UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2008
or
[ ] TRANSITION REPORT PURSUANT OT SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File No. 000-18774
SPINDLETOP 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 No.)
12850 Spurling Rd., Suite 200, Dallas, TX 75230
(Address of principal executive offices) (Zip Code)
(972) 644-2581
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of each exchange on which registered
None N/A
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 [ X ] No [ ]
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
Company 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 the
Form 10-K or any amendment to this Form 10-K. [ X ]
Indicate by check mark whether the registrant is a large accelerated filer,
an accelerated filer or a non-accelerated filer or a smaller reporting company
See definitions of "large accelerated filer", "accelerated filer", and "smaller
reporting company" in Rule 12b-2 of the Exchange Act (Check one):
Large accelerated filer [ ] Accelerated filer [ ]
Non-accelerated filer [ ] Smaller reporting company [ 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 ]
State the aggregate market value of the voting and non-voting common equity
held by non-affiliates computed by reference to the price at which the common
equity was last sold, or the average bid and asked price of such common equity,
as of the last business day of the registrant's most recently completed second
fiscal quarter.
$15,050,288 based upon a total of 1,710,260 shares held as of June 30, 2008 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, that such calculation, if
made as of a date within 60 days of this filing, would yield a different value.
APPLICABLE ONLY TO REGISTRANTS INVOLVED IN BANKRUPTCY
PROCEEDINGS DURING THE PRECEEDING FIVE YEARS:
Indicate by check mark whether the registrant has filed all documents and
reports required to be filed by Sections 12, 13 or 15(d) of the Securities
Exchange Act of 1934 subsequent to the distribution of securities under a plan
confirmed by a court. Yes [ ] No [ ]
(APPLICABLE ONLY TO CORPORATE REGISTRANTS)
Indicate the number of shares outstanding of each of the issuer's classes of
common, as of the latest practicable date.
Common Stock, $0.01 par value 7,610,803
(Class) (Outstanding at April 15, 2009)
DOCUMENTS INCORPORATED BY REFERENCE
None
- 2 -
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 20 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 through the fourth quarter of 2008, we returned our focus to a
strategy of development drilling. In the current economic climate, we are
taking a slower, more conservative approach to development of our leasehold
acreage. We are looking at growth through acquisitions and limited drilling.
With current lower product prices and high costs to produce, we believe that it
makes sense to carefully evaluate all our options and make sure that each
transaction can be supported in today's lower price environment.
Our strategic focus 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.
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.
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
Fort Worth Basin. The Company is developing its Fort Worth Basin producing
properties into the Barnett Shale formation. We want to capitalize on our
strengths which include an extensive 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 as needed to service
the Company's new wells. 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.
- 4 -
Significant Project Areas
-------------------------
The Company owns various interests in wells located in 16 states and the
Company's operations are currently located in six of those states which include
Alabama, Arkansas, Louisiana, Oklahoma, New Mexico and Texas.
The Company holds approximately 90,873 gross acres under lease in six states.
The majority of the leases are held by production. A breakout of the Company's
leasehold acreage by geographic area is as follows:
Operated Non-Operated
Properties Properties Total Percent
Gross Net Gross Net Gross Net of Total
Acres Acres Acres Acres Acres Acres Gross Net
------ ------ ------ ----- ------ ------ ----- ----
North Texas Including
the Fort Worth Basin 10,284 9,497 1,073 105 11,357 9,602 12.5 40.9
Arkansas 2,936 2,587 5,034 580 7,970 3,167 8.8 13.5
East Texas 2,613 2,297 5,342 446 7,955 2,743 8.8 11.7
Gulf Coast Texas 2,741 1,810 2,812 59 5,553 1,869 6.1 8.0
Alabama 1,480 789 612 56 2,092 845 2.3 3.6
West Texas 748 578 1,379 78 2,127 656 2.3 2.8
New Mexico 739 342 360 3 1,099 345 1.2 1.5
Louisiana 723 506 3,944 189 4,667 695 5.1 3.0
Texas Panhandle 640 640 1,200 122 1,840 762 2.0 3.2
Oklahoma 237 165 33,095 1,240 33,332 1,405 36.7 5.9
Utah - - 2,729 487 2,729 487 3.0 2.1
Wyoming - - 3,120 302 3,120 302 3.4 1.3
Kansas - - 800 224 800 224 0.9 1.0
North Dakota - - 800 122 800 122 0.9 0.5
Montana - - 2,450 109 2,450 109 2.7 0.5
Colorado - - 640 64 640 64 0.7 0.3
Mississippi - - 1,210 47 1,210 47 1.3 0.2
California - - 892 6 892 6 1.0 0.0
Michigan - - 240 6 240 6 0.3 0.0
Total 23,141 19,211 67,732 4,245 90,873 23,456 100.0 100.0
The majority of the Company's net reserves (66.7%) are located in Texas.
- 5 -
A breakout of the Company's most significant reserves by geographic area is as
follows:
North Texas Including
the Fort Worth Basin 1,821,058 BOE 71.27 %
West Texas 220,693 BOE 8.64 %
East Texas 124,082 BOE 4.85 %
Arkansas 91,076 BOE 3.57 %
Oklahoma 84,343 BOE 3.30 %
Louisiana 55,655 BOE 2.18 %
Gulf Coast Texas 49,760 BOE 1.95 %
Alabama 46,373 BOE 1.81 %
New Mexico 37,662 BOE 1.47 %
Panhandle Texas 15,273 BOE 0.60 %
North Dakota 6,076 BOE 0.24 %
Wyoming 2,985 BOE 0.12 %
Total 2,555,036 BOE 100.00 %
Fort Worth Basin/Bend Arch Province
The Fort Worth Basin has been the focal point of the Company since its
inception. Our technical personnel have an average of 20 years of exploration,
drilling and production experience in the Basin. We also have an extensive
collection of geologic and engineering data.
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, an estimated 26.7 TCF of undiscovered
natural gas, 98.5 MMBO of undiscovered oil, and 1.1 BBNGL of undiscovered
natural gas liquids remains within the 54,000 square mile Bend Arch-Fort Worth
Basin Province. More than 98 percent, or approximately 26.2 TCF of the
undiscovered natural gas is contained in the organic-rich Mississippian Barnett
Shale.
The Company has 11,357 gross acres under lease in the Bend Arch and Fort Worth
Basin the majority of it held by production from shallower producing zones. We
are planning to drill new wells into the Barnett Shale Formation on some of
these leases. We are also actively seeking and acquiring new leases in the
Barnett Shale trend.
- 6 -
Joint Drilling Development of North Texas Barnett Shale Leasehold
The Company along with Giant Energy Corp. ("Giant") entered into a Farmout and
Exploration Agreement dated August 22, 2006 (the "Agreement"), with Williams
Production-Gulf Coast Company, L.P. ("Williams"). The Agreement was
subsequently amended to clarify a number of provisions in the original Farmout
and Exploration Agreement. After drilling twelve of the prescribed number of
horizontal Barnett Shale wells, ten on the Spindletop leasehold and two on the
Giant leasehold, Williams gave notice of its election to terminate the
Agreement in accordance with provisions contained in the Agreement, and
subsequent amendments, effective September 19, 2008. No early termination
penalties were incurred by Williams, or any of the parties to the Agreement,
however, by opting not to drill all of the prescribed number of carried wells,
the earned assignments to Williams shall be limited to 50% gross working
interest in said wells along with a prescribed quantity of acreage surrounding
each horizontal drain hole. As a consequence of the termination of the
Agreement, Spindletop is now free to pursue other development opportunities on
the leasehold acreage that Spindletop retained and that was not earned by
Williams under the Agreement.
During the fourth quarter of 2007, two other wells were drilled, the
Buxton G.U. #1H well, located on our Weatherford, W block and the Fuller
G.U.#1H well located on our Weatherford, SW block. Both wells are located in
the southwest quarter of Parker County, Texas. The Buxton #1H well was drilled
to a total measured depth of 8,850 ft. and began production of natural gas on
June 3, 2008 at a rate of 767 MCFGPD and 813 BWPD. The well continues to
produce large amounts of water while gas production has declined. The Company
is evaluating whether it is a viable to continue to produce this well at
current product pricing. The Fuller G.U. #1H was drilled to a measured depth
of 9,076 ft. and completed in the Barnett Shale. The well was fractured and it
is believed the fracture stimulation communicated with the underlying
Ellenburger Formation based on the high volume of high chloride water flowed
back and tested. The well is currently shut in. The Company holds a 50%
working interest in both of these wells.
