UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 5(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2006
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 000-18774
SPINDLEOTP OIL & GAS CO.
(Exact name of registrant as specified in its charter)
Texas 75-2063001
(State or other jurisdiction IRS Employer
of Incorporation or organization Identification Number
12850 Spurling Rd., Suite 200, Dallas, TX 75230
(Address of principal executive office) (Zip Code)
(972) 644-2581
(Registrant's Telephone Number, including area code)
Securities registered pursuant to Section 12(b) of the Act
NONE
Securities registered pursuant to Section 12(g) of the Act
Common Stock, $0.01 par value
Indicate by check mark if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act. Yes [ ] No [ X ]
Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [ X ]
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 [ X ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K (Sec. 229.405 of this chapter) is not contained herein, and
will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. [ X ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [ ] No [ X ]
Indicate by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definitions of
"accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange
Act (check one).
Large accelerated filer [ ] Accelerated filer [ ] Non-accelerated filer [X]
Indicate by check mark whether the registrant is a shell company (as defined
in Rule 12b-2 of the Exchange Act. Yes [ ] No [X]
The aggregate market value of the shares of voting and non-voting common
equity held by non-affiliates of the Registrant, computed by reference to the
closing price at which the common equity was last sold which was the sales
price of the Common Stock on the (OTC) Stock Exchange as of June 30, 2006 (the
last business day of the Registrant's most recently completed second fiscal
quarter) was $8,296,799 based upon a total of 1,468,460 shares held as of June
30, 2006 by persons believed to be non-affiliates of the Registrant. The basis
of the calculation does not constitute a determination by the Registrant as
defined in Rule 405 of the Securities Act of 1933, as amended, such
calculation, if made as of a date within sixty days of this filing, would yield
a different value.
As of March 31, 2007, there were 7,595,803 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
NONE
PART I
Item 1. Description Of Business
GENERAL
Spindletop Oil & Gas Co. is an independent oil and gas company 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 terms the "Company", "We", "Us" or Spindletop are
used interchangeably herein to refer to Spindletop Oil & Gas Co. and its wholly
owned subsidiaries, Prairie Pipeline Co. ("PPC") and Spindletop Drilling
Company ("SDC").
The Company has focused its oil and gas operations principally in Texas,
although we operate properties in six states including: Texas, Oklahoma, New
Mexico, Louisiana, Alabama and Arkansas. We operate a majority of our projects
through the drilling and production phases. Our staff has a great deal of
experience in the operations arena. We have traditionally leveraged the risks
associated with drilling by obtaining industry partners to share in the costs
of drilling. However, we typically retain a controlling interest in the
prospects we drill.
In addition, the Company, through PPC, owns approximately 26.1 miles of
pipelines located in Texas, which are used for the gathering of natural gas.
These gathering lines are located in the Fort Worth Basin and are being
utilized to transport the Company's natural gas as well as natural gas
produced by third parties.
Website Access to Our Reports
-----------------------------
We make available free of charge through our website, www.spindletopoil.com ,
our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports
on form 8-K, and all amendments to those reports as soon as reasonably
practicable after such material is electronically filed with the Securities and
Exchange Commission. Information on our website is not a part of this report.
Operating Approach
------------------
We believe that a major attribute of the Company is its long history with, and
extensive knowledge of, the Fort Worth Basin of Texas. Our technical staff has
an average of over 27 years oil and gas experience, most of it in the
Fort Worth Basin.
One of our strengths has been the ability of the Company to look at cost
effective ways to grow our production. We have traditionally increased our
reserve base in one of two ways. Initially, in the 1970's and 1980's, the
Company obtained its production through an exploration and development drilling
program focused principally in Texas. Today, the Company has retained many of
these wells as producing properties and holds a large amount of acreage by
production.
- 3 -
From the 1990's through 2003, the Company took advantage of the lower product
prices by cost effectively adding to its reserve base through value-priced
acquisitions. We found that through selective purchases we could make
producing property acquisitions that were more cost effective than drilling.
During this time period, the Company acquired a large number of operated and
non-operated oil and gas properties in various states.
From 2003 to the present, we have returned our focus to a strategy of
development drilling. With higher product prices, we believe that it has been
more cost effective to drill on the Company's leasehold acreage rather than to
purchase production with escalated acquisition costs.
Our strategic focus in our drilling program is currently on the Barnett Shale
play located in the Fort Worth Basin of North Texas. The organic rich Barnett
Shale has been the source rock for the producing formations in the Fort Worth
Basin. As an unconventional fractured reservoir, the Barnett Shale itself has
become an attractive target due to technological advances in the drilling and
stimulation of tight gas formations. This technology driven play has the
potential of long life wells with the opportunity for multiple re-stimulations
which can significantly increase the commercial life of Barnett Shale wells.
The Company entered into a joint Barnett Shale horizontal drilling development
program with an unrelated company during the third quarter of 2006. Under the
terms of the Agreement, two Barnett Shale horizontal wells were drilled on the
Company's acreage of during the fourth quarter of 2006. The Hutcheson # 2H and
# 3H wells, located in the northeast quarter of Parker County, Texas were
completed during the first quarter of 2007. The Hutcheson # 2H well was placed
in production on February 20, 2007 at a rate of 1,174 thousand cubic feet of
gas per day("MCFG/D"). The Hutcheson # 3H well was placed in production on
March 15, 2007 at a rate of 1,057 MCFG/D. The Company holds a 50% working
interest in the wells.
During the first quarter of 2007, the third Barnett Shale horizontal well was
drilled on the Company's acreage under the terms of the Agreement. The
Harms # 4H well, located in the northeast quarter of Parker County, Texas was
drilled to a measured depth of 9,526 ft. and cased. This well is currently
awaiting completion. The Company holds a 50% working interest in the well.
It is anticipated that seven additional Barnett Shale horizontal wells will be
drilled during 2007 under the Agreement.
Strategic Business Plans
------------------------
One of our key strategies is to enhance shareholder value through
implementation of plans for controlled growth and development. The Company's
long-term focus is to grow its oil and gas production through a strategic
combination of selected property acquisitions, to the extent feasible, and an
exploration and development program primarily based on developing its leasehold
acreage. Additionally, the Company will continue to rework existing wells to
increase production and reserves.
- 4 -
The Company's primary area of operation has been and will continue to be in
Texas with an emphasis in the geological province known as the Ft. Worth Basin.
The Company is beginning to drill and develop its Fort Worth Basin producing
properties into the Barnett Shale formation. We want to capitalize on our
strengths which include a good knowledge of the Fort Worth Basin, experience in
operations in this geographic area, development of lease holdings, and
utilization of existing infrastructure to minimize costs.
The Company will continue to generate and evaluate prospects using its own
technical staff. The Company intends to fund operations primarily from cash
flow generated by operations.
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 that the Company operates.
Significant Project Areas
-------------------------
The Company has operations and well interests in 16 states; however, the
majority of reserves (86.40%) are located in Texas.
A breakout of the Company's most significant reserves by geographic area is
as follows:
Fort Worth Basin Texas 1,817,513 BOE 70.24 %
West Texas 186,448 BOE 7.21 %
East Texas 137,475 BOE 5.31 %
Oklahoma 112,507 BOE 4.35 %
Gulf Coast Texas 65,119 BOE 2.52 %
Louisiana 60,231 BOE 2.33 %
Alabama 56,874 BOE 2.20 %
New Mexico 44,126 BOE 1.71 %
Arkansas 35,908 BOE 1.39 %
Panhandle Texas 29,096 BOE 1.12 %
Kansas 22,228 BOE 0.86 %
North Dakota 9,077 BOE 0.35 %
Wyoming 6,330 BOE 0.24 %
Montana 4,207 BOE 0.16 %
Michigan 477 BOE 0.02 %
Total 2,587,616 BOE 100.00 %
The majority of our wells are located within a two-hour drive from our
corporate headquarters, which provides for more effective oversight of
operations.
Fort Worth Basin Texas
The Fort Worth Basin has been the focal point of the Company since its
inception. Our technical personnel have an average of 27 years of exploration,
drilling and production experience in the Basin. We also have an extensive
collection of geologic and engineering data.
- 5 -
The Fort Worth Basin is a gas prone region with multiple pay zones ranging in
depth from 1000-9000 feet. The basin is currently experiencing a drilling boom
due to increased natural gas prices and advances in fracturing technology that
have unlocked natural gas reserves from the Barnett Shale Formation.
The Barnett Shale is a thick blanket type formation covering the entire basin.
The natural gas reserves in place are significant; however, due to the
extremely low permeability of the shale, it has been technically difficult to
recover these reserves. Recent advances in hydraulic fracturing and horizontal
well technology have enabled economic recovery of natural gas reserves in the
Fort Worth Basin.
According to the U.S. Geological Survey, it is estimated that there is
approximately 26.7 trillion cubic feet (TCF) of undiscovered natural gas, 98.5
million barrels of undiscovered oil, and 1.1 billion barrels of undiscovered
natural gas liquids (condensate) in the Bend Arch-Fort Worth Basin Province and
more than 98 percent, or 26.2 TCF, of the undiscovered natural gas is located
in the Barnett Shale.
The Company has large lease-holdings in the Bend Arch Fort Worth Basin held by
production from shallower producing zones. We are planning to drill into the
Barnett Shale Formation on these leases. We are also actively seeking and
acquiring new leases in the Barnett Shale play.
The Company drilled two vertical Barnett Shale wells in Denton County, Texas
during the last quarter of 2007. The Olex US # 7 well reached its total depth
of 8,803 ft. on December 6, 200606 and production casing was set to the bottom.
The Olex US # 6 well reached its total depth of 8,870 ft. on December 30, 2006
and was production casing was also set to the bottom.
The Olex US # 7 well was completed during the first quarter of 2007 and was
placed into production at a rate of 1,253 MCFG/D and 15 barrels of oil per day
(BO/D) from the Upper and Lower Barnett Shale. The Olex US # 6 well is
currently being completed in the Upper and Lower Barnett Shale. The company
owns a 53% and 52.5% working interest in the Olex U.S. #6 and #7 wells,
respectively. The Olex U.S. lease is surrounded by productive Barnett Shale
gas wells and with existing spacing rules, an additional 27 vertical wells
could be drilled on this lease.
Joint Drilling Development of North Texas Barnett Shale Leasehold.
The Company entered into a joint Barnett Shale horizontal drilling development
program with an unrelated company during the third quarter of 2006. Under the
terms of the Agreement, two Barnett Shale horizontal wells were drilled on the
Company's acreage of during the fourth quarter of 2006. The Hutcheson # 2H and
# 3H wells, located in the northeast quarter of Parker County, Texas were
completed during the first quarter of 2007. The Hutcheson # 2H well was placed
in production on February 20, 2007 at a rate of 1,174 MCFG/D. The Hutcheson
# 3H well was placed in production on March 15, 20/07 at a rate of 1,057
MCFG/D. The Company holds a 50% working interest in the wells.
During the first quarter of 2007, the third Barnett Shale horizontal well was
drilled on the Company's acreage under the terms of the Agreement. The
Harms # 4H well, located in the northeast quarter of Parker County, Texas was
- 6 -
drilled to a measured depth of 9,526 ft. and cased. This well is currently
awaiting completion. The Company holds a 50% working interest in the well.
It is anticipated that seven additional Barnett Shale horizontal wells will be
drilled during 2007 under the Agreement.
Other than the Barnett Shale, the Company has other opportunities to optimize
existing natural gas production.
Arkansas
The Company participated during 2006 in the drilling of three development
wells in the Arkoma Basin of Arkansas. Two were completed as gas wells
(Marshall #9 and Paul X #5) and one was plugged (Paul X #4). The Marshall #9
well went online September 27, 2006 producing at a rate of 468 MCFG/D.
The Paul X #5 well went online July 7, 2006 producing at a rate of 1,339 MCFG/D
Montana
The Company has participated in the drilling and completion of one 2,000 ft.
development gas well in the Bowdoin gas field located in Phillips County,
Montana.
Texas
A company to which we granted a farm-out on a lease in Bee County, Texas, has
drilled and completed a second well on this lease during the first quarter of
2006. The Spindletop #2 well went into production at a rate of 178 MCFG/D and
22 BO/D during the first quarter of 2006 from a sand at 9,060 ft. The Company
has retained a 5.625% overriding royalty interest in this well.
In 2006, a company to which we granted a farm out on a lease in Ochiltree
County, Texas has drilled two wells on this lease and they are both currently
producing gas. The Pope 140 #3 and Pope 140 #4 wells were both placed into
production in January of 2007. The average daily production for the first month
was 59 MCFG/D from the Oswego and 400 MCFG/D from the Missippian Chester,
respectively. The Company has retained a 12.5% overriding royalty interest in
these wells
A company to which we granted a farm out on a lease in Parker County, Texas
drilled a well on this lease during the last quarter of 2005 . The Koonsman
#1H well was completed and placed into production during the first quarter of
2006. The well had an average daily sales volume of 156 MCFG/D for the first
month. The Company retained a 5.00% overriding royalty interest in this well.
Oklahoma
The Company participated in the drilling of the Dahlenburg 1-34 well located in
Caddo Co., OK, to approximately 12,950 feet to test the Springer Formation.
The Dahlenburg 1-34 well was spud on October 4, 2006 and the date of first
production was February 23, 2007.
The Company participated in the drilling of the Creach #4-2 well, a 13,300 ft.
Redfork well in Roger Mills, Co., OK. The well was completed and placed into
- 7 -
production at a rate of 1,242 MCFG/D and 5 BO/D during the second quarter of
2006.
The Company also participated in the drilling of two development Hoxbar wells
in the Elk City Unit located in Beckham Co., OK. Both wells were completed
during the fourth quarter of 2006.
The Company participated in the drilling of a Chester well in Beaver Co., OK.
The Miller #2-3 well was drilled and cased in the fourth quarter of 2006 and
placed into production in the first quarter of 2007.
Oil and Natural Gas Reserves
----------------------------
The net crude oil and gas reserves of the Company as of December 31, 2006 were
483,623 barrels of oil and condensate and 14,781,813 MCF (thousand cubic feet)
of natural gas. Based on SEC guidelines, the reserves were classified as
follows:
Proved Developed Producing 290,905 BO and 5.3 BCFG
Proved Developed Non-Producing 49,965 BO and 2.0 BCFG
Proved Undeveloped 15,752 BO and 6.0 BCFG
Total Proved Reserves 356,622 BO and 13.4 BCFG
Only reserves that fell within the Proved classification were considered.
Other categories such as Probable or Possible Reserves were not considered.
No value was given to the potential future development of behind pipe reserves,
untested fault blocks, or the potential for deeper reservoirs (other than
Barnett Shale proved undeveloped reserves directly offset by producing wells)
underlying the Company's properties. Shut-in uneconomic wells and insignificant
non-operated interests were excluded.
