and
Loch in the same proportions as their respective ownership interests. The
Company will serve as administrator for properties acquired in connection with
this agreement, and will be entitled to an overhead reimbursement for properties
for which the Company serves as operator. This agreement had an initial term of
six months, and continues month to month thereafter, until canceled by either
party.
In March 1994, the Company entered into an agreement with PGC Gas Company, an
unaffiliated entity, under terms similar to those of the agreement with Loch
Exploration, Inc., described above. This agreement had an initial term of six
months, to continue month to month thereafter and was cancelled in January,
2001.
The Company's oil and gas exploration and production activities are subject to
Federal, State and environmental quality and pollution control laws and
regulations. Such regulations restrict emission and discharge of wastes from
wells, may require permits for the drilling of wells, prescribe the spacing of
wells and rate of production, and require prevention and clean-up pollution.
Although the Company has not in the past incurred substantial costs in complying
with such laws and regulations, future environmental restrictions or
33
requirements may materially increase the Company's capital expenditures, reduce
earnings, and delay or prohibit certain activities.
14. ADDITIONAL OPERATIONS AND BALANCE SHEET INFORMATION
Certain information about the Company's operations for the years ended December
31, 2000, 1999, and 1998 follows.
Significant Oil and Gas Purchasers
The Company's oil sales are made on a day to day basis at approximately the
current area posted price. The loss of any oil purchaser would not have an
adverse effect upon operations. The Company generally contracts to sell its
natural gas to purchasers pursuant to both short-term and long-term contracts.
Additionally, some of the Company's natural gas not under contract is sold at
the then current prevailing "spot" price on a month to month basis. Following is
a summary of significant oil and gas purchasers during the three year period
ended December 31, 2000.
Year Ended
December 31,
2000 1999 1998
---- ---- ----
TXU Processing/Cantera
Resources and Affiliates 23% 15% 13%
Mitchell Marketing Co. 24 23 22
There are no other customers of the Company which individually accounted for
more than 10% of the Company's oil and gas revenues during the three years ended
December 31, 2000.
Year Ended December 31,
Capitalized costs relating to oil and gas 2000 1999 1998
producing activities: ------------ ------------ -----------
Unproved properties $ - $ 93,000 $ 89,000
Proved properties 3,202,000 3,112,000 2,919,000
------------ ------------ ------------
Total Capitalized Costs 3,202,000 3,205,000 3,008,000
Accumulated amortization (2,334,000) (2,128,000) (1,965,000)
----------- ----------- -----------
$ 868,000 $ 1,077,000 $ 1,043,000
=========== =========== ===========
34
Year ended December 31,
2000 1999 1998
----------- ---------- ----------
Costs incurred in oil and gas property
acquisition, exploration and
development:
Acquisition of Properties $ 61,000 $ 241,000 $ -
Exploration Costs - - 122,000
Development Costs - - 66,000
---------- ---------- ----------
$ 61,000 $ 241,000 $ 188,000
========== ========== ==========
Results of operations from producing activities: Year ended December 31,
------------------------------------
2000 1999 1998
----------- ----------- -----------
Sales of oil and gas $ 1,994,000 $ 729,000 $ 850,000
----------- ----------- -----------
Production costs 729,000 457,000 529,000
Amortization of oil and gas properties 206,000 163,000 207,000
----------- ---------- ----------
935,000 620,000 736,000
----------- ---------- ----------
$ 1,059,000 $ 109,000 $ 114,000
=========== ========== ==========
Year ended December 31,
2000 1999 1998
----------- ----------- ---------
Sales price per equivalent Mcf $ 3.69 $ 2.20 $ 1.97
======= ======= =======
Production cost per equivalent Mcf $ 1.35 $ 1.59 $ 1.23