In the first quarter of 2008, the McKeon G.U. #1H well, located on our Peaster,
SW block in the northwest quarter of Parker County, Texas, was spud and was
drilled to a measured depth of 9,329 ft. and cased. Production of natural gas
began on June 13, 2008 at a rate of 1,951 MCFGPD and 1,760 BWPD. The well was
fractured and the fracture stimulation also appears to have communicated with
the underlying the Ellenberger Formation based on the high water production.
An additional workover was attempted to reduce the water production but was not
successful. The well is currently shut-in.
Company's Development of North Texas Barnett Shale Leasehold outside of the
Joint Drilling Development Project
During the third quarter of 2008, the Olex U.S. #8 well, located on our
Krum SW Block in Denton Co., Texas was drilled to a depth of 8,827 ft. and
cased. The well was fractured and tested subsequent to year end during the
first quarter of 2009. It began production on March 17, 2009. The well is
currently producing at an average rate of 1,056 MCFGPD and 40 BOPD.
The Company owns a 52.5% working interest in this well.
- 7 -
Also, during the fourth quarter of 2008, the Poston #1 well, located on our
Godley North Block in Johnson Co., Texas was drilled to a depth of 6,754 ft.
and cased. Completion of this well is scheduled in the second quarter of 2009.
The company owns a 91% working interest in this well.
In addition to the Company's Barnett Shale development drilling activities,
the Company has worked on or participated in the following projects:
West Texas
In the second quarter of 2008, the Company initiated a recompletion on one of
its existing wells in Ward Co., Texas on its Pyote Block. The Company
attempted to deepen its University "K" #1 well to a depth of 14,900 ft. The
Company worked on this well for a period of four months during the second and
third quarters of 2008. The primary objective could not be reached due to the
Company's inability to remove or drill through unexpected oilfield tools that
were encountered deep in the wellbore. The Company recompleted the well in
some shallow secondary objectives. The well was placed back in production and
is producing approximately 5 BOPD and 10 MCFGPD. The Company owns a 100%
working interest in this well.
The Company participated in the drilling of a well in Midland County, Texas.
The Dixon #2TM well was spud on 12/30/2007. The well was drilled to a depth
of 8,560 ft. The well was completed in the Sprayberry Formation and was
placed into production on 5/1/2008 at an initial rate of 32 BOPD and 28 MCFGPD.
The Company owns a 8.03542 % working interest in this well.
The Company also participated in two wells in Andrews County, Texas. The Miles
#5 well was spud on 9/1/2008. The well was drilled to the San Andres Formation
at a depth of 4,774 ft. The well was placed into production on 9/25/2008 at
a rate of 44 BOPD and 18 MCFGPD. The Miles #7 well was spud on 10/22/2008 and
drilled to a total depth of 4,855 ft. in the San Andres formation. Initial
production on 11/25/2008 was 59 BOPD and 63 MCFGPD. The Company owns a 4.6875%
working interest in both of these wells.
Oklahoma
The Company participated in the drilling of a well in Roger Mills County,
Oklahoma. The Chamberlain # 6-2 well was spud on 3/8/2008 and drilled to a
total depth of 12,726 ft. with first production on 4/24/2008 from the Redfork
Formation. The initial rate was 526 MCFGPD and 0 BOPD. The Company owns a
6.2898% working interest in this well.
The Company participated in the drilling of two wells in Beckham County,
Oklahoma during 2008. The Elk City Unit #2-12-17 well was spud on 7/17/2008
and drilled to a depth of 10,125' to the Hoxbar Formation. The well was placed
in production on 10/27/2008 with an initial rate of 30 BOPD and 999 MCFGPD.
The Elk City Unit #1-9-19 well was spud on 7/29/2008 and drilled to a depth of
9,975 ft to the Hoxbar Formation. This well has not yet been completed. The
Company owns a 0.1419 % working interest in both of these wells.
The Company participated in the drilling of two wells in Canadian County,
Oklahoma. The Betty 1-30 well was drilled to a total depth of 11,471 ft. to
the Simpson Formation with first production on 2/20/2008. The initial
- 8 -
potential was 783 MCFGPD. The Company owns a 2.22186% working interest in this
well. The Crowley #1-30 well was spud on 8/23/2008 and drilled to a total
depth of 9,684 ft. with first production on 10/16/2008 from the Hunton
formation. The initial rate was 12 BOPD and 122 MCFGPD. The Company owns a
13.26532% working interest in this well.
New Mexico
The Company participated in the drilling of a well in Eddy County, New Mexico.
The Firefox Federal #1 well was spud on 11/3/2008 and completed 2/18/2009. The
well was drilled to a total depth of 12,350 ft. in the Morrow formation. First
production was on 3/11/2009 with an initial production of 1,013 MCFGPD and
27 BOPD. The Company owns a 0.62295% working interest in this well.
Montana
The Company participated in the drilling of a well in Phillips County, Montana.
The Loring Unit #1279-2 well was spud on 8/11/2008 and completed on 9/4/2008.
The well was drilled to a depth of 1,965 ft. to the Phillips Formation.
Initial potential was 45 MCFGPD. The well averaged 45 MCFGPD during the first
month of production. The Company owns a 12.50% working interest in this well.
Oil and Natural Gas Reserves
----------------------------
The net crude oil and gas reserves of the Company as of December 31, 2008 were
261,712 barrels of oil and condensate and 13.76 BCFG (billion cubic feet) of
natural gas. Based on SEC guidelines, the reserves were classified as follows:
Proved Developed Producing 224,901 BO and 8.280 BCFG
Proved Developed Non-Producing 28,047 BO and 2.603 BCFG
Proved Undeveloped 8,764 BO and 2.877 BCFG
Total Proved Reserves 261,712 BO and 13.760 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
which are slated for drilling in the next 5 years) underlying the Company's
properties. Shut-in uneconomic wells and insignificant non-operated interests
were excluded.
- 9 -
On a barrel of oil equivalent basis (6 MCF/BOE), the net reserves are
Natural Gas Reserves 2,293,325 BOE 90%
Oil Reserves 261,712 BOE 10%
Total Reserves 2,555,037 BOE 100%
Proved Developed Producing 1,604,908 BOE 63%
Proved Developed Non-Producing 461,813 BOE 18%
Proved Undeveloped 488,316 BOE 19%
Total Proved Reserves 2,555,037 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 2,389,437 BOE 94%
Non Operated Wells 165,600 BOE 6%
Total 2,555,037 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
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 1,520 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.
- 10 -
The Company owns land and a two story commercial office building in Dallas,
Texas, which it 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 $25.00 per net mineral acre but can exceed this range.
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.
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, 2008:
Year Ended December 31, (1)
--------------------------------
Purchaser 2008 2007 2006
----------------------------------------- -------- -------- --------
Crosstex Energy Services, LP 42% 26% 3%
Enbridge Energy Partners
(formerly Enbridge North Texas 26% 36% 38%
Targa Midstream Service, LIM
(formerly Dynegy Midstream Services, LIM 6% 3% -%
Shell Trading (US) Company 5% 6% 8%
Eastex Crude Company 3% 2% -%
Devon Gas Services, L.P 2% 2% 4%
Teppco Crude Oil, LP 2% 5% 3%
Genesis 1% -% -%
Gateway Gathering & Marketing 1% -% -%
ETC Texas Pipeline 1% 2% 5%
Navajo Refining Co. 1% 2% -%
Plains Marketing, L.P. -% 1% 6%
(1) Percent of Total Oil & Gas Sales
-11 -
Oil and gas is sold to approximately 96 different purchasers 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, 2008.
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.
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 employs or contracts for the services of a total of approximately
60 people. Twenty-seven are full-time employees or contractors. The remainder
are part-time independent 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
- 12 -
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-man 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
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.
On June 21, 2007, the acting United States attorney for the Eastern District
of Texas filed an Information against Spindletop Drilling Company, a subsidiary
of the registrant in a case styled The United States of America v. Spindletop
Drilling Company, Case No. 5:07CR16 filed in the United States District Court
for the Eastern District of Texas, Texarkana Division. The Information alleged
a violation of Title 16, USC Sec 703 (unlawful taking of migratory birds),
charged Spindletop Drilling Company with a Class B misdemeanor petty offense
advising that on or about September 6, 2006 in Titus County, Texas allegedly
took migratory birds including approximately twelve (12) Northern Mockingbirds
(Mimus Polyglottos) and one (1) Mourning Dove (Zenaida Macroura), all in
violation of 16 USC Sec 703 and 707(a). Spindletop Drilling Company owns and
operates an oil pit located on the "Pewitt D" lease located in Titus County,
Texas. Although Spindletop Drilling Company had netting in place, several
small birds were found in the pit in early September, 2006.