On a barrel of oil equivalent basis (6MCF/BOE), the reserves are
Natural Gas Reserves 2,230,994 BOE 86%
Oil Reserves 356,622 BOE 14%
Total Reserves 2,587,616 BOE 100%
Proved Developed Producing 1,177,600 BOE 46%
Proved Developed Non-Producing 388,688 BOE 15%
Proved Undeveloped 1,021,328 BOE 39%
Total Proved Reserves 2,587,616 BOE 100%
The Company has operational control over the majority of these reserves and can
therefore to a large extent control the timing of development and production.
The Company's Operated Wells 2,363,632 BOE 91%
Non Operated Wells 223,984 BOE 9%
Total 2,587,616 BOE 100%
Financial Information Relating to Industry Segments
--------------------------------------------------
The Company has three identifiable business segments: exploration, development
and production of oil and natural gas, gas gathering, and commercial real
- 8 -
estate investment. 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.
Narrative Description of Business
---------------------------------
The Company is engaged in the exploration, development and production of oil
and natural gas, and the gathering and marketing of natural gas. The Company
is also engaged in commercial real estate leasing through the acquisition and
partial occupancy of its corporate headquarters office building.
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 PPC, which owns 26.1 miles of pipelines and currently
gathers approximately 714 MCF of gas per day. Natural gas is gathered for a
fee. Substantially all of the gas gathered by the Company is gas produced
from wells that the Company operates and in which it owns a working interest.
In December, 2004, the Company purchased land and a two story commercial office
building in Dallas, Texas, which it has moved into and uses as its principal
headquarters office. The Company leases the remainder of the building to non-
related third party commercial tenants at prevailing market rates.
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.
- 9 -
Dependence on Customers
The following is a summary of significant purchasers from oil and natural
gas produced by the Company for the three-year period ended December 31, 2006:
Year Ended December 31, (1)
--------------------------------
Purchaser 2006 2005 2004
----------------------------------------- -------- -------- --------
Enbridge Energy Partners 38% 39% 14%
Shell Trading (US) Company 8% 7% 6%
ETC Texas Pipeline 5% -% -%
Plains Marketing, LP. 6% 6% 6%
Devon Gas Services, L.P 4% 6% 12%
Crosstex Energy Services, Ltd 3% 5% 8%
Empire Pipeline Corp 3% -% -%
Teppco Refining 3% -% -%
Dynegy Midstream Services, LIM -% 5% 11%
Panther Pipeline North Texas, Inc. -% -% 13%
LIG Chemical Company -% -% 2%
(1) Percent of Total Oil & Gas Sales
Oil and gas is sold to approximately 110 different purchasers (such as Devon
Gas Services, L.P., Enbridge Energy Partners (formerly Cantera Resources,
Inc.), Plains Marketing, L.P., Shell Trading (US) Company, Targa (formerly
Dynegy Midstream Services), Empire Pipeline Corporation, and Duke Energy Field
Services under market sensitive, short-term contracts computed on a month to
month basis.
Except as set forth above, there are no other customers of the Company that
individually accounted for more than 5% of the Company's oil and gas revenues
during the three years ended December 31, 2006.
The Company currently has no hedged contracts.
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.
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
a reversionary interest.
- 10 -
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 along with
the issuance of common stock and options to purchase common stock in some
cases, 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 land men, 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.
Special Tax Provisions
See Footnote 8 to Consolidated Financial Statements regarding the accounting
for income taxes.
Employees
The Company, on its own account and through a management contract with its
parent corporation, employs or contracts for the services of a total of 48
people. Fourteen are full-time employees or contractors. The remainder are
part-time contractors or employees. We believe that our relationships with
our employees are good.
In order to effectively utilize our resources in respect to our development
program, we employ the services of independent consultants and contractors to
perform a variety of professional and technical services, including in the
areas of lease acquisition, land-related documentation and contracts, drilling
and completion work, pumping, inspection, testing, maintenance and specialized
services. We believe that it can be more cost effective to utilize the
services of consultants and independent contractors for some of these services.
We depend to a large extent on the services of certain key management personnel
and officers, and the loss of any these individuals could have a material
adverse effect on our operations. The Company does not maintain key-main life
insurance policies on its employees.
Financial information about foreign and domestic operations and export sales
----------------------------------------------------------------------------
All of the Company's business is conducted domestically, with no export sales.
Compliance with Environmental Regulations
-----------------------------------------
Our oil and natural gas operations are subject to numerous U.S. Federal, state
and local laws and regulations relating to the protection of the environment,
including those governing the discharge of materials into the water and air,
the generation, management and disposal of hazardous substances and wastes and
clean-up of contaminated science. We could incur material costs, including
clean-up costs, fines and civil and criminal sanctions and third party claims
for property damage and personal injury as a result of violations of, or
liabilities under, environmental laws and regulations. Such laws and
- 11 -
regulations not only expose us to liability for our own activities, but may
also expose us to liability for the conduct of others or for actions by us
that were in compliance with all applicable laws at the time those actions
were taken. In addition, we could incur substantial expenditures complying
with environmental laws and regulations, including future environmental laws
and regulations which may be more stringent.
Spindletop Drilling Company ("SDC") has reached a tentative agreement with the
United States Government concerning an investigation conducted by the United
States Department of the Interior, Fish and Wildlife Service related to the
accidental deaths of several birds on one of SDC's east Texas leases. Under
the terms of the tentative agreement, SDC would accept a misdemeanor citation
with respect to the Migratory Bird Treaty Act, pay a $10,000 fine, and agree
to implement appropriate safeguards to further protect migratory birds. The
understanding, which could be implemented as early as the end of April, 2007,
would resolve the matter as to SDC and the Company
Item 1A. Risk Factors
Risks related directly to our Company
-------------------------------------
You should carefully consider the following risk factors, in addition to the
other information set forth in this Report, before investing in shares of our
common stock. Each of these risk factors could adversely affect our business,
operating results and financial condition, as well as adversely affect the
value of an investment in our common stock. Some information in this Report
may contain "forward-looking" statements that discuss future expectations of
our financial condition and results of operation. The risk factors noted in
this section and other factors could cause our actual results to differ
materially from those contained in any forward-looking statements.
We face significant competition, and many of our competitors have resources
in excess of our available resources.
The oil and gas industry is highly competitive. We encounter competition from
other oil and gas companies in all areas of our operations, including the
acquisition of producing properties and sale of crude oil and natural gas. Our
competitors include major integrated oil and gas companies and numerous
independent oil and gas companies, individuals and drilling and income
programs. Many of our competitors are large, well established companies with
substantially larger operating staffs and greater capital resources than us.
Such companies may be able to pay more for productive oil and gas properties
and exploratory prospects and to define, evaluate, bid for and purchase a
greater number of properties and prospects than our financial or human
resources permit. Our ability to acquire additional properties and to discover
reserves in the future will depend upon our ability to evaluate and select
suitable properties and to consummate transactions in this highly competitive
environment.
- 12 -
Exploratory drilling is a speculative activity that may not result in
commercially productive reserves and may require expenditures in excess of
budgeted amounts.
Drilling activities are subject to many risks, including the risk that no
commercially productive oil or gas reservoirs will be encountered. There can
be no assurance that new wells drilled by us will be productive or that we will
recover all or any portion of our investment. Drilling for oil and gas may
involve unprofitable efforts, not only from dry wells, but also from wells that
are productive but do not produce sufficient net revenues to return a profit
after drilling, operating and other costs. The cost of drilling, completing and
operating wells is often uncertain. Our drilling operations may be curtailed,
delayed or canceled as a result of a variety of factors, many of which are
beyond our control, including economic conditions, mechanical problems,
pressure or irregularities in formations, title problems, weather conditions,
compliance with governmental requirements and shortages in or delays in the
delivery of equipment and services. In today's environment, shortages make
drilling rigs, labor and services difficult to obtain and could cause delays or
inability to proceed with our drilling and development plans. Such equipment
shortages and delays sometimes involve drilling rigs where inclement weather
prohibits the movement of land rigs causing a high demand for rigs by a large
number of companies during a relatively short period of time. Our future
drilling activities may not be successful. Lack of drilling success could have
a material adverse effect on our financial condition and results of operations.
Our operations are also subject to all the hazards and risks normally incident
to the development, exploitation, production and transportation of, and the
exploration for, oil and gas, including unusual or unexpected geologic
formations, pressures, down hole fires, mechanical failures, blowouts,
explosions, uncontrollable flows of oil, gas or well fluids and pollution and
other environmental risks. These hazards could result in substantial losses to
us due to injury and loss of life, severe damage to and destruction of
property and equipment, pollution and other environmental damage and suspension
of operations. We participate in insurance coverage maintained by the operator
of its wells, although there can be no assurances that such coverage will be
sufficient to prevent a material adverse effect to us in such events.
The vast majority of our oil and gas reserves are classified as proved
reserves. Recovery of the Company's future proved undeveloped reserves will
require significant capital expenditures. Our management estimates that
aggregate capital expenditures of approximately $4,778,000 will be required to
fully develop some of these reserves in the next twenty-four months. No
assurance can be given that our estimates of capital expenditures will prove
accurate, that our financing sources will be sufficient to fully fund our
planned development activities or that development activities will be either
successful or in accordance with our schedule. Additionally, any significant
decrease in oil and gas prices or any significant increase in the cost of
development could result in a significant reduction in the number of wells
drilled and/or reworked. No assurance can be given that any wells will produce
oil or gas in commercially profitable quantities.
- 13 -
We are subject to uncertainties in reserve estimates and future net cash flows.
This annual report contains estimates of our oil and gas reserves and the
future net cash flows from those reserves, which have been prepared by
Netherland, Sewell & Associates, Inc., independent petroleum engineers. There
are numerous uncertainties inherent in estimating quantities of reserves of
oil and gas and in projecting future rates of production and the timing of
development expenditures, including many factors beyond our control. The
reserve estimates in this annual report are based on various assumptions,
including, for example, constant oil and gas prices, operating expenses,
capital expenditures and the availability of funds, and, therefore, are
inherently imprecise indications of future net cash flows. Actual future
production, cash flows, taxes, operating expenses, development expenditures
and quantities of recoverable oil and gas reserves may vary substantially from
those assumed in the estimates. Any significant variance in these assumptions
could materially affect the estimated quantity and value of reserves set forth
in this prospectus. Additionally, our reserves may be subject to downward or
upward revision based upon actual production performance, results of future
development and exploration, prevailing oil and gas prices and other factors,
many of which are beyond our control.
The present value of future net reserves discounted at 10% (the "PV-10") of
proved reserves referred to in this annual report should not be construed as
the current market value of the estimated proved reserves of oil and gas
attributable to our properties. In accordance with applicable requirements of
the SEC, the estimated discounted future net cash flows from proved reserves
are generally based on prices and costs as of the date of the estimate, whereas
actual future prices and costs may be materially higher or lower. Actual
future net cash flows also will be affected by: (i) the timing of both
production and related expenses; (ii) changes in consumption levels; and
(iii) governmental regulations or taxation. In addition, the calculation of the
present value of the future net cash flows using a 10% discount as required by
the SEC is not necessarily the most appropriate discount factor based on
interest rates in effect from time to time and risks associated with our
reserves or the oil and gas industry in general. Furthermore, our reserves may
be subject to downward or upward revision based upon actual production, results
of future development, supply and demand for oil and gas, prevailing oil and
gas prices and other factors. See "Properties - Oil and Gas Reserves."
We are subject to various operating and other casualty risks that could result
in liability exposure or the loss of production and revenues.
Our oil and gas business involves a variety of operating risks, including, but
not limited to, unexpected formations or pressures, uncontrollable flows of
oil, gas, brine or well fluids into the environment (including groundwater
contamination), blowouts, fires, explosions, pollution and other risks, any of
which could result in personal injuries, loss of life, damage to properties
and substantial losses. Although we carry insurance at levels that we believe
are reasonable, we are not fully insured against all risks. We do not carry
business interruption insurance. Losses and liabilities arising from uninsured
or under-insured events could have a material adverse effect on our financial
condition and operations.
- 14 -
From time to time, due primarily to contract terms, pipeline interruptions or
weather conditions, the producing wells in which we own an interest have been
subject to production curtailments. The curtailments range from production
being partially restricted to wells being completely shut-in. The duration of
curtailments varies from a few days to several months. In most cases, we are
provided only limited notice as to when production will be curtailed and the
duration of such curtailments. We are not currently experiencing any material
curtailment of our production.
We intend to increase our development and, to a lesser extent, exploration
activities. Exploration drilling and, to a lesser extent, development drilling
of oil and gas reserves involve a high degree of risk that no commercial
production will be obtained and/or that production will be insufficient to
recover drilling and completion costs. The cost of drilling, completing and
operating wells is often uncertain. Our drilling operations may be curtailed,
delayed or canceled as a result of numerous factors, including title problems,
weather conditions, compliance with governmental requirements and shortages or
delays in the delivery of equipment. Furthermore, completion of a well does not
assure a profit on the investment or a recovery of drilling, completion and
operating costs.
We depend to a large extent on the services of Chris G. Mazzini, our President,
Chairman of the Board, and Chief Executive Officer. The loss of the services
of Mr. Mazzini would have a material adverse effect on our operations. We have
not entered into any employment contracts with our executive officer and have
not obtained key personnel life insurance on Mr. Mazzini.
Certain of our affiliates control a majority of our outstanding common stock,
which may affect your vote as a shareholder.
Our executive officers, directors and their affiliates hold approximately 81%
of our outstanding shares of common stock. As a result, officers, directors
and their affiliates and such shareholders have the ability to exert
significant influence over our business affairs, including the ability to
control the election of directors and results of voting on all matters
requiring shareholder approval. This concentration of voting power may delay
or prevent a potential change in control.
Certain of our affiliates have engaged in business transactions with the
Company, which may result in conflicts of interest.
Certain officers, directors and related parties, including entities controlled
by Mr. Mazzini, the President and Chief Executive Officer, have engaged in
business transactions with the Company which were not the result of arm's
length negotiations between independent parties. Our management believes that
the terms of these transactions were as favorable to us as those that could
have been obtained from unaffiliated parties under similar circumstances.
All future transactions between us and our affiliates will be on terms no less
favorable than could be obtained from unaffiliated third parties and will be
approved by a majority of the disinterested members of our Board of Directors.
- 15 -
Our common stock is traded on the Over-the-Counter Bulletin Board ("OTC BB"),
symbol "SPND".
The liquidity of our common stock may be adversely affected, and purchasers of
our common stock may have difficulty selling our common stock, if our common
stock does not continue to trade in that or another suitable trading market.
There is presently only a limited public market for our common stock, and there
is no assurance that a ready public market for our securities will develop. It
is likely that any market that develops for our common stock will be highly
volatile and that the trading volume in such market will be limited. The
trading price of our common stock could be subject to wide fluctuations in
response to quarter-to-quarter variations in our operating results,
announcements of our drilling results and other events or factors. In
addition, the U.S. stock market has from time to time experienced extreme price
and volume fluctuations that have affected the market price for many companies
and which often have been unrelated to the operating performance of these
companies. These broad market fluctuations may adversely affect the market
price of our securities.
We do not intend to declare dividends in the foreseeable future.