======= ======= =======
Amortization per equivalent Mcf $ .38 $ .51 $ .48
======= ======= =======
Costs incurred in gas gathering
and equipment rental
Acquisition of property and equipment $ - $ - $ -
======== ======== =======
Results of operations from gas gathering
and equipment rental:
Revenues $ 161,000 $ 128,000 $ 173,000
--------- ---------- ----------
Gas pipeline purchases - - 19,000
Operating Expenses 29,000 50,000 86,000
Depreciation 20,000 14,000 21,000
-------- ---------- ---------
49,000 64,000 126,000
-------- ---------- ---------
$ 112,000 $ 64,000 $ 47,000
========= ========== ========
35
15. BUSINESS SEGMENTS
The Company's two business segments are (1) oil and gas exploration, production
and operations and (2) transportation and compression of natural gas, including
related equipment rental. Management has chosen to organize the Company into the
two segments based on the products or services provided.The following is a
summary of selected information for these segments for the three-year period
ended December 31, 2000:
2000 1999 1998
------------- ------------ ------------
Revenues:(3)
Oil and gas exploration,
production and operations $ 2,087,000 $ 887,000 $ 1,026,000
Gas gathering, compression and
equipment rental 161,000 128,000 173,000
------------ ------------ ------------
$ 2,248,000 $ 1,015,000 $ 1,199,000
============ ============ ============
Depreciation, depletion and
amortization expense:
Oil and gas exploration,
production and operations $ 206,000 $ 163,000 $ 207,000
Gas gathering and equipment rental 20,000 14,000 21,000
------------ ----------- -----------
$ 226,000 $ 177,000 $ 228,000
============ =========== ===========
Income from operations:
Oil and gas exploration,
production and operations $ 1,152,000 $ 267,000 $ 290,000
Gas gathering and equipment rental 112,000 64,000 47,000
------------ ----------- -----------
1,264,000 331,000 337,000
Corporate and other (1) (415,000) (602,000) (566,000)
------------ ----------- -----------
Consolidated net income (loss) $ 849,000 $ (271,000) $ (229,000)
============ =========== ===========
Identifiable assets:
Oil and gas exploration,
production and operations $ 868,000 $ 1,077,000 $ 1,043,000
Gas gathering & rental equipment 98,000 118,000 71,000
------------- ---------- ----------
966,000 1,195,000 1,114,000
Corporate and other (2) 1,943,000 648,000 679,000
------------- ---------- -----------
$ 2,909,000 $ 1,843,000 $ 1,793,000
============= ========== ===========
(1) Corporate and other includes general and administrative expenses, other
non-operating income and expense and income taxes.
(2) Corporate and other includes cash, accounts and notes receivable, inventory,
other property and equipment and intangible assets.
(3) All reported revenues are from external customers.
36
16. SUPPLEMENTARY INCOME STATEMENT INFORMATION
Charged
Directly to Expense
2000 1999 1998
----------- ---------- ----------
Maintenance and Repairs $ 29,000 $ 50,000 $ 86,000
Production taxes 102,000 41,000 45,000
Taxes, other than payroll and income taxes 9,000 12,000 23,000
17. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
The Company's net proved oil and gas reserves as of December 31, 2000, 1999 and
1998 have been estimated by Company personnel in accordance with guidelines
established by the Securities and Exchange Commission. Accordingly, the
following reserve estimates were based on existing economic and operating
conditions. Oil and gas prices in effect at December 31 of each year were used.
Operating costs, production and ad valorem taxes and future development costs
were based on current costs with no escalation.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting the future rates of production and timing of
development expenditures. The following reserve data represents estimates only
and should not be construed as being exact. Moreover, the present values should
not be construed as the current market value of the Company's oil and gas
reserves or the costs that would be incurred to obtain equivalent reserves.