Although the incident was inadvertent, on June 26, 2007, in order to resolve
the matter, Spindletop Drilling Company entered into a plea agreement agreeing
to one count of the Information which charged a violation of 16 USC Sec 703 and
stipulated and agreed that two years probation, $10,000 in restitution payable
- 13 -
to the National Fish and Wildlife Foundation, no fine, and a $25 special
assessment would best advance the objectives under the law. The court gave
final approval of this agreement on October 4, 2007.
During the first quarter of 2007, Spindletop Drilling Company corrected the
netting on the property and implemented other safeguards to further protect
the migratory birds and property in question.
Glossary of Oil and Gas Terms
The following are abbreviations and definitions of terms commonly used in the
oil and gas industry that are used in this Report. The terms defined herein
may be found in this report in both upper and lower case or a combination of
both.
"BBL" means a barrel of 42 U.S. gallons
"BBNGL" means billion barrels of natural gas liquids.
"BCF" or "BCFG" means billion cubic feet.
"BOE" means barrels of oil equivalent; converting volumes of natural gas to oil
equivalent volumes using a ratio of six Mcf of natural gas to one Bbl of oil.
"BOPD" means barrels of oil per day.
"BTU" means British Thermal Units. British Thermal Unit means the quantity of
heat required to raise the temperature of one pound of water by one degree
Fahrenheit.
"Completion" means the installation of permanent equipment for the production
of oil or gas.
"Development Well" means a well drilled within the proved area of an oil or gas
reservoir to the depth of a strata graphic horizon known to be productive.
"Dry Hole" or "Dry Well" means a well found to be incapable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
"Exploratory Well" means a well drilled to find and produce oil or gas reserves
not classified as proved, to find a new production reservoir in a field
previously found to be productive of oil or gas in another reservoir or to
extend a known reservoir.
"Farm-Out" means an agreement pursuant to which the owner of a working interest
in an oil and gas lease assigns the working interest or a portion thereof to
another party who desires to drill on the leased acreage. Generally, the
assignee is required to drill one or more wells in order to earn its interest
in the acreage. The assignor usually retains a royalty or reversionary
interest in the lease. The interest received by an assignee is a "farm-in" and
the assignor issues a "farm-out."
"Farm-In" see "Farm-Out" above.
- 4 -
"Gas" means natural gas.
"Gross" when used with respect to acres or wells, refers to the total acres or
wells in which we have a working interest.
"Infill Drilling" means drilling of an additional well or wells provided for by
an existing spacing order to more adequately drain a reservoir.
"MCF" or "MCFG" means thousand cubic feet.
"MCFE" means MCF of natural gas equivalent; converting volumes of oil to
natural gas equivalent volumes using a ratio of one BBL of oil to six MCF
of natural gas.
"MCFGPD" means thousand cubic feet of gas per day.
"MMBO" means million barrels of oil.
"MMBTU" means ones million BTUs.
"Net" when used with respect to acres or wells, refers to gross acres or wells
multiplied, in each case, by the percentage working interest owned by the
Company.
"Net Production" means production that is owned by the Company less royalties
and production due others.
"Non-Operated" or "Outside Operated" means wells that are operated by a third
party.
"Operator" means the individual or company responsible for the exploration,
development, production and management of an oil or gas well or lease.
"Overriding Royalty" means a royalty interest which is usually reserved by an
owner of the leasehold in connection with a transfer to a subsequent owner.
"Present Value" ("PV") when used with respect to oil and gas reserves, means
the estimated future gross revenues to be generated from the production of
proved reserves calculated in accordance with the guidelines of the SEC, net
of estimated production and future development costs, using prices and costs
as of the date of estimation without future escalation (except to the extent a
contract specifically provides otherwise), without giving effect to
non-property related expenses such as general and administrative expenses,
debt service, future income tax expense and depreciation, depletion and
amortization, and discounted using an annual discount rate of 10%.
"Productive Wells" or "Producing Wells" consist of producing wells and wells
capable of production, including wells waiting on pipeline connections.
"Proved Developed Reserves" means reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
- 15 -
forces and mechanisms of primary recovery will be included as "proved developed
reserves" only after testing by a pilot project or after the operation of an
installed program has confirmed through production response that increased
recovery will be achieved.
"Proved Reserves" means the estimated quantities of crude oil and natural gas
which upon analysis of geological and engineering data appear with reasonable
certainty to be recoverable in future years from known reservoirs under
existing economic and operating conditions, i.e., prices and costs as of the
date the estimate is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on escalations based
upon future conditions.
(i) Reservoirs are considered proved if either actual production or
conclusive formation tests support economic producibility. The area of
a reservoir considered proved includes (A) that portion delineated by
drilling and defined by gas-oil and/or oil-water contacts, if any; and
(B) the immediately adjoining portions not yet drilled, but which can
be reasonably judged as economically productive on the basis of
available geological and engineering data. In the absence of
information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application
of improved recovery techniques (such as fluid injection) are included
in the "proved" classification when successful testing by a pilot
project, or the operation of an installed program in the reservoir,
provides support for the engineering analysis on which the project or
program was based.
(iii) Estimates of proved reserves do not include the following: (A)
oil that may become available from known reservoirs but is classified
separately as "indicated additional reserves"; (B) crude oil and
natural gas, the recovery of which is subject to reasonable doubt
because of uncertainty as to geology, reservoir characteristics or
economic factors; (C) crude oil and natural gas that may occur in
undrilled prospects; and (D) crude oil and natural gas that may be
recovered from oil shales, coal, gilsonite and other such resources.
"Proved Undeveloped Reserves" means reserves that are recovered from new wells
on undrilled acreage, or from existing wells where a relatively major
expenditure is required for completion. Reserves on undrilled acreage shall be
limited to those drilling units offsetting productive units that are reasonably
certain of production when drilled. Proved reserves for other undrilled units
can be claimed only where it can be demonstrated with certainty that there is
continuity of production from the existing productive formation. Under no
circumstances should estimates for proved undeveloped reserves be attributable
to any acreage for which an application of fluid injection or other improved
recovery technique is contemplated, unless such techniques have been proved
effective by actual tests in the area and in the same reservoir.
- 16 -
"Recompletion" means the completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
"Reserves" means proved reserves.
"Reservoir" means a porous and permeable underground formation containing a
natural accumulation of producible oil and/or gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.
"Royalty" means an interest in an oil and gas lease that gives the owner of the
interest the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not
require the owner to pay any portion of the costs of drilling or operating the
wells on the leased acreage. Royalties may be either landowner's royalties,
which are reserved by the owner of the leased acreage at the time the lease is
granted, or overriding royalties, which are usually reserved by an owner of the
leasehold in connection with a transfer to a subsequent owner.
"TCF" means trillion cubic feet.
"2-D Seismic" means an advanced technology method by which a cross-section of
the earth's subsurface is created through the interpretation of reflecting
seismic data collected along a single source profile.
"3-D Seismic" means an advanced technology method by which a three dimensional
image of the earth's subsurface is created through the interpretation of
reflection seismic data collected over a surface grid. 3-D seismic surveys
allow for a more detailed understanding of the subsurface than do conventional
surveys and contribute significantly to field appraisal, development and
production.
"Working Interest" means an interest in an oil and gas lease that gives the
owner of the interest the right to drill for and produce oil and gas on the
leased acreage and requires the owner to pay a share of the costs of drilling
and production operations. The share of production to which a working interest
owner is entitled will always be smaller than the share of costs that the
working interest owner is required to bear, with the balance of the production
accruing to the owners of royalties.
"Workover" means operations on a producing well to restore or increase
production.
- 17 -
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.
The current global economic and financial crisis could lead to an extended
national or global economic recession. A slowdown in economic activity caused
by a recession would likely reduce national and worldwide demand for oil and
natural gas and result in lower commodity prices for long periods of time.
Prices for oil and natural gas have decreased significantly from highs in 2008.
In the last six months, oil prices have decreased by two thirds off their
highest prices and natural gas prices have decreased in half or more during
this time period. Costs of exploration, development and production have not
yet adjusted to current economic conditions or in proportion to the significant
reduction in product prices. Prolonged, substantial decreases in oil and
natural gas prices would likely have a material adverse effect on Spindletop's
business, financial condition and results of operations, could further limit
the Company's access to liquidity and credit and could hinder its ability to
satisfy its capital requirements.