Our Board of Directors presently intends to retain all of our earnings for the
expansion of our business. We therefore do not anticipate the distribution of
cash dividends in the foreseeable future. Any future decision of our Board of
Directors to pay cash dividends will depend, among other factors, upon our
earnings, financial position and cash requirements.
Our company employees and contract land professionals have reviewed title
records or other title review materials relating to substantially all of our
producing properties. The title investigation performed by us prior to
acquiring undeveloped properties is thorough, but less rigorous than that
conducted prior to drilling, consistent with industry standards. We believe we
have satisfactory title to all our producing properties in accordance with
standards generally accepted in the oil and gas industry. Our properties are
subject to customary royalty interests, liens incident to operating agreements,
liens for current taxes and other burdens, which we believe do not materially
interfere with the use of or affect the value of such properties. At December
31, 2006, our leaseholds for some of our net acreage were being kept in force
by virtue of production on that acreage in paying quantities. The remaining
net acreage was held by lease rentals and similar provisions and requires
production in paying quantities prior to expiration of various time periods
to avoid lease termination.
We expect to make acquisitions of oil and gas properties from time to time
subject to available resources. In making an acquisition, we generally focus
most of our title and valuation efforts on the more significant properties.
It is generally not feasible for us to review in-depth every property we
purchase and all records with respect to such properties. However, even an
in-depth review of properties and records may not necessarily reveal existing
or potential problems, nor will it permit us to become familiar enough with the
properties to assess fully their deficiencies and capabilities. Evaluation of
future recoverable reserves of oil and gas, which is an integral part of the
- 16 -
property selection process, is a process that depends upon evaluation of
existing geological, engineering and production data, some or all of which may
prove to be unreliable or not indicative of future performance. To the extent
the seller does not operate the properties, obtaining access to properties and
records may be more difficult. Even when problems are identified, the seller may
not be willing or financially able to give contractual protection against such
problems, and we may decide to assume environmental and other liabilities in
connection with acquired properties.
Our business is highly capital-intensive requiring continuous development and
acquisition of oil and gas reserves. In addition, capital is required to
operate and expand our oil and gas field operations and purchase equipment.
At December 31, 2006, we had working capital of $4,964,000. We anticipate that
we will be able to meet our cash requirements for the next 12 months. However,
if such plans or assumptions change or prove to be inaccurate, we could be
required to seek additional financing sooner than currently anticipated.
We have funded our operations, acquisitions and expansion costs primarily
through the generation of our internally generated cash flow. Our success in
obtaining the necessary capital resources to fund future costs associated with
our operations and expansion plans is dependent upon our ability to:
(i) increase revenues through acquisitions and recovery of our proved
producing and proved developed non-producing oil and gas reserves; and
(ii) maintain effective cost controls at the corporate administrative office
and in field operations. However, even if we achieve some success with our
plans, there can be no assurance that we will be able to generate sufficient
revenues to achieve significant profitable operations or fund our expansion
plans.
We have substantial capital requirements necessary for undeveloped properties
for which we may not be able to obtain adequate financing.
Development of our properties will require additional capital resources. We
have no commitments to obtain any additional debt or equity financing and there
can be no assurance that additional financing will be available, when required,
on favorable terms to us. The inability to obtain additional financing could
have a material adverse effect on us, including requiring us to curtail
significantly our oil and gas acquisition and development plans or farm-out
development of our properties. Any additional financing may involve
substantial dilution to the interests of our shareholders at that time.
Oil and natural gas prices fluctuate widely and low prices could have a
material adverse impact on our business and financial results.
Our revenues, profitability and the carrying value of its oil and gas
properties are substantially dependent upon prevailing prices of, and demand
for, oil and gas and the costs of acquiring, finding, developing and producing
reserves. Our ability to obtain borrowing capacity, to repay future
indebtedness, and to obtain additional capital on favorable terms is also
substantially dependent upon oil and gas prices. Historically, the markets for
oil and gas have been volatile and are likely to continue to be volatile in the
future. Prices for oil and gas are subject to wide fluctuations in response
- 17 -
to: (i) relatively minor changes in the supply of, and demand for, oil and
gas; (ii) market uncertainty; and (iii) a variety of additional factors, all
of which are beyond our control. These factors include domestic and foreign
political conditions, the price and availability of domestic and imported oil
and gas, the level of consumer and industrial demand, weather, domestic and
foreign government relations, the price and availability of alternative fuels
and overall economic conditions. Furthermore, the marketability of our
production depends in part upon the availability, proximity and capacity of
gathering systems, pipelines and processing facilities. Volatility in oil and
gas prices could affect our ability to market our production through such
systems, pipelines or facilities. As of December 31, 2006, approximately 70%
of our gas production is currently sold to eight gas marketing firms on a
month-to-month basis at prevailing spot market prices. Oil prices remained
subject to unpredictable political and economic forces during 2004, 2005 and
2006, and experienced fluctuations similar to those seen in natural gas prices
for the year. We believe that oil prices will continue to fluctuate in
response to changes in the policies of the Organization of Petroleum Exporting
Countries ("OPEC"), changes in demand from many Asian countries, current
events in the Middle East, security threats to the United States, and other
factors associated with the world political and economic environment. As a
result of the many uncertainties associated with levels of production
maintained by OPEC and other oil producing countries, the availabilities of
worldwide energy supplies and competitive relationships and consumer
perceptions of various energy sources, we are unable to predict what changes
will occur in crude oil and natural gas prices.
We may be responsible for additional costs in connection with abandonment of
properties.
We are responsible for payment of plugging and abandonment costs on its oil
And gas properties pro rata to our working interest. Based on our experience,
We anticipate that in most cases, the ultimate aggregate salvage value of lease
and well equipment located on our properties will exceed the costs of
abandoning such properties. There can be no assurance, however, that we will
be successful in avoiding additional expenses in connection with the
abandonment of any of our properties. In addition, abandonment costs and their
timing may change due to many factors, including actual production results,
inflation rates and changes in environmental laws and regulations.
Risks that Involve the Oil & Gas Industry in General.
-----------------------------------------------------
We are subject to various governmental regulations which may cause us to incur
substantial costs.
Our operations are affected from time to time in varying degrees by political
developments and federal, state and local laws and regulations. In particular,
oil and gas production related operations are or have been subject to price
controls, taxes and other laws and regulations relating to the oil and gas
industry. Failure to comply with such laws and regulations can result in
substantial penalties. The regulatory burden on the oil and gas industry
increases our cost of doing business and affects our profitability. Although
we believe we are in substantial compliance with all applicable laws and
- 18 -
regulations, because such laws and regulations are frequently amended or
reinterpreted, we are unable to predict the future cost or impact of complying
with such laws and regulations.
Sales of natural gas by us are not regulated and are generally made at market
prices. However, the Federal Energy Regulatory Commission ("FERC") regulates
interstate natural gas transportation rates and service conditions, which
affect the marketing of natural gas produced by us, as well as the revenues
received by us for sales of such production. Sales of our natural gas
currently are made at uncontrolled market prices, subject to applicable
contract provisions and price fluctuations that normally attend sales of
commodity products.
Since the mid-1980's, the FERC has issued a series of orders, culminating in
Order Nos. 636, 636-A and 636-B ("Order 636"), that have significantly altered
the marketing and transportation of natural gas. Order 636 mandated a
fundamental restructuring of interstate pipeline sales and transportation
service, including the unbundling by interstate pipelines of the sale,
transportation, storage and other components of the city-gate sales services
such pipelines previously performed. One of the FERC's purposes in issuing the
orders was to increase competition within all phases of the natural gas
industry. Order 636 and subsequent FERC orders issued in individual pipeline
restructuring proceedings have been the subject of appeals, and the courts have
largely upheld Order 636. Because further review of certain of these orders is
still possible, and other appeals may be pending, it is difficult to exactly
predict the ultimate impact of the orders on us and our natural gas marketing
efforts. Generally, Order 636 has eliminated or substantially reduced the
interstate pipelines' traditional role as wholesalers of natural gas, and has
substantially increased competition and volatility in natural gas markets.
While significant regulatory uncertainty remains, Order 636 may ultimately
enhance our ability to market and transport our natural gas, although it may
also subject us to greater competition, more restrictive pipeline imbalance
tolerances and greater associated penalties for violation of such tolerances.
The FERC has announced several important transportation-related policy
statements and proposed rule changes, including the appropriate manner in
which interstate pipelines release capacity under Order 636 and, more recently,
the price which shippers can charge for their released capacity. In addition,
in 1995, the FERC issued a policy statement on how interstate natural gas
pipelines can recover the costs of new pipeline facilities. In January 1997,
the FERC issued a policy statement and a request for comments concerning
alternatives to its traditional cost-of-service rate making methodology. A
number of pipelines have obtained FERC authorization to charge negotiated
rates as one such alternative. While any additional FERC action on these
matters would affect us only indirectly, these policy statements and proposed
rule changes are intended to further enhance competition in natural gas
markets. We cannot predict what the FERC will take on these matters, nor can
we predict whether the FERC's actions will achieve its stated goal of
increasing competition in natural gas markets. However, we do not believe that
we will be treated materially differently than other natural gas producers and
marketers with which we compete.
- 19 -
The price we receive from the sale of oil is affected by the cost of
transporting such products to market. Effective January 1, 1995, the FERC
implemented regulations establishing an indexing system for transportation rates
for oil pipelines, which, generally, would index such rates to inflation,
subject to certain conditions and limitations. These regulations could increase
the cost of transporting oil by interstate pipelines, although the most recent
adjustment generally decreased rates. These regulations have generally been
approved on judicial review. We are not able to predict with certainty the
effect, if any, of these regulations on its operations. However, the
regulations may increase transportation costs or reduce wellhead prices
for oil.
The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration for and production of oil and gas.
Such states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and gas properties,
the establishment of maximum rates of production from wells and the regulation
of spacing, plugging and abandonment of such wells. The statutes and
regulations of certain states limit the rate at which oil and gas can be
produced from our properties. However, we do not believe we will be affected
materially differently by these statutes and regulations than any other
similarly situated oil and gas company.
We are subject to various environmental risks which may cause us to incur
substantial costs.
Our operations and properties are subject to extensive and changing federal,
state and local laws and regulations relating to environmental protection,
including the generation, storage, handling and transportation of oil and gas
and the discharge of materials into the environment, and relating to safety and
health. The recent trend in environmental legislation and regulation generally
is toward stricter standards, and this trend will likely continue. These laws
and regulations may require the acquisition of a permit or other authorization
before construction or drilling commences and for certain other activities;
limit or prohibit construction, drilling and other activities on certain lands
lying within wilderness and other protected areas; and impose substantial
liabilities for pollution resulting from our operations. The permits required
for our various operations are subject to revocation, modification and renewal
by issuing authorities. Governmental authorities have the power to enforce
compliance with their regulations, and violations are subject to fines,
penalties or injunctions. In the opinion of management, we are in substantial
compliance with current applicable environmental laws and regulations, and we
have no material commitments for capital expenditures to comply with existing
environmental requirements. Nevertheless, changes in existing environmental
laws and regulations or in interpretations thereof could have a significant
impact on us. The impact of such changes, however, would not likely be any
more burdensome to us than to any other similarly situated oil and gas company.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, and similar state laws impose
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons that are considered to have contributed to the
- 20 -
release of a "hazardous substance" into the environment. These persons include
the owner or operator of the disposal site or sites where the release occurred
and companies that disposed or arranged for the disposal of the hazardous
substances found at the site. Persons who are or were responsible for releases
of hazardous substances under CERCLA may be subject to joint and several
liability for the costs of cleaning up the hazardous substances that have been
released into the environment and for damages to natural resources.
Furthermore, neighboring landowners and other third parties may file claims
for personal injury and property damage allegedly caused by the hazardous
substances released into the environment.
We generate typical oil and gas field wastes, including hazardous wastes that
are subject to the federal Resources Conservation and Recovery Act and
comparable state statutes. The United States Environmental Protection Agency
and various state agencies have limited the approved methods of disposal for
certain hazardous and non-hazardous wastes. Furthermore, certain wastes
generated by our oil and gas operations that are currently exempt from
regulation as "hazardous wastes" may in the future be designated as "hazardous
wastes," and therefore be subject to more rigorous and costly operating and
disposal requirements.
The Oil Pollution Act ("OPA") imposes a variety of requirements on responsible
parties for onshore and offshore oil and gas facilities and vessels related to
the prevention of oil spills and liability for damages resulting from such
spills in waters of the United States. The "responsible party" includes the
owner or operator of an onshore facility or vessel or the lessee or permittee
of, or the holder of a right of use and easement for, the area where an
onshore facility is located. OPA assigns liability to each responsible party
for oil spill removal costs and a variety of public and private damages from
oil spills. Few defenses exist to the liability for oil spills imposed by OPA.
OPA also imposes financial responsibility requirements. Failure to comply with
ongoing requirements or inadequate cooperation in a spill event may subject a
responsible party to civil or criminal enforcement actions.
We own or lease properties that for many years have produced oil and gas. We
also own natural gas gathering systems. It is not uncommon for such properties
to be contaminated with hydrocarbons. Although we or previous owners of these
interests may have used operating and disposal practices that were standard in
the industry at the time, hydrocarbons or other wastes may have been disposed
of or released on or under the properties or on or under other locations where
such wastes have been taken for disposal. These properties may be subject to
federal or state requirements that could require us to remove any such wastes
or to remediate the resulting contamination. All of our properties are
operated by third parties over whom we have limited control. Notwithstanding
our lack of control over properties operated by others, the failure of the
previous owners or operators to comply with applicable environmental
regulations may, in certain circumstances, adversely impact us.
Item 1B. Unresolved Staff Comments
None
- 21
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,
-----------------------------------
2006 2005 2004
----------- ----------- -----------
Gas and Oil Properties, net (1):
Proved developed gas reserves-Mcf (2) 7,353,000 7,110,000 6,888,000
Proved undeveloped gas reserves-Mcf (3) 6,033,000 7,672,000 6,844,000
----------- ----------- -----------
Total proved gas reserves-Mcf 13,386,000 14,782,000 13,732,000
=========== =========== ===========
Proved Developed Crude Oil and
Condensate reserves-Bbls (2) 341,000 434,000 390,000
Proved Undeveloped crude oil and
Condensate reserves-Bbls (3) 16,000 50,000 29,000
----------- ----------- -----------
Total proved crude oil and condensate
Reserves-Bbls 357,000 484,000 419,000
=========== =========== ===========
(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. See Footnote 18 to
the Financial Statements, Supplemental Reserve Information (Unaudited), for
further explanation of the changes for 2004 through 2006
- 22 -
Wells Drilled and Completed
---------------------------
The Company's working interests in exploration and development wells completed
during the years indicated were as follows:
Year Ended December 31,
-----------------------------------------
2006 2005 2004
------------- ------------- -------------
Gross Net Gross Net Gross Net
------ ------ ------ ------ ------ ------
Exploratory Wells (1):
Productive - - - - - -
Non-Productive - - - - - -
------ ------ ------ ------ ------ ------
Total - - - - - -
------ ------ ------ ------ ------ ------
Development Wells (2):
Productive 10.000 0.627 14.000 1.639 10.000 1.171
Non-Productive 1.000 0.006 - - - -
------ ------ ------ ------ ------ ------
Total 11.000 0.633 14.000 1.639 10.000 1.171
------ ------ ------ ------ ------ ------
Total Exploration & Development
Wells:
Productive 10.000 0.627 14.000 1.639 10.000 1.171
Non-Productive 1.000 0.006 - - - -
------ ------ ------ ------ ------ ------
Total 11.000 0.633 14.000 1.639 10.000 1.171
------ ------ ------ ------ ------ ------
(1) An exploratory well is a well drilled to find and produce oil or gas in an
unproven area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir.