Changes in Estimated Quantities of Proved Oil and Gas Reserves:
Oil Gas
Bbls Mcf
-------- ----------
Proved reserves:
Balance December 31, 1997 61,646 2,421,359
Sales of reserves in place - (50,843)
Revisions of previous estimates (14,422) (21,413)
Production (13,304) (350,566)
-------- ----------
Balance December 31, 1998 33,920 1,998,537
Sales of reserves in place (7,856) -
Acquired properties - 354,133
Revisions of previous estimates 3,484 (164,092)
Production (6,986) (277,834)
------- ----------
Balance December 31, 1999 22,562 1,910,744
Sales of reserves in place (2,008) -
Acquired properties 1,764 106,126
Revisions of previous estimates 6,764 1,296,022
Production (10,111) (479,769)
--------- ----------
Balance December 31, 2000 18,971 2,833,123
======= =========
Proved Developed Reserves:
Balance December 31, 1998 33,920 1,699,425
Balance December 31, 1999 22,562 1,683,667
Balance December 31, 2000 18,971 2,204,137
37
16. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) - Continued
Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil and Gas Reserves
(Unaudited)
The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
Relating to Proved Oil and Gas Reserves ("Standardized Measures") does not
purport to present the fair market value of a company's oil and gas properties.
An estimate of such value should consider, among other factors, anticipated
future prices of oil and gas, the probability of recoveries in excess of
existing proved reserves, the value of probable reserves and acreage prospects,
and perhaps different discount rates. It should be noted that estimates of
reserve quantities, especially from new discoveries, are inherently imprecise
and subject to substantial revision.
Future net cash flows were computed using the contract price which was not
escalated. Future production includes operating costs and taxes. No deduction
has been made for interest, general corporate overhead, depreciation or
amortization. Future income tax payable was not computed because of the net
operating loss carryforward (See Note 7). The annual discount of estimated
future net cash flows is defined, for use herein, as future cash flows
discounted at 10% per year, over the expected period of realization
Standardized Measures of Discounted December 31,
Future Net Cash Flows: 2000 1999 1998
-------------- ------------ -----------
Future production revenue $ 16,488,000 $ 4,643,000 $ 4,487,000
Future development costs (253,000) (110,000 (110,000)
Future production costs (6,150,000) (2,523,000) (2,238,000)
-------------- ------------ ----------
Future net cash flows before Federal
income tax 10,085,000 2,010,000 2,139,000
Future Federal income tax (1,513,000) - -
-------------- ----------- ----------
Future net cash flows 8,572,000 2,010,000 2,139,000
Effect of discounting 10%
Per year (1,463,000) (406,000) (540,000)
------------- ----------- ----------
$ 7,109,000 $ 1,604,000 $ 1,599,000
============= =========== ============
38
Change Relating to the Standardized
Measures of Discounted Future Net Cash
Flows: 2000 1999 1998
---------- ----------- -----------
Beginning balance $ 1,604,000 $ 1,599,000 $ 2,284,000
Oil and gas sales, net of
production costs (1,265,000) (272,000) (321,000)
Net change in prices, net of production
costs 4,230,000 (317,000) (211,000)
Purchase of reserves in place 83,000 825,000 -
Sales of reserves in place (13,000) (113,000) (73,000)
Revisions of quantity estimates 5,305,000 (171,000) (124,000)
Effect of income tax (1,513,000) - -
Accretion of discount 160,000 160,000 228,000
Changes in production rates, timing
and other (1,482,000) (107,000) (184,000)
----------- ----------- ----------
$ 7,109,000 $ 1,604,000 $ 1,599,000
=========== =========== ==========
39
SCHEDULE II
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2000, 1999, AND 1998
Charged To
Beginning Costs and Ending
Description Balance Expenses Deductions Balance
- ------------------------------- ----------- --------- ----------- -----------
Allowance for Doubtful Accounts
- -------------------------------
December 31, 1998 $ 230,000 20,000 - $ 250,000
======= ======= ======= =======
December 31, 1999 $ 250,000 50,000 - $ 300,000
======= ======= ======= =======
December 31, 2000 $ 300,000 30,000 300,000 $ 30,000
======= ======= ======== =======
40
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
Index to Exhibits
PAGE
22. Subsidiaries of the Registrant 42
41
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
Subsidiaries the Registrant
Prairie Pipeline Co. incorporated June 22, 1983, under the laws of the State
of Texas, is a wholly-owned subsidiary of Registrant.
Spindletop Drilling Company, incorporated September 5, 1975, under the laws of
the State of Texas, is a wholly-owned subsidiary of the Registrant.
42