Capital and credit markets have experienced unprecedented volatility and
disruption during the last half of 2008 and continue to be unpredictable. Given
the current levels of market volatility and disruption, the availability of
funds from those markets has diminished substantially. Further, arising from
concerns about the stability of financial markets generally and the solvency of
borrowers specifically, the cost of accessing the credit markets has increased
as many lenders have raised interest rates, enacted tighter lending standards
or altogether ceased to provide funding to borrowers.
Due to these capital and credit market conditions, Spindletop cannot be certain
that funding will be available to the Company in amounts or on terms acceptable
to the Company. The Company is evaluating whether current cash balances and
cash flow from operations alone would be sufficient to provide working capital
to fully fund the Company's operations. Accordingly, the Company is evaluating
alternatives, such as joint ventures with third parties, or sales of interest
in one or more of its properties. Such transactions if undertaken, could result
in a reduction in the Company's operating interests or require the Company to
relinquish the right to operate the property. There can be no assurance that
any such transactions can be completed or that such transactions will satisfy
the Company's operating capital requirements. If the Company is not successful
in obtaining sufficient funding or completing an alternative transaction on a
timely basis on terms acceptable to the Company, Spindletop would be required
- 18 -
to curtail its expenditures or restructure its operations, and the Company
would be unable to continue its exploration, drilling, and recompletion
program, any of which would have a material adverse effect on Spindletop's
business, financial condition and results of operations.
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.
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
- 19 -
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 $4,475,000 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.
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
- 20 -
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 risks associated with the current U.S. Government
Administration's proposed budget features.
The Obama administration has recently set forth budget proposals which if
passed, would significantly curtail our ability to attract investors and raise
capital. Proposed changes in the Federal income tax laws which would eliminate
or reduce the percentage depletion deduction and the deduction for intangible
drilling and development costs for small independent producers, will
significantly reduce the investment capital available to those in the industry
as well as our Company. Lengthening the time to expense seismic costs will
also have an adverse effect on our ability to explore and find new 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.
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 to some extent 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.
- 21 -
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 77%
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.
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
- 22 -
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.
We are subject to certain title risks.
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, 2008, 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
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, 2008, we had working capital of $7,929,000. 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 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
- 23 -
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
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, 2008, approximately 82%
of our gas production is currently sold to five gas purchasing firms on a
month-to-month basis at prevailing spot market prices. Oil prices remained
subject to unpredictable political and economic forces during 2008, 2007 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.
- 24 -
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 should equal to 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
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
- 25 -
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.
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
egulations 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.
- 26 -
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
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
- 27 -
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
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,
-----------------------------------
2008 2007 2006
----------- ----------- -----------
Gas and Oil Properties, net (1):
Proved developed gas reserves-Mcf (2)
Proved developed producing 8,280,000 10,206,000 5,320,000
Proved developed non-producing 2,603,000 742,000 2,033,000
Proved undeveloped gas reserves-Mcf (3) 2,877,000 3,419,000 6,033,000
----------- ----------- -----------
Total proved gas reserves-Mcf 13,760,000 14,367,000 13,386,000
=========== =========== ===========
- 28 -
Proved Developed Crude Oil and
Condensate reserves-Bbls (2)
Proved developed producing 225,000 292,000 291,000
Proved developed non-producing 28,000 42,000 50,000
Proved Undeveloped crude oil and
Condensate reserves-Bbls (3) 9,000 11,000 16,000
----------- ----------- -----------
Total proved crude oil and condensate
Reserves-Bbls 261,000 345,000 357,000
=========== =========== ===========
(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 2006 through 2008.
Productive Wells
----------------
The following table sets forth our domestic productive wells and includes both
operated wells and wells operated by third parties at December 31, 2008.
Gas Wells Oil Wells Total Wells
---------------------- --------------------- ---------------------
Gross Net Gross Net Gross Net
---------- ---------- ---------- ---------- ---------- ----------
269 86.08 102 53.08 371 139.16
Acreage
The following table sets forth our undeveloped and developed gross and net
leasehold acreage for our operated and non-operated wells at December 31, 2008.
Undeveloped acreage includes leased acres on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of oil and gas, regardless of whether or not such acreage contains
proved reserves. Undeveloped acreage should not be confused with undrilled
acreage Held by Production under the terms of a lease.
Undeveloped Acreage Developed Acreage Total Acreage
---------------------- --------------------- ---------------------
Gross Net Gross Net Gross Net
---------- ---------- ---------- ---------- ---------- ----------
2,783 2,220 88,090 21,237 90,874 23,457
-29 -
All the leases for the undeveloped acreage summarized in the preceding table
will expire at the end of their respective primary terms unless prior to that
date, the existing leases are renewed or production has been obtained from the
acreage subject to the lease, in which event the lease will remain in effect
until the cessation of production. As is customary in the industry, we
generally acquire oil and gas acreage without any warranty of title except as
to claims made by, through or under the transferor. Although we have title to
developed acreage examined prior to acquisition in those cases in which the
economic significance of the acreage justifies the cost, there can be no
assurance that losses will not result from title defect or from defects in the
assignment of leasehold rights.
Wells Drilled and Completed
---------------------------
The Company's working interests in both operated and outside operated
exploration and development wells completed during the years indicated were as
follows:
Year Ended December 31,
-----------------------------------------
2008 2007 2006
------------- ------------- -------------
Gross Net Gross Net Gross Net
------ ------ ------ ------ ------ ------
Exploratory Wells (1):
Productive - - - - - -
Non-Productive - - - - - -
------ ------ ------ ------ ------ ------
Total - - - - - -
------ ------ ------ ------ ------ ------
Development Wells (2):
Productive 11.000 1.962 17.000 4.714 10.000 0.627
Non-Productive - - - - 1.000 0.006
------ ------ ------ ------ ------ ------
Total 11.000 1.962 17.000 4.714 11.000 0.633
------ ------ ------ ------ ------ ------
Total Exploration & Development
Wells:
Productive 11.000 1.962 17.000 4.714 10.000 0.627
Non-Productive - - - - 1.000 0.006
------ ------ ------ ------ ------ ------
Total 11.000 1.962 17.000 4.714 11.000 0.633
------ ------ ------ ------ ------ ------
- 30 -
(1) An exploratory well is a well drilled to find and produce oil or gas in an
unproved 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.
The following tables set forth additional data with respect to production from
Company-owned oil and gas operated and non-operated properties, all located
within the continental United States:
For the years ended December 31
2008 2007 2006 2005 2004
-------- -------- -------- -------- --------
Oil and Gas Production, net:
Natural Gas (Mcf) 1,231,835 880,662 671,527 655,568 577,099
Crude Oil & Condensate (Bbl) 32,663 24,472 25,443 21,323 23,098
Average Sales Price per Unit
Produced:
Natural Gas ($/Mcf) $ 8.41 $ 6.63 $ 5.55 $ 6.74 $ 5.44
Crude Oil & Condensate($/Bbl)$ 71.21 $ 65.17 $ 53.14 $ 52.50 $ 38.90
Average Production Cost per
Equivalent Barrel (1) (2) $ 14.98 $ 14.36 $ 15.14 $ 13.38 $ 11.69
(1) Includes severance taxes and ad valorem taxes.
(2) Gas production is converted to equivalent barrels at the rate of six MCFG
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, 2008.
OFFICE SPACE
The Company owns a commercial office building. The property is a two story
multi-tenant, garden office building with a sub-grade parking garage. The 26
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 10,317
rentable 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.
- 31 -
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 1,520,
1,112, and 714 MCF per day for 2008, 2007, and 2006 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.
M-R Oilfield Services, LP is an oilfield service company which provides to the
Company, roustabout, swabbing and completion services at rates which are at or
below market. This limited partnership has Chris G. Mazzini and Michelle H.
Mazzini as its limited partners. This oil field services company currently
does work exclusively for the Company and its related company, Giant Energy
Corp although it has contemplated doing work for unrelated third parties as
well. The Company benefits by having immediate access to services.
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.
During the fourth quarter of the fiscal year covered by this report, no
proceeding previously reported was terminated.
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.
- 32 -
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 2006, 2007 and 2008.
Price Per Share
High Low
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
2007
First Quarter 6.10 5.00
Second Quarter 6.10 4.05
Third Quarter 5.55 5.00
Fourth Quarter 5.70 5.15
2008
First Quarter 6.50 5.00
Second Quarter 10.95 5.23
Third Quarter 8.80 4.25
Fourth Quarter 4.00 1.75
During the First Quarter of 2009, subsequent to year end, the following high
and low prices were recorded for the Company's common stock.