(2) A development well is a well drilled within the proved area of an oil or
gas reservoir to the depth of a stratigraphic horizon known to be productive.
- 23 -
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:
For the years ended December 31
2006 2005 2004 2003 2002
-------- -------- -------- -------- --------
Oil and Gas Production, net:
Natural Gas (Mcf) 671,527 655,568 577,099 540,799 499,081
Crude Oil & Condensate (Bbl) 25,443 21,323 23,098 28,747 9,553
Average Sales Price per Unit
Produced:
Natural Gas ($/Mcf) $ 5.55 $ 6.74 $ 5.44 $ 4.33 $ 3.02
Crude Oil & Condensate($/Bbl)$ 53.14 $ 52.50 $ 38.90 $ 25.14 $ 23.27
Average Production Cost per
Equivalent Barrel (1) (2) $ 15.14 $ 13.38 $ 11.69 $ 10.41 $ 8.51
(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 relative energy content of natural gas to oil.
The Company owns producing royalties and overriding royalties under properties
located in Texas. The revenue from these properties is not significant.
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, 2006.
The Company currently has leases covering in excess of 7,300 gross acres in
Denton, Eastland, Erath, Hood, Palo Pinto, Parker, and Tarrant Counties, Texas
(currently held by production), that the Company believes may have drilling
locations in the Barnett Shale Formation. The Company has included some of
these potential locations in its calculation of proven undeveloped oil and gas
reserves. See Footnote 18 to the Financial Statement for an expanded
description of this activity.
OFFICE SPACE
On December 27, 2004, the Company acquired a commercial office building. The
property acquired is a two story multi-tenant, garden office building with a
sub-grade parking garage. The 25 year old building contains approximately
46,286 rentable square feet and sits on a 1.4919 acre block of land situated
in north Dallas, Texas in close proximity to hotels, restaurants and shopping
areas (the Galleria/Valley View Mall) with easy access to Interstate
Highway 635 (LBJ Freeway) and Dallas Parkway (North Dallas Toll Road). The
Company occupies approximately 8,668 square feet of the building as its primary
office headquarters, and leases the remaining space in the building to non-
related third party commercial tenants at prevailing market rates.
- 24 -
The address of the Company's principal executive offices is One Spindletop
Centre, 12850 Spurling Road, Suite 200, Dallas, Texas 75230. The telephone
number is (972) 644-2581.
PIPELINES
The Company owns, through its subsidiary, PPC, 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 4 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.
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 were 714, 821,
and 806 MCF per day for 2006, 2005, and 2004 respectively.
Oilfield 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
operated by the Company and in which it owns a working interest. The rental
fees are charged as lease operating fees to each property and each owner.
Chris G. Mazzini and Michelle H. Mazzini, through a limited partnership in
which they are limited partners, started an oil field service company which
provides roustabout, swabbing and completion services at rates which are at or
below market to the Company. The oil field service company plans to expand
equipment and services they provide. This oil field services company does work
exclusively for the Company and its parent company Giant Energy Corp. The
Company benefits by having immediate access to services in a tight market.
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
During the fourth quarter of the registrant's fiscal year covered by this
report, no matter was submitted to a vote of security holders of the
registrant.
- 25 -
PART II
Item 5. Market For The Company's Common Stock, Related Stockholder Matters
And Issuer Purchases Of Equity Securities.
The Company's common stock trades over-the-counter under the symbol "SPND".
Prior to 2004, no significant public trading market had been established for
the Company's common stock. 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. However during 2004, there was a
material increase in the number of shares traded and a material increase in the
stock price. The following table shows high and low trading prices for each
quarter in 2004, 2005 and 2006.
Price Per Share
High Low
2004
First Quarter 2.00 .70
Second Quarter 1.50 1.00
Third Quarter 2.45 1.30
Fourth Quarter 2.55 1.60
2005
First Quarter 5.50 2.00
Second Quarter 3.55 2.05
Third Quarter 4.20 1.90
Fourth Quarter 4.80 3.11
2006
First Quarter 5.15 3.26
Second Quarter 6.00 4.57
Third Quarter 6.25 4.95
Fourth Quarter 7.00 4.50
During the First Quarter of 2006, subsequent to year end, the following high
and low prices were recorded for the Company's common stock.
Price Per Share
High Low
2007
First Quarter 6.10 5.00
There is no amount of common stock that is subject to outstanding warrants to
purchase, or securities convertible into, common stock of the Company.
As of March 31, 2007, there were approximately 574 record holders of the
Company's Common Stock.
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. The Business Loan Agreement entered into between the
- 26 -
Company and JPMorgan Chase Bank for the purpose of acquiring the commercial
office building contains restrictions on the payment of dividends in the event
a default under terms of the Business Loan Agreement has occurred and is
continuing or would result from the payment of such dividends or distributions.
The Registrant currently serves as its own stock transfer agent and registrar.
During the fourth quarter of the fiscal year ended December 31, 2006, the
Company did not repurchase any of its equity securities. The Board of
Directors has not approved nor authorized any standing repurchase program.
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.
For the years ended December 31
2006 2005 2003 2003 2002
----------- ----------- ----------- ----------- -----------
Total Revenue $6,174,000 $ 6,395,000 $ 4,515,000 $ 2,458,000 $ 2,084,000
Net Income (Loss) 920,000 1,417,000 1,266,000 987,000 382,000
Earnings per Share $ 0.12 $ 0.19 $ 0.16 $ 0.13 $ 0.05
As of December 31,
2006 2005 2004 2003 2002
----------- ----------- ----------- ----------- -----------
Total Assets $13,024,000 $11,387,000 $ 9,715,000 $ 5,395,000 $ 3,764,000
Long-Term Debt 1,320,000 1,440,000 - - -
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.
- 27 -
Results of Operations:
-----------------------
2006 Compared to 2005
Oil revenues increased in 2006 over 2005 by approximately $233,000, an increase
of 20.8%. This was due to an increase in average oil prices from $52.50 per
bbl in 2005 to $53.14 per bbl in 2006 combined with an increase in production
from approximately 21,300 bbls in 2005 to approximately 25,400 bbls in 2006.
Increased production of approximately 4,000 bbls came primarily from the King-
Lowe, Peters #1, Pope 1&2 and Sharp 1-18 wells, all operated wells.
Gas revenue decreased in 2006 from 2005 by approximately $698,000, a decrease
of 15.7%. This was due primarily to a decrease in average gas prices from
$6.74 per mcf in 2005 to $5.55 per mcf in 2006. The decrease in price was
offset by an increase in production from approximately 656,000 mcf in 2005 to
approximately 672,000 mcf in 2006. Approximately 25,800 mcf of the increase
was due to the following non-operated wells; three new Tuit Draw wells in
Wyoming (12,200 mcf), the Giant Energy Porter #2 a new well (4,622 mcf), and
the Strauch #1, a new well (14,700 mcf). Several operated wells in Texas and
Louisiana had decreased production in 2006 of approximately 9,800 mcf as
compared with 2005. These wells were shut for a portion of 2006, due to
pipeline problems, salt water disposal well issues and other mechanical
problems that will be addressed as soon as practicable.
Interest income is up due to the Company's policy of investing excess cash
Funds in higher earning money market accounts and certificates of deposit as
opposed to checking accounts, as well as the higher level of cash balances
earning interest in 2006 as compared to 2005. Interest rates were also
slightly higher than in the previous year.
Lease operating expenses were higher in 2006 because costs to operate have
increased. As oil and gas prices have escalated, operating cost, costs of oil
field services and equipment have also increased.
Amortization of the full cost pot (depletion) decreased by approximately
$267,000 in 2006. This decrease was due to a decrease in the calculated basis
of the full-cost pot for the cost to develop undeveloped reserves from an
estimated $13 million in 2005 to an estimated $4 million in 2006. The decrease
in the estimated future development cost more than offset the depletion rate
increase from 4.2% in 2005 to 5.04% in 2006.
General and administrative expenses increased approximately $400,000 between
years. Almost all of the increase was due to direct and indirect personnel
costs of salary, contract labor, payroll taxes, benefits and associated
expenses associated with the increased number of technical and professional
personnel added to the Company's staff during 2006. Additionally, a portion
of the increase is attributable to the outsourcing of the Company's payroll
and benefits to Administaff.
The decrease in other revenues is due mainly to receipt of approximately
$24,000 more received in 2005 over the amounts received in 2006 for farm-outs
of leasehold interests held by the Company.
- 28 -
The increase in interest expense for 2006 was due to approximately $48,000 of
interest expense paid to interest owners on funds that had been suspended
awaiting the completion of title work to determine and verify the ownership of
the respective interests.
2005 Compared to 2004
Both oil and gas revenues increased for the year 2005. This was due primarily
to an approximate 24% increase in average gas prices from $5.44 per Mcf in 2004
to $6.74 per Mcf in 2005. Average oil prices received by the Company also
increased approximately 35% from $38.93 per bbl in 2004 to $52.50 in 2005.
Natural gas production was approximately 656,000 Mcf in 2005 compared to
approximately 577,000 in 2004, an increase of approximately 14%. The increased
gas production was due primarily to production added by the Olex wells in
Denton County, Texas which were completed early in 2005. Oil production was
approximately 21,300 bbls in 2005 compared to 23,000 bbls in 2004. an
approximate decrease 7%. This decrease in production was due primarily to the
curtailment of oil production in South Texas due to problems with some salt
water disposal facilities which the Company intends to correct during 2006.
Gas gathering and compression fee income was up slightly during 2005 as a
result of an increase in production from properties served by PPC. The
Company charges a fee for transportation of gas from the well site to the
purchaser's pipeline, and in some cases provides and charges for compression
services.
Interest income is up due to the Company's policy of investing excess cash
funds in higher earning money market accounts and certificates of deposit as
opposed to checking accounts, as well as the higher level of cash balances
earning interest in 2005 as compared to 2004. Interest rates were also
slightly higher than in the previous year.
Lease operating expenses were higher in 2005 because costs to operate have
increased. As oil and gas prices have escalated, operating cost, costs of oil
field services and equipment have also increased.
Amortization of the full cost pot (depletion) was up in 2005 due to an increase
in the cost of acquisitions and the projected cost to develop the proved
undeveloped reserves which were added to the full cost pot. In addition,
$230,000 was added to the depletable basis due to the implementation of FAS143
for the addition of the asset retirement obligation. The depletion rate also
increased from 4.2% in 2004 to 4.7% in 2005.
General and administrative expenses increased approximately $222,000 due to
direct and indirect personnel costs of salary, contract labor, payroll taxes,
benefits and associated expenses associated with the increased number of
personnel from twelve to fourteen full-time and from 44 to 48 part time and
contract employees. General liability insurance premium increases account
for the additional increases.
The increase in other revenues is due mainly to a $96,000 paid to the Company
for a farm-out of leasehold interest held by the Company, and approximately
$18,000 of plant product sales by PPC.
- 29 -
Interest expense for 2005 was due to the note payable incurred on December 27,
2004 for purchase of the Commercial office building.
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.
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 42
Item 9. Changes In And Disagreements With Accountants On Accounting And
Financial Disclosure
None
Item 9A(T). Controls And Procedures
Evaluation of Disclosure Controls and Procedures
A review and evaluation was performed by management under the supervision and
with the participation of the Acting Principal Executive Officer and Chief
Financial Officer of the effectiveness of the Company's disclosure controls and
procedures, as required by Rule 13a-15(b) of the Securities Exchange Act of
1934 as of December 31, 2006. Based upon that most recent evaluation, which
was completed as of the end of the period covered by this Form 10-K, the Acting
Principal Executive Officer and Chief Financial Officer concluded that the
Company's disclosure controls and procedures were effective at December 31,
2006 to ensure that information required to be disclosed in reports that the
Company files submits under the Securities Exchange Act of 1934 is recorded,
processed, summarized and timely reported as provided in the Securities and
Exchange Commission ("SEC") rules and forms. As a result of this evaluation,
there were no significant changes in the Company's internal control over
financial reporting during the three months ended December 31, 2006 that have
materially affected or are reasonably likely to materially affect the Company's
internal control over financial reporting.
- 30 -
Management Report on Internal Control Over Financial Reporting
Management of the Company is responsible for establishing and maintaining
adequate internal control over financial reporting as defined in
Rules 13a-15(b) and 15d-15(f) under the Securities Exchange Act of 1934, as
amended, as a process designed by, or under the supervision of the Company's
principal executive and principal financial officers and effected by the
Company's board, management and other personnel to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with accounting
principles generally accepted in the United States ("GAAP, US") and includes
those policies and procedures that:
- pertain to the maintenance of records that in reasonable detail
accurately and fairly reflect the transactions and dispositions of the assets
of a company;
- provide reasonable assurance that the transactions are recorded as
necessary to permit preparation of financial statements in accordance with
GAAP, US and that receipts and expenditures of a company are being made only in
accordance with authorization of management and directors of a company; and
- provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of a company's assets that could
have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial
reporting, including the possibility of human error and the circumvention or
overriding of controls, material misstatements may not be prevented or detected
on a timely basis. Projections of any evaluation of effectiveness to future
periods are subject to the risks that controls may become inadequate because
of changes and conditions or that the degree of compliance with policies or
procedures may deteriorate. Accordingly, even internal controls determine to
be effective can provide only reasonable assurance that information required
to be disclosed in and reports filed under the Securities Exchange Act of 1934
is recorded, processed, summarized and represented within the time periods
required.
This annual report does not include an attestation report of the Company's
registered public accounting firm regarding internal control over financial
reporting. Management's report was not subject to attestation by the Company's
registered public accounting firm pursuant to temporary rules of the SEC that
permit the Company to provide only management's report in this annual report.
Changes in Internal Control Over Financial Reporting.
There has been no change in the Registrant's internal control over financial
reporting during the quarter ended December 31, 2006, that has materially
affected, or is reasonably likely to materially affect, the Registrant's
internal control over financial reporting.
Item 9B. Other Information
Not Applicable
- 31 -
PART III
Item 10. Directors And Executive Officers Of The Registrant
The Directors and Executive Officers of the Company and certain information
concerning them is set forth below:
Name Age Position
---------------------- --- --------------------------------------
Chris G. Mazzini 49 Chairman of the Board, Director and
President
Michelle H. Mazzini 45 Director, Vice President, Secretary
Treasurer
Paul E. Cash 74 Director
All directors hold offices 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.
Business Experience
-------------------
Chris Mazzini, Chairman of the Board of Directors and President, graduated from
the University of Texas at Arlington in 1979 with a Bachelor of Science degree
in geology. He started his career in the oil and gas industry in 1978, and
began as a petroleum geologist with Spindletop in 1979, working the Fort Worth
Basin of North Texas. He became Vice President of Geology at Spindletop in
1982, and served in that capacity until he left the Company in 1985 when he
founded Giant Energy Corp. ("Giant"). Mr. Mazzini has served as President of
Giant since then. He rejoined the Company in December 1999 when he, through
Giant, purchased controlling interest from Mr. Cash. Mr. Mazzini has been
Chairman of the Board of Directors and President of the Company since 1999 and
is a Certified and Licensed Petroleum Geologist. Mr. Mazzini has worked
numerous geological basins throughout the United States with an emphasis on the
Fort Worth Basin. He is responsible for several new field discoveries in the
Fort Worth Basin.
Michelle Mazzini, Vice President and General Counsel, received her Bachelor of
Science Degree in Business Administration (Major: Accounting) from the
University of Southwestern Louisiana (now named University of Louisiana at
Lafayette) where she graduated magna cum laude in 1985. She earned her law
degree from Louisiana State University where she graduated Order of the Coif in
1988. Ms. Mazzini began her career with Thompson & Knight, a large law firm in
Dallas, where she focused her practice on general corporate and finance
transactions. She also worked as Corporate Counsel for Alcatel USA, a global
telecommunications manufacturing corporation where her practice was
broad-based. Ms. Mazzini serves as Vice President and General Counsel of the
Company.
- 32 -
Paul E. Cash, Director, 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 40 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. He 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.
Key Employees
In addition to the services provided through the management contract with Giant
by Mr. Mazzini, Ms. Mazzini (both of whom have biographies listed above) and
the services of another Giant employee, the Company also relies extensively on
the key employees identified below.
Robert E. Corbin, Controller, has been a full-time employee of Spindletop since
April 2002. From May 2001 until April 2002, Mr. Corbin was an independent
accounting consultant and devoted substantially all of his time to Spindletop.
He has been active in the oil and gas industry for over 32 years, during which
time he has served as financial officer of a publicly-held company as well as
several private oil and gas companies and partnerships. Mr. Corbin graduated
from Texas Tech University in 1969 with a BBA degree in accounting and began
his accounting career as an auditor with Arthur Andersen & Co. in 1970.
Mr. Corbin is a Certified Public Accountant.
Mark Cook, Petroleum Geologist, joined the Company in November 2006. He has
over 28 years experience in the oil and gas industry. Mr. Cook graduated from
The University of Texas at San Antonio in 1983 with a Bachelor of Science in
Geology. He has extensive experience in the Continental United States with a
focus in the Fort Worth Basin and Bend Arch region. Mr. Cook has worked as
Chief Geologist for Raw Energy Corp. in Weatherford, Texas, McClymond, LTD of
Breckenridge, Texas, and as a personal Geologist for Mr. Tex Moncrief, in Fort
Worth, Texas. Mr. Cook is a Licensed Professional Geoscientist in the state
of Texas.
Mike Keen, Operations Manager, joined the Company in March, 2006. Mr. Keen has
over 26 years experience in the oil and gas industry. He graduated magna cum
laude from Rose-Hulman Institute of Technology in May 1975 with a Bachelor of
Science degree in Mechanical Engineering. Mr. Keen started his career with
Texaco, Inc. in Great Bend, Kansas working primarily in the mid-continent area.
Mr. Keen then moved to North Texas and went to work for Mitchell Energy
Corporation primarily focusing on the Fort Worth Basin. He also worked for
Huffco in Indonesia, Aminoil in South Texas and most recently for Envirogas,
primarily in the Appalachian and Illinois Basins, before switching to the
"downstream" side of the industry to work for Indiana Gas Company the largest
gas utility in Indiana at the time.
Dick A. Mastin, Petroleum Landman, has been a full-time employee of the Company
since February, 2006. Mr. Mastin graduated cum laude from Stephen F. Austin
State University in 1980 with a Bachelor of Science in Forestry and a minor in
General Business. From September of 1980 until December of 1985, Mr. Mastin
- 33 -
worked for Spindletop Oil & Gas Co. as a Petroleum Landman. He received his
Masters of Science in Management and Administrative Sciences from the
University of Texas at Dallas in 1990. In January of 1987, he took a position
with the Dallas office of the Federal Bureau of Investigation. After a year
with the Bureau, he accepted a position with the Internal Revenue Service as a
Revenue Agent. Fifteen of his eighteen years with the Service were spent in
the Large and Mid-Sized Business unit auditing tax returns of the largest
business entities.
Glenn E. Sparks is the Land Director and also acts as Associate General Counsel
to the Company. Mr. Sparks was previously employed as a Landman by the Company
from 1982 through 1986, prior to attending law school. Mr. Sparks holds a
B.B.A. with a concentration in Finance from the University of Texas at
Arlington, and a J.D. from Texas Tech University School of Law. From 1990 to
2005, Mr. Sparks practiced law in a private practice focusing primarily on oil
and gas law and real estate, as a partner in the law firm of Logan & Sparks,
PLLC, and has acted as outside legal counsel for the Company in numerous oil
and gas transactions during his years in private practice. Mr. Sparks left his
private law practice and joined the Company again as an employee in his current
position in 2005. Mr. Sparks is Board Certified in Oil & Gas Mineral Law by
the Texas Board of Legal Specialization.
Family Relationships
Michelle Mazzini, Vice President, Secretary and General Counsel is the wife of
Chris Mazzini, Chairman of the Board and President.
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.
Item 11. Executive Compensation
Cash Compensation
-----------------
For the years ended December 31, 2006, 2005 and 2004, neither Mr. Mazzini nor
Ms. Mazzini received any salary from the Company. None of the executive
officers were paid cash compensation by the Company at an annual rate in excess
of $100,000. Mr. Mazzini and Ms. Mazzini are both employed by Giant.
Management fees the Company paid to Giant are used to reimburse a portion of
Mr. Mazzini's, Ms. Mazzini's and other Giant employees' salaries for time spent
working on matters for the Company.
The Company has no stock option or incentive plan, does not grant any
plan-based awards or awards of equity securities. The Company has no pension
plan for its employees.
- 34 -
Compensation Pursuant to Plan
None
Other Compensation
Key employees and officers 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 less than one
percent to three percent for each employee or officer. 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.
During 2006, the Company issued 10,000 shares of restricted common stock out
of Treasury Stock to a key employee, and during 2005, the Company issued 20,000
shares of restricted stock out of Treasury Stock to the same employee pursuant
to an employment package. Subsequent to year end, in March, 2007, the Company
issued 5,000 shares of restricted common stock out of Treasury Stock to a
second key employee, pursuant to an employment package. See Footnote No. 7,
to the Financial Statements for further detail.
Compensation of Directors
Directors are not currently compensated nor are there plans to compensate them
for their services on the board. In each of 2007 and 2006, Mr. Cash was paid
a director's fee for the previous year of $10,000 to compensate him for his
position as the Board of Directors' Financial Expert.
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.
Item 12. Security Ownership Of Certain Beneficial Owners And Management
Security Ownership of Certain Beneficial Owners and Managers
The table below sets forth the information indicated regarding ownership of the
Registrant's common stock, $.01 par value, the only outstanding voting
securities, as of December 31, 2006 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.
-35 -
Pct Based On
Nature of Outstanding
Name and Address Number Beneficial Percent of
Of Beneficial Owner of Shares Ownership Class
----------------------------------- -------------- ----------- ---------------
Chris Mazzini 5,900,543 (1) 77%
12850 Spurling Rd., Suite 200
Dallas, Texas 75230
Paul E. Cash 291,968 Direct 4%
12850 Spurling Rd., Suite 200
Dallas, Texas 75230
West Coast Asset Management, Inc. 419,652 (2) 5%
Paul J. Orfalea
Lance W. Helfert
R. Atticus Lowe
2151 Alessandro Drive, #100
Ventura, CA 93011
All officers and directors
as a group 6,192,511 81%
(1) Chris Mazzini directly owns 39,654 shares (1%). Giant Energy Corp.,
directly owns 5,860,889 shares (76%). Chris Mazzini owns 100% of the common
stock of Giant Energy Corp.
(2) According to Amendment No. 1 to Schedule 13G filed with the Commission by
these persons for event occurring January 24, 2007, each of the individually
named persons have shared power to vote or direct a vote as well as shared
power to dispose or direct the disposition of the aggregate amount of stock
owned.
Changes in control
------------------
The Company is not aware of any arrangements or pledges with respect to its
securities that may result in a change in control of the Company.
Item 13. Certain Relationships And Related Transactions
Transactions with management and others
---------------------------------------
Certain officers, directors and related parties, including entities controlled
by Mr. Mazzini, the President and Chief Executive Officer, have engaged in
business transactions with the Company which were not the result of arm's
length negotiations between independent parties. Our management believes that
- 36 -
the terms of these transactions were as favorable to us as those that could
have been obtained from unaffiliated parties under similar circumstances. All
future transactions between us and our affiliates will be on terms no less
favorable than could be obtained from unaffiliated third parties and will be
approved by a majority of the disinterested members of our Board of Directors.
There is a management services agreement between Giant and the Company.
Details of the agreement are shown below under Certain Business Relationships.
During 2005 the Company participated in the drilling of the Giant Energy Corp.
Porter #2 well, a vertical Barnett Shale well in Parker County, Texas, which
was completed in June 2005 with an initial production of 128 thousand cubic
feet of gas per day ("MCFG/D") and 1 barrel of oil per day ("BO/D"). The
Company owns a 35% working interest and a 26.25% net revenue interest in the
Porter #2 well. Giant Energy Corp owns a 19% working interest (15.2% net
revenue interest) and Chris Mazzini owns a 3.9% overriding royalty interest in
the well.
Chris G. Mazzini and Michelle H. Mazzini, through a limited partnership in
which they are limited partners, started an oil field service company which
provides roustabout, swabbing and completion services at rates which are at or
below market to the Company. The oil field service company plans to expand
equipment and services they provide. This oil field services company does work
exclusively for the Company and its parent company Giant Energy Corp. The
Company benefits by having immediate access to services in a tight market.
Certain Business Relationships
------------------------------
The long-term debt, which is secured by the commercial office building, is
also guaranteed individually by Chris G. Mazzini and Michelle H. Mazzini,
related parties.
There is a management services agreement between Giant and the Company which
has been in effect since 1999. This agreement provides monthly payments from
the Company to Giant in the amount of $20,000 in exchange for several of
Giant's personnel providing management, administrative and other services to
the Company and for the use of certain Giant assets. We believe the management
services agreement described above was made on terms no less favorable than if
we had entered into the transaction with an unrelated party.
The Company has entered into a management services agreement with M-R Oilfield
Services, LP ("MRO") whereby MRO makes monthly payments in the amount of $1,000
per month to the Company in exchange for the Company providing administrative
services to MRO. The Company has entered into a similar arrangement with
Peveler Pipeline, LP ("Peveler"), whereby Peveler pays the Company a monthly
charge of $200 in exchange for the Company providing administrative services to
Peveler. Chris and Michelle Mazzini are the owners of Peveler Pipeline, LP, a
limited partnership which owns a pipeline gathering system servicing wells
owned by Giant, another related entity, described elsewhere in this report.
Key employees and officers 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 less than one
- 37 -
percent to three percent for each employee or officer. 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. We believe that
these types of compensation arrangements enable us to attract, retain and
provide additional incentives to qualified and experienced personnel.
Item 14. Principal Accounting Fees And Services
The following table sets forth the aggregate fees for professional services
rendered to Spindletop Oil & Gas Co. and Subsidiaries for the years 2006, 2005
and 2004 by accounting firm, Farmer, Fuqua, & Huff, P.C.
Type of Fees 2006 2005 2004
Audit Fees $14,000 $14,000 $14,000
Audit related fees - - -
Tax fees - - -
All other fees - - -
Members of the Board of Directors (the "Board") fulfill the responsibilities
Of an audit committee and have established policies and Procedures for the
approval and pre-approval of audit services and permitted non-audit services.
The Board has the responsibility to engage and terminate Farmer, Fuqua, & Huff,
P.C. independent auditors, to pre-approve their performance of audit services
and permitted non-audit services, to approve all audit and non-audit fees, and
to set guidelines for permitted non-audit services and fees. All the fees for
2006, 2005 and 2004 were pre-approved by the Board or were within the pre-
approved guidelines for permitted non-audit services and fees established by
the Board, and there were no instances of waiver of approved requirements or
guidelines during the same periods.
- 38 -
PART IV
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as a part of this report:
(1) FINANCIAL STATEMENTS: The following financial statements of the
Registrant and Report of Independent Registered Public Accounting
Firm therein are filed as part of this Report on Form 10-K:
Page
Report of Farmer, Fuqua & Huff, P.C
Independent Registered Public Accounting Firm 43
Consolidated Balance Sheets 44
Consolidated Statement of Income 46
Consolidated Statement of Changes in
Stockholders' Equity 47
Consolidated Statements of Cash Flows 48
Notes to Consolidated Financial Statements 49
(2) FINANCIAL STATEMENT SCHEDULES: Other financial statement schedules
have been omitted because the information required to be set forth
therein is not applicable, is immaterial or is shown in the
consolidated financial statements or notes thereto.
(3) EXHIBITS
The following documents are filed as exhibits (or are incorporated by
reference as indicated) into this Report:
Exhibit
Designation Description
3.1 Articles of Incorporation of Spindletop Oil & Gas Co. (previously
filed with our General Form for Registration of Securities on
Form 10, filed with the Commission on August 14, 1990)
3.2 Bylaws of Spindletop Oil & Gas Co. (previously filed with our
General Form for Registration of Securities on Form 10, filed
with the Commission on August 14, 1990)
14* Code of Ethics for Senior Financial Officers
21* Subsidiaries of the Registrant
- 39 -
31.1* Rule 13a-14(a) Certification of Chief Executive Officer
31.2* Rule 13a-14(a) Certification of Chief Financial Officer
32* Officers' Section 1350 Certifications
-----------------------------
* Filed herewith
(b) The Index of Exhibits is included following the Financial Statement
Schedules beginning at page 52 of this Report.
(c) The Index to Consolidated Financial Statements and Supplemental Schedules
is included following the signatures, beginning at page 28 of this Report.