Price Per Share
High Low
2009
First Quarter 3.00 1.75
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, 2009, there were approximately 550 record holders of the
Company's Common Stock.
- 33 -
The following chart compares the yearly percentage change in the cumulative
total stockholder return on the Company's Common Stock during the five years
ended December 31, 2008 with the cumulative total return of the Standard and
Poor's 500 Stock Index and of the Dow Jones U.S. Exploration and Production
Index (formerly Dow Jones Secondary Oil Stock Index). The comparison assumes
$100 was invested on December 31, 2003 in the Company's Common Stock and in
each of the foregoing indices and assumes reinvestment of dividends. The
Company paid no dividends on its Common Stock during the five-year period.
Stock Performance Chart
(See Chart in PDF Format filed Separately)
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
Company and JPMorgan Chase Bank for the purpose of acquiring its 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, 2008, the
Company did not repurchase any of its equity securities. The Board of
Directors has not approved nor authorized any standing repurchase program.
- 34 -
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
2008 2007 2006 2005 2004
----------- ----------- ----------- ----------- -----------
Total Revenue $14,064,000 $ 8,707,000 $ 6,174,000 $ 6,395,000 $ 4,515,000
Net Income (Loss) 3,521,000 1,808,000 920,000 1,417,000 1,266,000
Earnings per Share $ 0.46 $ 0.24 $ 0.12 $ 0.19 $ 0.16
As of December 31,
2008 2007 2006 2005 2004
----------- ----------- ----------- ----------- -----------
Total Assets $21,289,000 $15,631,000 $13,024,000 $11,387,000 $ 9,715,000
Long-Term Debt 1,080,000 1,200,000 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.
Results of Operations:
----------------------
2008 Compared to 2007
Oil revenue for 2008 was approximately $2,326,000 compared to $1,595,000 for
2007, an increase of approximately $731,000 or 45.8%. This was due to an
increase in average oil prices from $65.17 per bbl in 2007 to $71.21 per bbl in
2008, an increase of 9.27%. In addition to the increase in oil prices, oil
production increased from approximately 24,500 bbls in 2007 to approximately
32,650 bbls in 2008, an increase of 33.26%. This increase was primarily due to
increased revenue from the East Texas oil properties of approximately $194,000.
Gas revenue for 2008 was approximately $10,364,000 compared to $5,842,000 for
2007, an increase of approximately $4,522,000 or 77.41%. This was due
primarily to an increase in average gas prices from $6.63 per Mcf in 2007 to
$8.41 per Mcf in 2008, an increase of 26.85%. In addition to the increase in
gas prices, production increased from approximately 881,000 Mcf in 2007 to
approximately 1,232,000 Mcf in 2008, an increase of 351,000 Mcf or 39.84%. The
- 35 -
majority of the increase in gas production was from our new Barnett Shale
horizontal gas wells. There was a decrease of approximately $289,000 from our
Olex wells in Denton County, Texas. Our new Barnett Shale horizontal gas wells
accounted for approximately $3,100,000 of the increase over 2007 sales due to
production for a full year on most of the wells as well as increase gas prices
from 2007 to 2008. Gas sales for 2008 from non-operated wells increased by
approximately $462,000 as compared with 2007. In addition, we had an increase
in gas revenue from the University "K" workover of approximately $690,000.
Lease operating expenses for 2008 were $3,521,000 compared to $2,459,000,
a net increase of $1,062,000 or 43.18%. Many wells were operated in 2008 at
a decrease in expenses compared to 2007. These efficiencies were offset by
several projects including workover expenses. Remedial activity on our heavy
oil wells in Titus County, Texas was approximately $210,000 greater than in
2007. Workover expenses on our Ward, County wells were approximately $161,000
greater than in 2007. Lease operating expenses attributable to several new
Barnett Shale horizontal wells in Parker County, Texas were approximately
$580,000 greater than for the previous year. The remaining net increase in
operating expenses is due to the overall increase for oil field services,
equipment, and labor as well as additional remedial repir projects that are in
addition to normal operating expenses. In addition to increases in operating
expenses, the Company anticipates receiving a credit of approximately $264,000
for a high cost gas exemption of severance taxes covering four new Barnett
Shale wells drilled in 2007 and 2008. This anticipated credit, when approved
by and received from the State Comptroller of Texas, will be offset against
severance taxes payable.
Depreciation and amortization for 2008 was $1,215,000 compared to $728,000 for
2007, an increase of $487,000, or 66.90%. The Company re-evaluated its proved
oil and gas reserves as of December 31, 2008, and increased its depletion rate
for 2008 to 8.520% compared to 5.883% in the previous year. This increased
rate is the result of the Company's reserve base decreasing due to the lower
oil and gas prices used in the 2008 evaluation than in the 2007 evaluation.
(See Footnote 18 to the Financial Statements). This decrease of the reserve
base coupled with an increase in production over the previous year caused the
depletion percentage to increase. In addition to the rate of depletion, the
Company's undeleted amount of the full cost pot, against which the depletion
rate is applied, increased from $10,518,000 in 2007 to $12,806,000 in 2008, and
increase of $2,288,000 or 21.75%.
General and administrative expenses for 2008 was $3,198,000 compared to
$2,221,000 for 2007, an increase of approximately $977,000 between years or
44.0%. This increase is due mainly to payroll costs and associated employee
benefit costs. Personnel costs and benefits accounted for approximately
$2,649,000 of the total general and administrative costs in 2008 as compared to
$1,600,000 in 2007. This increase was due to the addition of several full-time
employees during 2008 and the last half of 2007.
- 36 -
2007 Compared to 2006
Oil revenues increased in 2007 over 2006 by approximately $243,000 an increase
of 18%. This was due to an increase in average oil prices from $53.14 per
bbl in 2006 to $65.17 per bbl in 2007 offset slightly by a decrease in
production from approximately 25,400 bbls in 2006 to approximately 24,500 bbls
in 2007. Decreased production of approximately 900 bbls or 3.5% came primarily
from mechanical issues associated with some of the Company's operated wells.
Gas revenue increased in 2007 from 2006 by approximately $2,118,000, an
increase of 56.9%. This was due primarily to an increase in average gas prices
from $5.55 per Mcf in 2006 to $6.63 per Mcf in 2007, combined with an increase
in production from approximately 672,000 Mcf in 2006 to approximately 881,000
Mcf in 2007, an increase of 31.1%. The majority of the increase in gas
production was from our new Barnett Shale horizontal gas wells. Approximately
$495,000 of the increase was from our Olex wells in Denton County, Texas. Our
new Barnett Shale horizontal gas wells accounted for approximately $1,414,000
of the increase over 2006 sales. Gas sales from non-operated wells decreased
by approximately $345,000 as compared with 2006.
Interest income is up approximately $24,000 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 during 2007 as compared to 2006.
Interest rates were also slightly higher than in the previous year.
Lease operating expenses were $353,000 (17%) higher in 2007 because costs to
operate increased. As oil and gas prices have escalated, the costs of oil
field services and equipment have also increased.
Amortization of the full cost pot (depletion) increased by approximately
$183,000 in 2007. This increase was due to the undepleted basis of the full
cost pot increasing from an estimated $8,600,00 in 2006 to an estimated
$10,500,000 in 2007, with the depletion rate increasing from 5.041% in 2006 to
5.883% in 2007.
General and administrative expenses increased approximately $687,000 between
years 2006 and 2007. 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 2007. Additionally,
a portion of the increase is attributable to the outsourcing of the Company's
payroll and benefits to Administaff, a Professional Employer Organization.
The decrease in other revenues is due mainly to receipt of approximately
$24,000 more received in 2006 over the amounts received in 2007 for farm-outs
of leasehold interests held by the Company.
The increase in interest expense for 2007 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.
- 37 -
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 49
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 Principal Executive Officer and Principal
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, 2008. Based upon that most recent evaluation, which
was completed as of the end of the period covered by this Form 10-K, the
Principal Executive Officer and Chief Financial Officer concluded that the
Company's disclosure controls and procedures were effective at December 31,
2008 to ensure that information required to be disclosed in reports that the
Company is required to file 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 changes in the Company's internal control over
financial reporting during the three months ended December 31, 2008 that have
materially affected or are reasonably likely to materially affect the Company's
internal control over financial reporting.
- 38 -
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-
5(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 determined 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.
Management of the Company has assessed the effectiveness of its internal
control over financial reporting at December 31, 2008. To make this
assessment, the Company used the criteria for effective internal control over
financial reporting described in Internal Control Integrated Framework, issued
by the Committee of Sponsoring Organizations of the Treadway Commission
("COSO"). Based on this assessment, management of the Company concluded that
as of December 31, 2008, the internal control system over financial reporting
met those criteria and was effective.
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
- 39 -
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 fourth fiscal quarter ended December 31, 2008, 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
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 51 Chairman of the Board, Director and
President
Michelle H. Mazzini 47 Director, Vice President, Secretary, Treasurer
David E. Allard 50 Director
On April 2, 2008, Mr. David E. Allard, was appointed as a member of the Board
of Directors of Spindletop Oil & Gas Co.
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. 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.
- 40 -
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.
Mr. Allard has been employed (since May 2008) by Wescott, LLC, a Dallas, Texas
based investment holding company. He was Chief Financial Officer (February
2005 to May 2008) of Digital Witness Surveillance, a Dallas, Texas based
development stage software provider; Executive Vice President and Secretary
(April 2003 to February 2, 2005) of Internet America, Inc. Mr. Allard was
Chief Operating Officer (2000-2002) of Primedia Workplace Learning, a workplace
training business; Executive Vice President and Chief Financial Officer (1999-
2000) of E-Train, Inc., a provider of online job training and seminars; Special
Advisor (1998-1999) of Thayer Capital Partners; Chief Operating Officer (1997-
1998) of Career Track, Inc. (a subsidiary of Transcontinental Realty Investors,
Inc.); Senior Vice President and Vice President - Business Development (1992-
1996) of Wescott Communications, Inc.; Partner (1985-1992) of Farmer and
Allard, P.C. (a CPA firm); Audit Manager/CPA (1983-1985) of Grant Thornton LLP
(a CPA Firm). Mr. Allard has been a Certified Public Accountant since 1983.
Key and Technical Employees
In addition to the services provided by Mr. Mazzini and Ms. Mazzini (both of
whom have biographies listed above), the Company also relies extensively on the
key and the technical employees identified below.
Michael G. Boos, Geologist, earned a Bachelor of Science degree in Geology from
the University of Delaware in 1979. After performing geophysical research for
the State of Delaware seeking hydrothermal energy sources, Mr. Boos worked
independently for many years as a Petroleum Exploration Consultant and as a
Staff Explorationist for a local oil company. He has numerous field
discoveries in the Mid-Continent to his credit. In 1993 Mr. Boos joined
Spindletop's Geological Gepartment. He pursued a Masters degree through the
University of Texas system, and later worked as a Geologist and Senior Project
Manager for several national environmental consulting firms until rejoining
Spindletop in October, 2008. His petroleum exploration experience includes
Alaska's North Slope (Prudhoe Bay), many of the continental U.S. producing
basins, as well as Central and South America. He has testified as an Expert
Witness before the Texas Railroad Commission (TRRC) on several occasions. He is
a founding member of both the Geological Information Library of Dallas (GILD,
now Geomap) and the American Association of Petroleum Geologists (AAPG)
Environmental Division, and is a licensed Professional Geologist (P.G.) in the
states of Texas and Tennessee.
Dave Chivvis, Petroleum Engineer, joined the Company at the end of May, 2008.
Mr. Chivvis earned his Bachelor of Science degree in Petroleum Engineering from
- 41 -
Texas A&M University in 1993. After graduation, he worked in Dallas for Cox
Resources Corporation. At this small independent oil and gas company, he
worked in various engineering areas from operations to acquisitions in Texas,
Oklahoma, Louisiana, and Arkansas. Mr. Chivvis then moved to Los Angeles in
2001 to pursue other opportunities before moving back to Texas to join the
Company.
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 34 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.
Charles (Chuck) D. Howell, Jr., Geologist, joined the Company in April, 2008.
Mr. Howell earned a Bachelor of Science in Geology from Southern Methodist
University in 1999. Currently, he is finishing his Ph.D. in Geology at the
University of Texas at Dallas. Mr. Howell has been in the energy industry
since 2003. He began his career at Pioneer Natural Resources working in the
Gulf of Mexico. During 2005, Mr. Howell was an Independent Consulting
Geologist for Anadarko Petroleum Corporation and worked on development of the
historic Salt Creek Oil Field. In 2007, immediately before joining Spindletop
Oil and Gas Company, he was a Geologist for Chevron Energy Technology Company
in Houston, Texas and was part of a team of stratigraphic specialists for the
West Coast of Africa. Mr. Howell is a long-standing and active member of the
American Association of Petroleum Geologists, the Society for Sedimentary
Geology, the Geological Society of America, the International Association of
Sedimentologists, and remains associated with the Ichnology Research Group.
Mike Keen, Operations Manager, joined the Company in March, 2006. Mr. Keen has
over 28 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
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
- 42 -
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
-----------------
On October 1, 2008, Mr. Mazzini and Ms. Mazzini became employees of the
Company. From October 1, 2008 to December 31, 2008 neither Mr. Mazzini nor
Ms. Mazzini were paid cash compensation in excess of $100,000.00 each as they
were employed by Giant. For the years ended December 31, 2007 and 2006,
neither Mr. Mazzini nor Ms. Mazzini received any salary from the Company.
Management fees the Company paid to Giant were 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.
- 43 -
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.
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 interests 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. We believe that these
types of compensation arrangements enable us to attract, retain and provide
additional incentives to qualified and experienced personnel
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 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. This
transaction was recorded in accordance with FAS 123-R that became effective
January 1, 2006.
Effective August 15, 2007, the Company issued 10,000 shares of restricted
common stock to a key employee pursuant to an employment package. 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 76,668 to 66,668 shares. This
transaction was recorded in accordance with FAS 123-R that became effective
January 1, 2006.
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. See Footnote No. 7, to the Financial Statements for
further detail.
Compensation of Directors
Directors who are employees of the Company are not currently compensated for
their services on the board. In 2008, Mr. Allard was paid a director's fee of
$10,000 to compensate him for his position as the Board of Directors' Financial
Expert. Mr. Allard received $2,500 for each board of directors meeting during
the year. In each of 2007 and 2006, Mr. Paul E. Cash (a director who resigned
on October 31, 2007) was paid a director's fee of $10,000 to compensate him for
his position as the Board of Directors' Financial Expert.
- 44 -
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, 2008 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.
Pct Based On
Nature of Outstanding
Name and Address Number Beneficial Percent of
Of Beneficial Owner of Shares Ownership Class
----------------------------------- -------------- ----------- ---------------
Chris Mazzini and Michelle Mazzini 5,900,543 (1) 77%
12850 Spurling Rd., Suite 200
Dallas, Texas 75230
All officers and directors
as a group 5,900,543 77%
West Coast Asset Management, Inc. 703,000 (2) 8%
West Coast Opportunity Fund, LLC
Paul J. Orfalea
Lance W. Helfert
R. Atticus Lowe
1205 Coast Village Road
Montecito, California 93108
(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. 2 to Schedule 13G filed with the Commission by
these persons for event occurring December 31, 2008, 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.
- 45 -
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
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.
Chris G. Mazzini and Michelle H. Mazzini, through a limited partnership in
which they are limited partners, own M-R Oilfield Services, LP ("MRO"), an
oilfield service company which provides roustabout, swabbing and completion
services at rates which are at or below market to the Company. This oilfield
services company currently does work exclusively for the Company and its parent
company Giant Energy Corp. although MRO is contemplating offering its services
to unrelated third-parties. The Company benefits by having immediate access to
services.
The Company along with Giant Energy Corp. ("Giant") entered into a Farmout and
Exploration Agreement dated August 22, 2006 (the "Agreement"), with Williams
Production-Gulf Coast Company, L.P. ("Williams"). The Agreement was
subsequently amended to clarify a number of provisions in the original Farmout
and Exploration Agreement. After drilling twelve of the prescribed number of
horizontal Barnett Shale wells, ten on the Spindletop leasehold and two on the
Giant leasehold, Williams gave notice of its election to terminate the
Agreement in accordance with provisions contained in the Agreement, and
subsequent amendments, effective September 19, 2008. There are no early
termination penalties incurred by Williams, or any of the parties to the
Agreement, however, by opting not to drill all of the prescribed number of
carried wells, the earned assignments shall be limited to 50% gross working
interest in said wells along with a prescribed quantity of acreage surrounding
each horizontal drain hole. As a consequence of the termination of the
Agreement, Spindletop is now free to pursue other development opportunities on
the leasehold acreage that Spindletop retained and that was not earned by
Williams under the Agreement.
Certain Business Relationships
------------------------------
The long-term debt, which is secured by the commercial office building, is also
- 46 -
guaranteed individually by Chris G. Mazzini and Michelle H. Mazzini, related
parties.