- 40 -
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: April 16, 2007
By /s/ Chris Mazzini
___________________________________
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:
/s/ Chris Mazzini
___________________________________ President, Director April 16, 2007
Chris Mazzini (Principal Executive
Officer)
/s/ Michelle Mazzini
___________________________________ Vice President, April 16, 2007
Michelle Mazzini Secretary, Treasurer,
Director
/s/ Robert E. Corbin
___________________________________ Controller (Principal April 16, 2007
Robert E. Corbin Financial and
Accounting Officer)
/s/ Paul E. Cash
___________________________________ Director April 16, 2007
Paul E. Cash
- 41 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
Index to Consolidated Financial Statements and Schedules
Page
Report of Independent Registered Public Accounting Firm 43
Consolidated Balance Sheets - December 31, 2006 and 2005 44
Consolidated Statements of Income for the years
Ended December 31, 2006, 2005 and 2004 46
Consolidated Statements of Changes in Shareholders'
Equity for the years ended December 31, 2006, 2005, and 2004. 47
Consolidated Statements of Cash Flows for the years ended
December 31, 2006, 2005 and 2004 48
Notes to Consolidated Financial Statements 49
Schedules for the years ended December 31, 2006, 2005 and 2004
II - Valuation and Qualifying Accounts 69
III - Real Estate and Accumulated Depreciation 70
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.
- 42 -
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and
Shareholders of 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, 2006 and
2005, and the related consolidated statements of income, shareholders' equity
and cash flows for each of the years in the three-year period ended
December 31, 2006. 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 the standards of the Public Company
Accounting Oversight Board (United States). 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. The
company is not required to have, nor were we engaged to perform, an audit of
its internal control over financial reporting. Our audit included
consideration of internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of the company's
internal control over financial reporting. Accordingly, we express no such
opinion. An audit also includes examining, on a test basis, evidence
supporting the amounts and disclosures in the consolidated financial
statements, 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 financial position of Spindletop
Oil & Gas Co. and subsidiaries as of December 31, 2006 and 2005, and the
consolidated results of their operations and their cash flows for each of the
years in the three-year period ended December 31, 2006 in conformity with
accounting principles generally accepted in the United States of America.
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 & HUFF, P.C.
Plano, Texas
April 13, 2007
- 43 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31
--------------------------
2006 2005
----------- -----------
ASSETS
Current Assets
Cash and cash equivalents $ 5,759,000 $ 5,508,000
Accounts receivable, trade 1,173,000 1,228,000
Prepaid expenses, related party 60,000 -
Prepaid income tax 426,000 -
----------- -----------
Total current assets 7,418,000 6,736,000
----------- -----------
Property and Equipment, at cost
Oil and gas properties (full cost method) 8,102,000 6,819,000
Rental equipment 399,000 399,000
Gas gathering systems 145,000 145,000
Other property and equipment 141,000 157,000
----------- -----------
8,787,000 7,520,000
Accumulated depreciation and amortization (5,257,000) (4,807,000)
----------- -----------
Total property and equipment, net 3,530,000 2,713,000
----------- -----------
Real Estate Property, at cost
Land 688,000 688,000
Commercial office building 1,508,000 1,298,000
Accumulated depreciation (120,000) (49,000)
----------- -----------
Total real estate property, net 2,076,000 1,937,000
----------- -----------
Other Assets - 1,000
----------- -----------
Total Assets $13,024,000 $11,387,000
=========== ===========
The accompanying notes are an integral part of these statements.
- 44 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - (Continued)
As of December 31
--------------------------
2006 2005
----------- -----------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable, current portion $ 120,000 $ 120,000
Accounts payable and accrued liabilities 2,237,000 1,943,000
Income tax payable - 20,000
Tax savings benefit payable 97,000 97,000
----------- -----------
Total current liabilities 2,454,000 2,180,000
----------- -----------
Noncurrent Liabilities
Notes payable, long-term portion 1,320,000 1,440,000
Asset Retirement Obligation 251,000 239,000
----------- -----------
Total noncurrent liabilities 1,571,000 1,679,000
----------- -----------
Deferred income tax payable 1,324,000 794,000
----------- -----------
Shareholders' Equity
Common stock, $.01 par value; 100,000,000
Shares authorized; 7,677,471 shares
issued and 7,595,803 shares outstanding at
December 31, 2006. 7,667,471 shares
issued and 7,585,803 shares outstanding at
December 31, 2005. 77,000 77,000
Additional paid-in capital 850,000 831,000
Treasury Stock at cost (40,000) (42,000)
Retained earnings 6,788,000 5,868,000
----------- -----------
Total shareholders' equity 7,675,000 6,734,000
----------- -----------
Total Liabilities and Shareholders' Equity $13,024,000 $11,387,000
=========== ===========
The accompanying notes are an integral part of these statements.
- 45 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Years Ended December 31,
-----------------------------------
2006 2005 2004
----------- ----------- -----------
Revenues
Oil and gas revenue $ 5,076,000 $ 5,541,000 $ 4,039,000
Revenue from lease operations 154,000 120,000 127,000
Gas gathering, compression and
Equipment rental 140,000 167,000 158,000
Real estate rental income 430,000 302,000 3,000
Interest income 275,000 132,000 100,000
Other 99,000 133,000 88,000
----------- ----------- -----------
Total revenue 6,174,000 6,395,000 4,515,000
----------- ----------- -----------
Expenses
Lease operations 2,106,000 1,747,000 1,235,000
Pipeline and rental operations 50,000 29,000 24,000
Real estate operations 330,000 484,000 2,000
Depreciation and amortization 528,000 795,000 498,000
Accretion of asset retirement obligation 34,000 - -
General and administrative 1,534,000 1,125,000 903,000
Interest expense 142,000 105,000 -
----------- ----------- -----------
Total expenses 4,724,000 4,285,000 2,662,000
----------- ----------- -----------
Income before income tax 1,450,000 2,110,000 1,853,000
----------- ----------- -----------
Current tax provision - 360,000 144,000
Deferred tax provision 530,000 333,000 443,000
----------- ----------- -----------
530,000 693,000 587,000
----------- ----------- -----------
Net income $ 920,000 $ 1,417,000 $ 1,266,000
=========== =========== ===========
Earnings per Share of Common Stock
Basic $ 0.12 $ 0.19 $ 0.16
=========== =========== ===========
Diluted $ 0.12 $ 0.19 $ 0.16
=========== =========== ===========
Weighted Average Shares Outstanding 7,589,995 7,573,365 7,567,875
=========== =========== ===========
Diluted Shares Outstanding 7,589,995 7,573,365 7,592,670
=========== =========== ===========
The accompanying notes are an integral part of these statements.
- 46 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2006, 2005 and 2004
Additional Treasury
Common Stock Paid-In Stock Retained
Shares Amount Capital Shares Amount Earnings
--------- -------- ---------- -------- -------- -----------
Balance at
December 31, 2003 7,677,471 77,000 796,000 103,334 (18,000) 3,185,000
Purchase of
Treasury Stock - - - 83,334 (40,000) -
Issuance of 75,000
shares of Common Stock
upon exercise of option
out of Treasury Stock - - 10,000 (75,000) 13,000 -
Net Income - - - - - 1,266,000
--------- -------- ---------- -------- -------- -----------
Balance at
December 31, 2004 7,677,471 77,000 806,000 111,668 (45,000) 4,451,000
Issuance of 20,000
shares of Common Stock
out of Treasury Stock
as part of an employee
compensation package - - 25,000 (20,000) 3,000 -
Net Income - - - - - 1,417,000
--------- -------- ---------- -------- -------- -----------
Balance at
December 31, 2005 7,677,471 $ 77,000 $ 831,000 91,668 $(42,000)$ 5,868,000
Issuance of 10,000
shares of Common Stock
out of Treasury Stock
as part of an employee
compensation package - - 19,000 (10,000) 2,000 -
Net Income - - - - - 920,000
--------- -------- ---------- -------- -------- -----------
Balance at
December 31, 2006 7,677,471 $ 77,000 $ 850,000 81,668 $ (40,000)$ 6,788,000
========= ======== ========== ======== ======== ===========
The accompanying notes are an integral part of these statements.
- 47 -
SPINDLETOP OIL & GAS CO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31,
-----------------------------------
2006 2005 2004
----------- ----------- -----------
Cash Flows from Operating Activities
Net Income $ 920,000 $ 1,417,000 $ 1,266,000
Reconciliation of net income
to net cash provided by
Operating Activities
Depreciation and amortization 528,000 795,000 498,000
Non-cash employee compensation 21,000 - -
Changes in prepaid expenses
to related party (60,000) - -
Changes in accounts receivable 55,000 (611,000) (52,000)
Changes in prepaid income tax (426,000) 190,000 (190,000)
Changes in accounts payable 293,000 (125,000) 1,106,000
Changes in current taxes payable (20,000) 20,000 (278,000)
Changes in deferred taxes payable 530,000 333,000 443,000
Changes in other assets 1,000 - 1,000
----------- ----------- -----------
Net cash provided by operating
activities 1,842,000 2,019,000 2,794,000
----------- ----------- -----------
Cash flows from Investing Activities
Capitalized acquisition, exploration
and development costs (1,271,000) (619,000) (884,000)
Purchase of property and equipment 10,000 (55,000) (18,000)
Capitalized tenant improvements (210,000) - (185,000)
Proceeds from sale of properties - 23,000 -
----------- ----------- -----------
Net cash used for investing activities
activities (1,471,000) (651,000) (1,087,000)
----------- ----------- -----------
Cash Flows from Financing Activities
Repayment of note payable to a bank (120,000) (240,000) -
Purchase of treasury stock - - (40,000)
Sale of common stock - 28,000 23,000
----------- ----------- -----------
Net cash used for financing
activities (121,000) (212,000) (17,000)
----------- ----------- -----------
Increase in cash 251,000 1,156,000 1,690,000
Cash at beginning of period 5,508,000 4,352,000 2,662,000
----------- ----------- -----------
Cash at end of period $ 5,759,000 $ 5,508,000 $ 4,352,000
=========== =========== ===========
The accompanying notes are an integral part of these statements.
- 48 -
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., a Texas corporation 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 a stock split,
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, 2006, 2005, and 2004,
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; and through one of its subsidiaries, the
gathering and marketing of natural gas.
On December 27, 2004, the Company purchased a commercial office building and
related land. The building contains approximately 46,286 of rentable square
feet, of which the Company occupies approximately 8,668 square feet as its
corporate office headquarters. The Company leases the remaining space in the
building to non-related third party commercial tenants at prevailing market
rates.
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 inter-company transactions and
accounts have been eliminated.
- 49 -
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 proven 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.
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.
Real Estate Property
--------------------
The Company owns land along with a two-story commercial office building which
is situated thereon. The Company occupies a portion of the building as its
primary corporate headquarters, and leases the remaining space in the building
to non-related third party commercial tenants at prevailing market rates. The
Company depreciates the commercial office using the straight-line method of
depreciation for financial statement and income tax purposes.
Investments in Real Estate and Oil and Gas Properties
-----------------------------------------------------
All investments in oil and gas properties and in real estate holdings are
stated at cost or adjusted carrying value. Statement of Financial Accounting
- 50 -
Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets" ("SFAS No. 144"), requires that a property be considered impaired if
the sum of the expected future cash flows (undiscounted and without interest
charges) is less than the carrying amount of the property. If impairment
exists, an impairment loss is recognized by a charge against earning equal to
the amount by which the carrying amount of the property exceeds fair market
value less cost to sell the property. If impairment of a property is
recognized, the carrying amount of the property is reduced by the amount of the
impairment, and a new cost for the property is established. Depreciation is
provided over the properties estimated remaining useful life. There was no
charge to earnings during 2006 due to impairment of oil and gas properties or
real estate holdings.
Accounting for Asset Retirement Obligations
-------------------------------------------
The Company adopted Statement of Financial Accounting Standards No. 143 ("SFAS
143") "Accounting for Asset Retirement Obligations" on December 31, 2005. The
adoption of SFAS 143 on December 31, 2005 resulted in a cumulative effect
adjustment to record a $239,000 increase in the carrying value of oil and gas
properties, and an asset retirement obligation liability of the same amount.
This statement requires the recording of a liability in the period in which an
asset retirement obligation ("ARO") is incurred, in an amount equal to the
discounted estimated fair value of the obligation that is capitalized.
Thereafter, each quarter, this liability is accreted up to the final retirement
cost. The determination of the ARO is based on an estimate of the future cost
to plug and abandon our oil and gas wells. The actual costs could be higher or
lower than current estimates.
The following table reflects the changes of the asset retirement obligations
during the current period.
Carrying amount of asset retirement obligation
at December 31, 2006 $ 239,000
Liabilities added 27,000
Liabilities divested or settled (49,000)
Current period accretion expenses 34,000
----------
Carrying amount as of December 31, 2006 $ 251,000
==========
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.
- 51 -
Use of Estimates
----------------
The preparation of financial statements in conformity with U. S. 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.
Share-Based Payments
--------------------
Effective January 1, 2006, the Company adopted the Financial Accounting
Standards Board's revised Statement of Financial Accounting Standards No. 123
(FAS 123R), "Share-Based Payment". FAS 123R requires compensation costs
related to share-based payments to be recognized in the income statement over
the requisite service period. The amount of the compensation cost is to be
measured based on the grant-date fair value of the instrument issued. FAS 123R
is effective for awards granted or modified after the date of adoption and for
awards granted prior to that date that have not vested. FAS 123R does not
materially change the Company's existing accounting practices or the amount of
share-based compensation recognized in earnings.
3. ACCOUNTS RECEIVABLE
December 31,
----------------------------
2006 2005
------------ ------------
Trade $ 530,000 $ 160,000
Accrued receivable 657,000 1,082,000
------------ ------------
1,187,000 1,242,000
Less: Allowance for losses (14,000) (14,000)
------------ ------------
$ 1,173,000 $ 1,228,000
============ ============
4. ACCOUNTS PAYABLE
December 31,
----------------------------
2006 2005
------------ ------------
Trade payables $ 213,000 $ 138,000
Production proceeds payable 1,385,000 1,153,000
Prepaid drilling costs 561,000 604,000
Other 78,000 48,000
----------- ------------
$ 2,237,000 $ 1,943,000
=========== ============
- 52 -
5. NOTES PAYABLE
December 31,
----------------------------
2006 2005
------------ ------------
Note payable to a bank with monthly
principal payments of $10,000 plus
Accrued interest; interest at a
variable annual interest rate based
upon an index which is the Treasury
Securities Rate for a term of seven
years, plus 2.20%. The interest rate
is subject to change on the first day
of each seven year anniversary after
the date of the note based on the Index
then in effect. As of the date of the
Loan, the annual interest rate was
6.11%. The note is collateralized by
land and commercial office building,
plus a guarantee by certain related
parties. $ 1,440,000 $ 1,560,000
Less current maturities 120,000 120,000
------------ ------------
Total notes payable, long-term portion $ 1,320,000 $ 1,440,000
============ ============
Estimated annual maturities for long-term debt are as follows:
2007 $ 120,000
2008 120,000
2009 120,000
2010 120,000
2011 120,000
thereafter 840,000
-----------
$ 1,440,000
===========
6. RELATED PARTY TRANSACTIONS
Since 1999 Giant Energy Corp. ("Giant") has charged the Company a fee pursuant
to a management services agreement. Effective January 1, 2003, this agreement
was amended to increase the monthly payments from the Company to Giant to
$20,000 in exchange for several of Giant's personnel providing management,
administrative and other services to the Company and for the use of certain
Giant assets. Giant is wholly owned by Chris Mazzini, President of the
Company. General and administrative expense for the years ended December 31,
2006, 2005 and 2004 includes $240,000, $240,000 and $240,000 respectively,
related to this agreement. In addition, prepaid expenses, related party, at
December 31, 2006 includes $60,000 related to this agreement.
The Company has entered into a management services agreement with M-R Oilfield
Services, LP ("MRO") whereby MRO makes monthly payments in the amount of $1,000
- 53 -
per month to the Company in exchange for the Company providing administrative
services to MRO. The Company has entered into a similar arrangement with
Peveler Pipeline, LP ("Peveler"), whereby Peveler pays the Company a monthly
charge of $200 in exchange for the Company providing administrative services to
Peveler. Chris Mazzini and Michelle Mazzini, President and Vice President
respectively of the Company are the owners of both MRO and Peveler.
The Company has guaranteed a $50,000 letter of credit and a $25,000 letter of
credit issued by a credit union for the benefit of two affiliated companies in
favor of the Railroad Commission of Texas. These letters of credit were issued
in accordance with the filing of a P-5 Organization Report as required by the
Texas Natural Resources Code in order to perform operations within the
jurisdiction of the Railroad Commission of Texas. These letters of credit are
secured by a restriction of certain funds of the Company on deposit at the
credit union issuing the letters of credit.
The long-term debt, which is secured by the commercial office building, is also
guaranteed individually by Chris G. Mazzini and Michelle H. Mazzini, related
parties.
7. COMMON STOCK
Effective January 1, 2006, the Company adopted the Financial Accounting
Standards Board's revised Statement of Financial Accounting Standards No. 123
(FAS 123R), "Share-Based Payment". FAS 123R requires compensation costs
related to share-based payments to be recognized in the income statement over
the requisite service period. The amount of the compensation cost is to be
measured based on the grant-date fair value of the instrument issued. FAS 123R
is effective for awards granted or modified after the date of adoption and for
awards granted prior to that date that have not vested. FAS 123R does not
materially change the Company's existing accounting practices or the amount of
share-based compensation recognized in earnings.
Effective August 15, 2005, the Company issued 20,000 shares of restricted
common stock to a key employee pursuant to an employment package. The shares
were valued at $1.44 per share, a 60% discount from the believed market value
for free trading shares at the time of issue of $3.60 per share. The discount
was determined based in part on the fact that the shares were restricted and
could not be sold or traded for at least one year from date of issue. The
amount was expensed as general and administrative expense. The shares of
common stock were issued out of Treasury Stock and reduced the amount of the
Company's common stock held in Treasury from 111,668 to 91,668 shares.
Effective August 15, 2006, the Company issued 10,000 shares of restricted
common stock to a key employee pursuant to an employment package. The shares
were valued at $2.10 per share, a 60% discount from the believed market value
for free trading shares at the time of issue of $5.25 per share. The discount
was determined based in part on the fact that the shares were restricted and
could not be sold or traded for at least one year from date of issue. The
amount was expensed as general and administrative expense. The shares of
common stock were issued out of Treasury Stock and reduced the amount of the
Company's common stock held in Treasury from 91,668 to 81,668 shares.
- 54 -
Subsequent to year end, and effective March 22, 2007, the Company issued 5,000
shares of restricted common stock to a key employee pursuant to an employment
package. The shares were valued at $2.12 per share, a 60% discount from the
believed market value for free trading shares at the time of issue of $5.30 per
share. The discount was determined based in part on the fact that the shares
were restricted and could not be sold or traded for at least one year from date
of issue. The amount was expensed as general and administrative expense. The
shares of common stock were issued out of Treasury Stock and reduced the amount
of the Company's common stock held in Treasury from 81,668 to 76,668 shares.
8. 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 2006, 2005 and 2004, respectively. As of
December 31, 2006 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
carry-forwards is assured, the Company will not pay to Exploration's unsecured
creditors any of the tax savings benefit. As of December 31, 2006 and 2005,
the Company owes $97,000 respectively to Exploration's unsecured creditors.
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:
Income tax differed from the amounts computed by applying an effective U.S.
federal income tax rate of 34% to pretax income in 2006, 2005 and 2004 as a
result of the following:
2006 2005 2004
----------- ---------- ----------
Computed expected tax expense $ 493,000 $ 718,000 $ 649,000
Miscellaneous timing differences
related to book and tax depletion
differences and the expensing of
intangible drilling costs 493,000 (358,000) (505,000)
----------- ---------- ----------
$ - $ 360,000 $ 144,000
=========== ========== ==========
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
- 55 -
offsetting valuation allowance. The Company's total deferred tax assets and
corresponding valuation allowance at December 31, 2006 and 2005 consisted of
the following:
December 31,
----------------------------
2006 2005
------------ ------------
Deferred tax assets
Depreciation, depletion and amortization 247,000 441,000
Other, net 9,000 9,000
------------ ------------
Total 256,000 450,000
Deferred tax liabilities
Expired leasehold (58,000) (58,000)
Intangible drilling costs (1,522,000) (1,186,000)
------------ ------------
Net deferred tax liability (1,324,000) (794,000)
============ ============
9. CASH FLOW INFORMATION
The Company does not consider any of its assets, other than cash and
certificates of deposit shown as cash on the balance sheet, to meet the
definition of a cash equivalent.
Net cash provided by operating activities includes cash payments for interest
of $94,000, $105,000 and $ -0- for the years 2006, 2005 and 2004, respectively.
Also included are cash payments for taxes of $445,000, $373,000, and $260,000
in 2006, 2005 and 2004, respectively.
Excluded from the Consolidated Statements of Cash Flows were the effects of
certain non-cash investing and financing activities, as follows:
2006 2005 2004
----------- ----------- -----------
Addition (reduction) of Oil & Gas
Properties by recognition of
Asset Retirement Obligation $ (22,000) 239,000 -
Purchase of land and commercial office
building in exchange for note payable - - 1,800,000
----------- ----------- -----------
$ (22,000)$ 239,000 $ 1,800,000
=========== =========== ===========
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. The adoption of SFAS 128 had no
effect on previously reported EPS. Diluted EPS is computed based on the
- 56 -
weighted number of shares outstanding, plus the additional common shares that
would have been issued had the options outstanding been exercised.
11. CONCENTRATIONS OF CREDIT RISK
As of December 31, 2006, the Company had approximately $2,418,000 in accounts
at one bank, including $375,000 of short term certificates of deposit and
$3,421,000 in a second bank, including $975,000 of short-term certificates of
deposit. The Company also had $1,273,000, including $960,000 of short-term
certificates of deposit invested at two other banking institutions.
Most of the Company's business activity is located in Texas. Accounts
receivable as of December 31, 2006 and 2005 are due from both individual and
institutional owners of joint interests in oil and gas wells as well as
purchasers of oil and gas. 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.
12. FINANCIAL INSTRUMENTS
The estimated fair value of the Company's financial instruments at
December 31, 2006 and 2005 follow:
-------- 2006 ------ -------- 2005 -------
Carrying Fair Carrying Fair
Amount Value Amount Value
----------- ----------- ----------- -----------
Cash $ 5,759,000 $ 5,759,000 $ 5,508,000 $ 5,508,000
Accounts receivable 1,173,000 1,173,000 1,228,000 1,228,000
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.
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
requirements may materially increase the Company's capital expenditures, reduce
earnings, and delay or prohibit certain activities.
At December 31, 2006 the Company has acquired bonds and letters of credit
issued in favor of various state regulatory agencies as mandated by state law
- 57 -
in order to comply with financial assurance regulations required to perform
oil and gas operations within the various state jurisdictions.
The Company has eleven, $5,000 single-well bonds totaling $55,000 with an
insurance company, for wells the Company operates in Alabama. The bonds are
written for a three year period. The Company also has a single-well bond in
the amount of $10,000 with a different insurance company for a well operated
in New Mexico. This bond renews annually.
The Company has nine letters of credit from a credit union issued for the
benefit of various state regulatory agencies in Texas, Oklahoma, and Louisiana,
ranging in amounts from $25,000 to $50,000 and totaling $275,000. These letters
of credit have expiration dates that range from April 30, 2007 through March 31,
2008 and are fully secured by funds on deposit with the credit union in business
money market accounts.
14. ADDITIONAL OPERATIONS AND BALANCE SHEET INFORMATION
Certain information about the Company's operations for the years ended
December 31, 2006, 2005, and 2004 follows.
Sale of Oil & Gas Properties
----------------------------
On January 30, 2004, the Company purchased a gas pipeline for a purchase price
of $200,000 plus fees, which was paid by the Exchanger out of funds held
on behalf of the Company. Both of the above purchases (the "Replacement
Property") qualify as tax-free exchanges under IRC Section 1031. On February
12, 2004, the Exchanger transferred approximately $437,500 into the Company's
bank account, representing the net proceeds after purchase of the Replacement
Properties. This amount less the basis of the Relinquished Property, of
approximately $56,000, was taxable to the Company in 2003, and accordingly a
provision for current income taxes of approximately $130,000 has been recorded
in the books of the Company. Under the full cost method of accounting, the
gain on the sale of the Relinquished Property of approximately $679,000, is not
recognized as income from current operations in the Company's income statement,
but the full amount of the sales price of $735,000 is treated as an adjustment
to capital costs. The purchase price of the $97,270 property is recorded as an
addition to Oil and Gas Properties at year-end. The acquisition cost of
$200,200 of the second Replacement Property acquired in 2004 was recorded as an
Oil and Gas Property addition in 2004.
Effective December 15, 2004, the Company sold the aforementioned gas pipeline
for a sales price of $225,000. The sale qualified as a tax-free exchange under
IRC Section 1031. The proceeds of the sale were deposited directly from the
purchaser into the account of a third party intermediary (the "Exchanger") that
specializes in deferred like-kind exchanges under IRC Section 1031. On
December 27, 2004, subsequent to the initial transaction, the Company acquired
real estate in the form of land and a commercial office building from a third
party for the sum of $2,038,000, and a portion of the purchase price was paid
out of the funds being held by the Exchanger.
- 58 -
Effective November 1, 2005, the Company sold its working interest and
operations in the Beth #1 and #2 wells in Gray County, Texas for $22,500 in
cash.
Significant Oil and Gas Purchasers
----------------------------------
Dependence on 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 short-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, 2006.
Year Ended December 31, (1)
--------------------------------
Purchaser 2006 2005 2004
----------------------------------------- -------- -------- --------
Enbridge Energy Partners 38% 39% 14%
Shell Trading (US) Company 8% 7% 6%
ETC Texas Pipeline 5% -% -%
Plains Marketing, LP. 6% 6% 6%
Devon Gas Services, L.P 4% 6% 12%
Crosstex Energy Services, Ltd 3% 5% 8%
Empire Pipeline Corp 3% -% -%
Teppco Refining 3% -% -%
Dynegy Midstream Services, LIM -% 5% 11%
Panther Pipeline North Texas, Inc. -% -% 13%
LIG Chemical Company -% -% 2%
(1) Percent of Total Oil & Gas Sales
Oil and Gas is sold to approximately 110 different purchasers (such as Devon
Gas Services, L.P., Enbridge Energy Partners (formerly Cantera Resources,
Inc.), Plains Marketing, L.P., Shell Trading (US) Company, Dynegy Midstream
Services, Empire Pipeline Corporation, and Duke Energy Field Services under
market sensitive, short-term contracts computed on a month to month basis.
Except as set forth above, there are no other customers of the Company that
individually accounted for more than 5% of the Company's oil and gas revenues
during the three years ended December 31, 2006.
The Company currently has no hedged contracts.
- 59 -
Certain revenues, costs and expenses related to the Company's oil and gas
operations are as follows:
Year Ended December 31,
-----------------------------------
2006 2005 2004
----------- ----------- -----------
Capitalized costs relating to oil
and gas producing activities:
Unproved properties $ 428,000 $ 349,000 $ 696,000
Proved properties 7,674,000 6,470,000 5,287,000
----------- ----------- -----------
Total capitalized costs 8,102,000 6,819,000 5,983,000
Accumulated amortization (4,631,000) (4,196,000) (3,467,000)
----------- ----------- -----------
Total capitalized costs, net $ 3,471,000 $ 2,623,000 $ 2,516,000
=========== =========== ===========
Year Ended December 31,
-----------------------------------
2006 2005 2004
----------- ----------- -----------
Costs incurred in oil and gas property
acquisition, exploration and
development:
Acquisition of properties $ - $ - $ -
Development costs 1,283,000 621,000 1,526,000
----------- ----------- -----------
Total costs incurred $ 1,283,000 $ 621,000 $ 1,526,000
=========== =========== ===========
Year Ended December 31,
-----------------------------------
2006 2005 2004
----------- ----------- -----------
Results of Operations from producing
activities:
Sales of oil and gas $ 5,076,000 $ 5,541,000 $ 4,039,000
----------- ----------- -----------
Production costs 2,106,000 1,747,000 1,235,000
Amortization of oil and gas
Properties 435,000 738,000 477,000
----------- ----------- -----------
Total production costs 2,541,000 2,485,000 1,712,000
----------- ----------- -----------
Total net revenue $ 2,535,000 $ 3,056,000 $ 2,327,000
=========== =========== ===========
- 60 -
Year Ended December 31,
-----------------------------------
2006 2005 2004
----------- ----------- -----------
Sales price per equivalent Mcf $ 6.16 $ 7.07 $ 5.64
=========== =========== ===========
Production costs per equivalent Mcf $ 2.55 $ 2.23 $ 1.73
=========== =========== ===========
Amortization per equivalent Mcf $ 0.53 $ 1.03 $ .67
=========== =========== ===========
Year Ended December 31,
-----------------------------------
2006 2005 2004
----------- ----------- -----------
Results of Operations from gas
gathering and equipment rental
activities:
Revenue $ 140,000 $ 167,000 $ 158,000
----------- ----------- -----------
Operating expenses 50,000 29,000 24,000
Depreciation 10,000 10,000 10,000
----------- ----------- -----------
Total costs 60,000 39,000 34,000
----------- ----------- -----------
Total net revenue $ 80,000 $ 128,000 $ 124,000
=========== =========== ===========
- 61 -
15. BUSINESS SEGMENTS
The Company's three business segments are (1) oil and gas exploration,
production and operations, (2) transportation and compression of natural gas,
and (3) commercial real estate investment. Management has chosen to organize
the Company into the three 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, 2006:
Year Ended December 31,
-----------------------------------
2006 2005 2004
----------- ----------- -----------
Revenues: (3)
Oil and gas exploration, production
and operations $ 5,230,000 $ 5,661,000 $ 4,166,000
Gas gathering, compression and
equipment rental 140,000 167,000 158,000
Real estate rental 430,000 302,000 3,000
----------- ----------- -----------
$ 5,800,000 $ 6,130,000 $ 4,327,000
=========== =========== ===========
Depreciation, depletion and
Amortization expense:
Oil and gas exploration, production
and operations $ 471,000 $ 738,000 $ 487,000
Gas gathering, compression and
equipment rental 10,000 10,000 10,000
Real estate rental 47,000 47,000 1,000
----------- ----------- -----------
$ 528,000 $ 795,000 $ 498,000
=========== =========== ===========
Income from operations:
Oil and gas exploration, production
and operations $ 2,653,000 $ 3,176,000 $ 2,445,000
Gas gathering, compression and
equipment rental 80,000 128,000 123,000
Real estate rental 53,000 (229,000) -
----------- ----------- -----------
2,786,000 3,075,000 2,568,000
Corporate and other (1) (1,302,000) (1,658,000) (1,302,000)
----------- ----------- -----------
Consolidated net income (loss) $ 1,484,000 $ 1,417,000 $ 1,266,000
=========== =========== ===========
- 62 -
Identifiable Assets net of DDA:
Oil and gas exploration, production
and operations $ 3,507,000 $ 2,682,000 $ 2,531,000
Gas gathering, compression and
equipment rental 23,000 31,000 39,000
Real estate rental 2,076,000 1,937,000 1,985,000
----------- ----------- -----------
$ 5,606,000 $ 4,650,000 $ 4,555,000
Corporate and other (2) 7,418,000 6,737,000 5,160,000
----------- ----------- -----------
Consolidated total assets $13,024,000 $11,387,000 $ 9,715,000
=========== =========== ===========
Note (1): Corporate and other includes general and administrative expenses,
other non-operating income and expense and income taxes.