On October 1, 2008, GEC entered into an Administrative Services Agreement with
the Company whereby GEC will pay the Company $250 per month for the Company
providing administrative services to GEC.
The management services agreement between Giant and the Company which was in
effect since 1999 was terminated on September 30, 2008. This agreement
provided 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. On
October 1, 2008, GEC entered into an Administrative Services Agreement with the
Company whereby GEC will pay the Company $250 per month for the Company
providing administrative services to GEC.
The Company has entered into a management services agreement with 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. On
October 1, 2008, the Company entered into a similar agreement with Giant NRG,
LP ("NRG") a limited partnership with Chris Mazzini and Michelle Mazzini as
limited partners. Under this agreement NRG pays a monthly fee of $2,500 to the
Company in exchange for the Company providing certain administrative services
to NRG. The Company has entered into a similar arrangement with Peveler
Pipeline, LP ("Peveler"), whereby Peveler pays the Company a monthly charge of
$250 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. The Company
entered into a similar agreement with M-R Ventures, LLC ("MRV") a limited
liability company that operates some wells in Michigan, and that is owned by
Chris and Michelle Mazzini. Pursuant to this agreement, MRV will pay the
Company a monthly fee in the amount of $500 for certain administrative services
that the Company provides to MRV.
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 2008, 2007
and 2006 by accounting firm, Farmer, Fuqua, & Huff, P.C.
Type of Fees 2008 2007 2006
Audit Fees $31,000 $33,000 $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
- 47 -
to set guidelines for permitted non-audit services and fees. All the fees for
2008, 2007 and 2006 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.
- 48 -
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 . . . . . . . . .53
Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . .55
Consolidated Statement of Income. . . . . . . . . . . . . . . . .57
Consolidated Statement of Changes in
Stockholders' Equity . . . . . . . . . . . . . . . . . . . . .58
Consolidated Statements of Cash Flows . . . . . . . . . . . . . .59
Notes to Consolidated Financial Statements. . . . . . . . . . . .60
(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 (Incorporated by
reference to Exhibit 14 to the registrant's annual report
Form 10-K for the fiscal year ended December 31, 2005).
21* Subsidiaries of the Registrant
- 49 -
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 71 of this Report.
(c) The Index to Consolidated Financial Statements and Supplemental Schedules
is included following the signatures, beginning at page 51 of this Report.
- 50 -
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this Report to be signed on its
behalf by the undersigned, thereunto duly authorized.
SPINDLETOP OIL & GAS CO.
Dated: April 15, 2009
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 Registrant and
in the capacities and on the dates indicated.
Signatures Capacity Date
Principal Executive Officers:
/s/ Chris Mazzini
__________________________________ President, Director April 15, 2009
Chris Mazzini (Chief Executive
Officer)
/s/ Michelle Mazzini
__________________________________ Vice President, Secretary, April 15, 2009
Michelle Mazzini Treasurer, Director
/s/ David E. Allard
__________________________________ Director April 15, 2009
David E. Allard
/s/ Robert E. Corbin
__________________________________ Controller (Principal April 15, 2009
Robert E. Corbin Financial and Accounting
Officer)
- 51 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
Index to Consolidated Financial Statements and Schedules
Page
Report of Independent Registered Public Accounting Firm . . . . . . . . . .54
Consolidated Balance Sheets - December 31, 2008 and 2007. . . . . . . . . .55
Consolidated Statements of Income for the years
Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . .57
Consolidated Statements of Changes in Shareholders'
Equity for the years ended December 31, 2008, 2007, and 2006. . . . . .58
Consolidated Statements of Cash Flows for the years ended
December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . .59
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . .60
Schedules for the years ended December 31, 2008, 2007 and 2006
II - Valuation and Qualifying Accounts . . . . . . . . . . . . . . . . .81
III - Real Estate and Accumulated Depreciation . . . . . . . . . . . . .82
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.
- 52 -
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, 2008 and
2007, 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, 2008. Spindletop Oil & Gas Co.'s management is responsible for these
consolidated financial statements. 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. Our
audits 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, 2008 and 2007, and the consolidated
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 2008 in conformity with accounting
principles generally accepted in the United States of America.
We were not engaged to examine management's assertion about the effectiveness
of Spindletop Oil & Gas Co's internal control over financial reporting as of
December 31, 2008 included in the accompanying management report on internal
control over financial reporting and, accordingly, we do not express an opinion
thereon.
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 the 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.
/s/ Farmer, Fuqua and Huff, P.C.
Plano, Texas
April 15, 2009
- 53 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31
--------------------------
2008 2007
----------- -----------
ASSETS
Current Assets
Cash and cash equivalents $10,468,000 $ 6,325,000
Accounts receivable, trade 1,510,000 1,413,000
----------- -----------
Total current assets 11,978,000 7,738,000
----------- -----------
Property and Equipment, at cost
Oil and gas properties (full cost method) 13,633,000 11,041,000
Rental equipment 399,000 399,000
Gas gathering systems 145,000 145,000
Other property and equipment 170,000 183,000
----------- -----------
14,347,000 11,768,000
Accumulated depreciation and amortization (7,007,000) (5,902,000)
----------- -----------
Total property and equipment, net 7,340,000 5,866,000
----------- -----------
Real Estate Property, at cost
Land 688,000 688,000
Commercial office building 1,580,000 1,542,000
Accumulated depreciation (300,000) (204,000)
----------- -----------
Total real estate property, net 1,968,000 2,026,000
----------- -----------
Other Assets 3,000 1,000
----------- -----------
Total Assets $21,289,000 $15,631,000
=========== ===========
The accompanying notes are an integral part of these statements.
- 54 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - (Continued)
As of December 31
--------------------------
2008 2007
----------- -----------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable, current portion $ 120,000 $ 120,000
Accounts payable and accrued liabilities 3,788,000 2,272,000
Income tax payable 44,000 8,000
Tax savings benefit payable 97,000 97,000
----------- -----------
Total current liabilities 4,049,000 2,497,000
----------- -----------
Non-current Liabilities
Notes payable, long-term portion 1,080,000 1,200,000
Asset Retirement Obligation 667,000 564,000
----------- -----------
Total non-current liabilities 1,747,000 1,764,000
----------- -----------
Deferred income tax payable 2,457,000 1,855,000
----------- -----------
Total liabilities 8,253,000 6,116,000
----------- -----------
Shareholders' Equity
Common stock, $.01 par value; 100,000,000
Shares authorized; 7,677,471 shares
issued and 7,610,803 shares outstanding
at December 31, 2008; 7,677,471 shares
issued and 7,610,803 shares outstanding at
December 31, 2007. 77,000 77,000
Additional paid-in capital 874,000 874,000
Treasury Stock at cost (32,000) (32,000)
Retained earnings 12,117,000 8,596,000
----------- -----------
Total shareholders' equity 13,036,000 9,515,000
----------- -----------
Total Liabilities and Shareholders' Equity $21,289,000 $15,631,000
=========== ===========
The accompanying notes are an integral part of these statements.
- 55 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Years Ended December 31,
-----------------------------------
2008 2007 2006
----------- ----------- -----------
Revenues
Oil and gas revenue $12,690,000 $ 7,437,000 $ 5,076,000
Revenue from lease operations 269,000 212,000 154,000
Gas gathering, compression and
Equipment rental 179,000 179,000 140,000
Real estate rental income 509,000 512,000 430,000
Interest income 285,000 299,000 275,000
Other 132,000 68,000 99,000
----------- ----------- -----------
Total revenue 14,064,000 8,707,000 6,174,000
----------- ----------- -----------
Expenses
Lease operations 3,521,000 2,459,000 2,106,000
Pipeline and rental operations 40,000 49,000 50,000
Real estate operations 320,000 365,000 330,000
Depreciation and amortization 1,215,000 728,000 528,000
Accretion of asset retirement obligation 38,000 24,000 34,000
General and administrative 3,198,000 2,221,000 1,534,000
Interest expense 112,000 86,000 142,000
----------- ----------- -----------
Total expenses 8,444,000 5,932,000 4,724,000
----------- ----------- -----------
Income before income tax 5,620,000 2,775,000 1,450,000
----------- ----------- -----------
Current tax provision 1,497,000 436,000 -
Deferred tax provision 602,000 531,000 530,000
----------- ----------- -----------
2,099,000 967,000 530,000
----------- ----------- -----------
Net income $ 3,521,000 $ 1,808,000 $ 920,000
=========== =========== ===========
Earnings per Share of Common Stock
Basic $ 0.46 $ 0.24 $ 0.12
=========== =========== ===========
Diluted $ 0.46 $ 0.24 $ 0.12
=========== =========== ===========
Weighted Average Shares Outstanding 7,610,803 7,604,269 7,589,995
=========== =========== ===========
Diluted Shares Outstanding 7,610,803 7,604,269 7,589,995
=========== =========== ===========
The accompanying notes are an integral part of these statements.