Note (2): Corporate and other includes cash, accounts and notes receivable,
inventory, other property and equipment and intangible assets.
Note (3): All reported revenues are from external customers.
16. SUPPLEMENTARY INCOME STATEMENT INFORMATION
The following items were charged directly to expense:
Year Ended December 31,
-----------------------------------
2006 2005 2004
----------- ----------- -----------
Maintenance and repairs $ 31,000 $ 10,000 $ 13,000
Production taxes 290,000 303,000 236,000
Taxes, other than payroll and
income taxes 37,000 70,000 42,000
- 63 -
17. QUARTERLY DATA (UNAUDITED)
The table below reflects selected quarterly information for the years ended
December 31, 2006, 2005 and 2004.
Year Ended December 31, 2006
----------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
---------- ---------- ---------- ----------
Revenue $1,561,000 $1,520,000 $1,696,000 $1,397,000
Expense (927,000) (1,176,000) (1,233,000) (1,388,000)
---------- ---------- ---------- ----------
Operating income 634,000 344,000 463,000 9,000
Current tax provision (2,000) (133,000) (115,000) 250,000
Deferred tax provision (161,000) (91,000) (20,000) (258,000)
---------- ---------- ---------- ----------
Net income 471,000 120,000 328,000 1,000
========== ========== ========== ==========
Earnings per share
of common stock
Basic $0.06 $0.02 $0.04 $0.00
Diluted $0.06 $0.02 $0.04 $0.00
Year Ended December 31, 2005
----------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
---------- ---------- ---------- ----------
Revenue $1,306,000 $1,503,000 $1,465,000 $2,121,000
Expense (698,000) (898,000) (1,037,000) (1,652,000)
---------- ---------- ---------- ----------
Operating income 608,000 605,000 428,000 469,000
Current tax provision (109,000) (140,000) (76,000) (35,000)
Deferred tax provision (55,000) (40,000) (39,000) (199,000)
---------- ---------- ---------- ----------
Net income 444,000 425,000 313,000 235,000
========== ========== ========== ==========
Earnings per share
of common stock
Basic $0.06 $0.06 $0.04 $0.03
Diluted $0.06 $0.06 $0.04 $0.03
- 64 -
Year Ended December 31, 2004
----------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
---------- ---------- ---------- ----------
Revenue $1,004,000 $1,028,000 $1,169,000 $1,314,000
Expense (564,000) (544,000) (644,000) (910,000)
---------- ---------- ---------- ----------
Operating income 440,000 484,000 525,000 404,000
Current tax provision (13,000) (156,000) (115,000) 140,000
Deferred tax provision - - - (443,000)
---------- ---------- ---------- ----------
Net income 427,000 328,000 410,000 101,000
========== ========== ========== ==========
Earnings per share
of common stock
Basic $0.06 $0.04 $0.05 $0.01
Diluted $0.06 $0.04 $0.05 $0.01
18. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
The Company's net proved oil and natural gas reserves as of December 31, 2006
have been estimated by Netherland, Sewell & Associates, Inc. The Company's net
proved oil and natural gas reserves as of December 31, 2005 and 2004 were
estimated by Company personnel. All estimates are 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.
- 65 -
Changes in Estimated Quantities of Proved Oil and Gas Reserves (Unaudited):
Crude Oil Natural Gas
Bbls Mcf
------------ ------------
Quantities of Proved Reserves:
------------------------------
Balance December 31, 2003 365,230 9,353,560
Sales of reserves in place - -
Acquired properties - -
Extensions and discoveries 3,590 418,592
Revisions of previous estimates 73,271 4,537,079
Production (23,098) (577,099)
------------ ------------
Balance December 31, 2004 418,993 13,732,132
Sales of reserves in place (770) (6,113)
Acquired properties - -
Extensions and discoveries 6,407 188,973
Revisions of previous estimates 80,316 1,522,389
Production (21,323) (655,568)
------------ ------------
Balance December 31, 2005 483,623 14,781,813
Sales of reserves in place - -
Acquired properties - -
Extensions and discoveries 35,856 6,098,653
Revisions of previous estimates (137,414) (6,822,992)
Production (25,443) (671,512)
------------ ------------
Balance December 31, 2006 356,622 13,385,962
============ ============
Proved Developed Reserves:
--------------------------
Balance December 31, 2004 389,851 6,887,978
Balance December 31, 2005 433,455 7,109,815
Balance December 31, 2006 340,870 7,352,511
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.
Reserve estimates were prepared in accordance with standard Security and
Exchange Commission guidelines. The future net cash flow was computed using
year-end 2006 oil and gas prices. Lease operating costs, compression,
-66 -
dehydration, transportation, ad valorem taxes, severance taxes, and federal
income taxes were deducted. Costs and prices were held constant and were not
escalated over the life of the properties. No deduction has been made for
interest, or general corporate overhead. The annual discount of estimated
future cash flows is defined, for use herein, as future cash flows discounted
at 10% per year, over the expected period of realization.
Proved Developed Reserves were calculated based on Decline Curve Analysis on 91
operated wells and 275 non-operated wells. Materially insignificant non-
operated wells were excluded from the reserve estimate.
The Company emphasizes that reserve estimates are inherently imprecise.
Accordingly, the estimates are expected to change as more current information
becomes available. It is reasonably possible that, because of changes in
market conditions or the inherent imprecision of these reserve estimates, that
the estimates of future cash inflows, future gross revenues, the amount of oil
and gas reserves, the remaining estimated lives of the oil and gas properties,
or any combination of the above may be increased or reduced in the near term.
If reduced, the carrying amount of capitalized oil and gas properties may be
reduced materially in the near term.
Standardized measure of discounted future net cash flows related to proved
reserves:
Year Ended December 31,
--------------------------------------
2006 2005 2004
------------ ------------ ------------
Future production revenue $ 81,294,000 $130,178,000 $ 87,568,000
Future development costs (4,778,000) (13,831,000) (8,300,000)
Future production costs (21,323,000) (25,144,000) (22,668,000)
------------ ------------ ------------
Future net cash flow before
Federal income tax 55,193,000 91,203,000 56,600,000
Future income taxes (15,454,000) (22,941,000) (15,175,000)
------------ ------------ ------------
Future net cash flows 39,739,000 68,262,000 41,425,000
Effect of 10% annual discounting (14,074,000) (40,401,000) (24,534,000)
------------ ------------ ------------
Standardized measure of
Discounted net cash flows $ 25,655,000 $ 27,861,000 $ 16,891,000
============ ============ ============
- 67 -
Changes in the standardized measure of discounted future net cash flows:
Year Ended December 31,
--------------------------------------
2006 2005 2004
------------ ------------ ------------
Beginning of the year $ 27,861,000 $ 16,891,000 $ 11,862,000
Oil and gas sales, net of
production costs (2,970,000) (5,541,000) (2,644,000)
Purchases of reserves in place - - -
Sales of reserves in place - (31,000) -
Net change in prices, net of
production costs (8,513,000) 13,063,000 7,809,000
Extensions, discoveries and additions 9,251,000) - -
Changes in production rates,
timing and other - (7,571,000) (3,101,000)
Revisions of quantity estimate (1,592,000 11,722,000 7,662,000
Effect of income tax (1,158,000) (2,361,000) (5,883,000)
Accretion of discount 2,786,000 1,689,000 1,186,000
------------ ------------ ------------
End of year $ 25,655,000 $ 27,861,000 $ 16,891,000
============ ============ ============
- 68 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2006, 2005, AND 2004
SCHEDULE II
Beginning Costs & Ending
Description Balance Expenses Deductions Balance
----------------------------- ----------- ----------- ----------- -----------
Allowance for
doubtful Accounts
December 31, 2004 $ 30,000 $ - $ - $ 30,000
========== ========== ========== ==========
December 31, 2005 $ 30,000 $ - $ 16,000 $ 14,000
========== ========== ========== ==========
December 31, 2006 $ 14,000 $ - $ - $ 14,000
========== ========== ========== ==========
- 69 -
SCHEDULE III
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
REAL ESTATE AND ACCUMULATED DEPRECIATION
Initial Cost to Corporation Total Cost
----------------------------------------------------------------- Subsequent
Description Encumbrances Land Buildings ToAcquist'n
------------------------- ------------- ----------- ----------- -----------
Two story multi-tenant
garden office building with
sub-grade parking garage
located in Dallas, Texas (b) $ 688,000 $1,298,000 $210,000
Gross Amounts at Which Carried at Close of Year
Life on which
Accumulated Depreciation Date
Land Buildings Total Depreciation Calculated Acquired
---------- ------------ ----------- ------------- ------------ -----------
$ 688,000 $ 1,508,000 $ 2,196,000 $ 120,000 (a) 12/27/2004
Notes to Schedule III
(a) See Footnote 2 to the Financial Statements outlining depreciation methods
and lives.
(b) See description of notes payable in Footnote 5 to the Financial Statements
outlining the terms and provisions of the acquisition loan for the building.
(c) The reconciliation for investments in real estate and accumulated
depreciation for the years ended December 31, 2006 is as follows:
Investments in Accumulated
Real Estate Depreciation
------------ ------------
Balance, December 31, 2003
Acquisitions 1,986,000
Depreciation expense - 1,000
------------ ------------
Balance, December 31, 2004 $ 1,986,000 $ 1,000
Acquisitions - -
Depreciation expense - 48,000
------------ ------------
Balance, December 31, 2005 $ 1,986,000 $ 49,000
Acquisitions 210,000 -
Depreciation expense - 71,000
------------ ------------
Balance, December 31, 2006 $ 2,196,000 $ 120,000
============ ============
- 70 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
Index to Exhibits
The following documents are filed as exhibits (or are incorporated by reference
as indicated) into this Report:
Exhibit
Designation Description
3.1 Articles of Incorporation of Spindletop Oil & Gas Co. (previously
filed with our General Form for Registration of Securities on
Form 10, filed with the Commission on August 14, 1990)
3.2 Bylaws of Spindletop Oil & Gas Co. (previously filed with our
General Form for Registration of Securities on Form 10, filed
with the Commission on August 14, 1990)
14 Code of Ethics for Senior Financial Officers (previously filed
with our Annual Report Form 10-K for the fiscal year ended
December 31, 2005)
21 Subsidiaries of the Registrant
31.1 Rule 13a-14(a) Certification of Chief Executive Officer
31.2 Rule 13a-14(a) Certification of Chief Executive Officer
32 Officers' Section 1350 Certifications
- 71 -
EXHIBIT 21
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
Subsidiaries of 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.
- 72 -
Exhibit 31.1
CERTIFICATIONS
I, Chris G. Mazzini, certify that:
1. I have reviewed this report on Form 10-K of Spindletop Oil & Gas Co.;
2. Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material respects
the financial condition, results of operations and cash flows of the registrant
as of, and for, the periods presented in this report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13-15(e) and 15d-15e) and have internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)
for the registrant and have:
(a) designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this report is being prepared;
(b) designed such internal control over financial reporting, or caused
such internal control over financial reporting to be designed under
our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted
accounting principles; and
(c) evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this report our conclusions about the
effectiveness of the controls and procedures as of the end of the
period covered by this report based on such evaluation; and
(d) disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's
most recent fiscal quarter that has materially affected, or is
reasonably likely to materially affect, the registrant's internal
control over financial reporting; and
- 73 -
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation of internal control over financial reporting, to
the registrant's auditors and the audit committee of registrant's board of
directors (or persons performing the equivalent functions):
(a) all significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls.
Dated April 16, 2007
/s/ Chris G. Mazzini
CHRIS G. MAZZINI
Chief Executive Officer
- 74 -
Exhibit 31.2
CERTIFICATIONS
I, Robert E. Corbin, certify that:
1. I have reviewed this report on Form 10-K of Spindletop Oil & Gas Co.;
2. Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were
made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material respects
the financial condition, results of operations and cash flows of the registrant
as of, and for, the periods presented in this report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13-15(e) and 15d-15e) and have internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)
for the registrant and have:
(a) designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known
to us by others within those entities, particularly during the period
in which this report is being prepared;
(b) designed such internal control over financial reporting, or caused
such internal control over financial reporting to be designed under
our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted
accounting principles; and
(c) evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this report our conclusions about
the effectiveness of the controls and procedures as of the end of the
period covered by this report based on such evaluation; and
(d) disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's most
recent fiscal quarter that has materially affected, or is reasonably likely
to materially affect, the registrant's internal control over financial
reporting; and
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5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation of internal control over financial reporting, to
the registrant's auditors and the audit committee of registrant's board of
directors (or persons performing the equivalent functions):
(a) all significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; and
(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls.
Dated: April 16, 2007
/s/ Robert E. Corbin
ROBERT E. CORBIN
Principal Financial and
Accounting Officer
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Exhibit 32
Officers' Section 1350 Certifications
The undersigned officer of Spindletop Oil & Gas Co., a Texas corporation (the
"Company"), hereby certifies that (i) the Company's Annual Report on Form 10-K
for the year ended December 31, 2005 fully complies with the requirements of
Section 13(a) of the Securities Exchange Act of 1934, and (ii) the information
contained in the Company's Annual Report on Form 10-K for the year ended
December 31, 2005 fairly presents, in all material respects, the financial
condition and results of operations of the Company, at and for the periods
indicated.
Dated: April 16, 2007
/s/ Chris G. Mazzini
CHRIS G. MAZZINI
Chief Executive Officer
/s/ Robert E. Corbin
ROBERT E. CORBIN
Principal Financial and
Accounting Officer
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