- 56 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2008, 2007 and 2006
Additional Treasury
Common Stock Paid-In Stock Retained
Shares Amount Capital Shares Amount Earnings
--------- -------- ---------- -------- -------- -----------
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
Issuance of 5,000
shares of Common Stock
out of Treasury Stock
as part of an employee
compensation package - - 9,000 (5,000) 2,000 -
Issuance of 10,000
shares of Common Stock
out of Treasury Stock
as part of an employee
compensation package - - 15,000 (10,000) 6,000 -
Net Income - - - - - 1,808,000
--------- -------- ---------- -------- -------- -----------
Balance at
December 31, 2007 7,677,471 $ 77,000 $ 874,000 66,668 $(32,000)$ 8,596,000
Net Income - - - - - 3,521,000
--------- -------- ---------- -------- -------- -----------
Balance at
December 31, 2008 7,677,471 $ 77,000 $ 874,000 66,668 $(32,000)$12,117,000
========= ======== ========== ======== ======== ===========
The accompanying notes are an integral part of these statements.
- 57 -
SPINDLETOP OIL & GAS CO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31,
-----------------------------------
2008 2007 2006
----------- ----------- -----------
Cash Flows from Operating Activities
Net Income $ 3,521,000 $ 1,808,000 $ 920,000
Reconciliation of net income
to net cash provided by
Operating Activities
Depreciation and amortization 1,215,000 728,000 528,000
Accretion of asset retirement
Obligation 38,000 24,000 34,000
Loss on disposal of assets 8,000 - -
Non-cash employee compensation - 32,000 21,000
Changes in prepaid expenses
to related party - 60,000 (60,000)
Changes in accounts receivable (97,000) (240,000) 55,000
Changes in prepaid income tax - 427,000 (426,000)
Changes in accounts payable 1,517,000 35,000 293,000
Changes in current taxes payable 35,000 8,000 (20,000)
Changes in deferred taxes payable 602,000 531,000 530,000
Changes in other assets (2,000) (1,000) 1,000
----------- ----------- -----------
Net cash provided by operating
activities 6,837,000 3,412,000 1,876,000
----------- ----------- -----------
Cash flows from Investing Activities
Capitalized acquisition, exploration
and development costs (2,527,000) (2,651,000) (1,305,000)
Purchase of property and equipment (8,000) (42,000) 10,000
Capitalized tenant improvements (39,000) (33,000) (210,000)
Proceeds from sale of properties - - -
----------- ----------- -----------
Net cash used for investing activities
activities (2,574,000) (2,726,000) (1,505,000)
----------- ----------- -----------
Cash Flows from Financing Activities
Repayment of note payable to a bank (120,000) (120,000) (120,000)
----------- ----------- -----------
Net cash used for financing
activities (120,000) (120,000) (120,000)
----------- ----------- -----------
Increase in cash 4,143,000 566,000 251,000
Cash at beginning of period 6,325,000 5,759,000 5,508,000
----------- ----------- -----------
Cash at end of period $10,468,000 $ 6,325,000 $ 5,759,000
=========== =========== ===========
The accompanying notes are an integral part of these statements.
- 58 -
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, 2008, 2007, and 2006,
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 10,317 rentable 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.
- 59 -
Cash and Cash Equivalents
-------------------------
The Company considers all highly liquid instruments with a maturity of three
months or less to be cash equivalents.
Allowance for Doubtful Accounts
-------------------------------
The Company provides an allowance for doubtful accounts equal to the estimated
uncollectible portion of accounts receivable. This estimate is based on
historical collection experience and a review of the current status of accounts
receivable.
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, development costs and estimated
future expenditures for proved undeveloped properties as well as estimated
dismantlement and abandonment costs as calculated under the asset retirement
obligation category, net of salvage value. 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
- 60 -
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
--------------------------
All investments in real estate holdings are stated at cost or adjusted carrying
value. Statement of Financial Accounting 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 earnings 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 2008 due to impairment of
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.
- 61 -
The following table reflects the changes of the asset retirement obligations
during the period ending December 31;
2008 2007
------------ ------------
Carrying amount of asset retirement obligation $ 564,000 $ 251,000
Liabilities added 84,000 374,000
Liabilities divested or settled (19,000) (85,000)
Current period accretion expenses 38,000 24,000
------------ ------------
Carrying amount as of December 31, $ 667,000 $ 564,000
============ ============
Revenue Recognition
-------------------
The Company follows the "sales" (takes or cash) method of accounting for oil
and gas revenues. Under this method, we recognize revenues on oil and gas
production as it is taken and delivered to the purchasers. The volumes sold
may be more or less than the volumes we are entitled to take based on our
ownership in the property. These differences result in a condition known as a
production imbalance. Our crude oil and natural gas imbalances are
insignificant.
Income Taxes
------------
In June, 2006, the Financial Accounting Standards Board ("FASB") issued
Interpretation No..48, "Accounting for Uncertainty in Income Taxes , an
Interpretation of SFAS No.109" ("FIN 48"). The interpretation creates a single
model to address accounting for uncertainty in tax positions. Specifically, the
pronouncement prescribes a recognition threshold and a measurement attribute
for the financial statement recognition and measurement of a tax position taken
or expected to be taken in a tax return. The interpretation also provides
guidance on de-recognition, classification, interest and penalties, accounting
in interim periods, disclosure and transition of certain tax positions.
The Company adopted the provisions of FIN 48 effective January 1, 2007. The
adoption of this accounting principle did not have an effect on the Company's
consolidated financial statements at, and for the three years ended
December 31, 2008.
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.
- 62 -
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.
Newly issued accounting standards
----------------------------------
In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements."
("SFAS No. 157"). SFAS No. 157 defines fair value and establishes a framework
for measuring fair value, which includes a hierarchy based on the quality of
inputs used to measure fair value. SFAS No. 157 also expands disclosures about
fair value measurements. SFAS No. 157 does not require any new fair value
measurements. SFAS No. 157 requires the categorization of financial assets and
liabilities, based on the inputs to the valuation technique, into a three-level
fair value hierarchy. The fair value hierarchy gives the highest priority to
the quoted prices in active markets for identical assets and liabilities and
lowest priority to unobservable inputs. SFAS No. 157 requires the use of
observable market data, when available, in making fair value measurements. When
inputs used to measure fair value fall within different levels of the
hierarchy, the level within which the fair value measurement is categorized is
based on the lowest level input that is significant to the fair value
measurement. The levels of the SFAS No. 157 fair value hierarchy are described
as follows:
- Level 1-Financial assets and liabilities whose values are based on
unadjusted quoted market prices for identical assets and liabilities in
an active market that the Company has the ability to access.
- Level 2-Financial assets and liabilities whose values are based on
quoted prices in markets that are not active or model inputs that are
observable for substantially the full term of the asset or liability.
- Level 3-Financial assets and liabilities whose values are based on
prices or valuation techniques that require inputs that are both
unobservable and significant to the overall fair value measurement.
- 63 -
SFAS No. 157 became effective for fiscal years beginning after November 15,
2007. In February 2008, the FASB deferred the effective date of SFAS No. 157
for one year for nonfinancial assets and nonfinancial liabilities that are
recognized or disclosed at fair value in the financial statements on a
nonrecurring basis. The FASB also removed certain leasing transactions from the
scope of SFAS No. 157. On January 1, 2008, the Company partially adopted SFAS
No. 157. The partial adoption of this statement did not have a material impact
on the financial statements. Management expects to adopt the remaining
provisions of SFAS 157 beginning in 2009. Management does not expect this
adoption to have a material impact on the consolidated financial statements.
In February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for
Financial Assets and Financial Liabilities-including an amendment of FASB
Statement No. 115. " ("SFAS No. 159"). SFAS No. 159 permits entities to choose,
at specified election dates, to measure many financial instruments and certain
other items at fair value that are not currently required to be measured at
fair value. Unrealized gains and losses shall be reported on items for which
the fair value option has been elected in earnings at each subsequent reporting
date. SFAS No. 159 became effective for fiscal years beginning after November
15, 2007. On January 1, 2008, the Company adopted SFAS No. 159 and has
currently not elected to measure any financial instruments or other items (not
currently required to be measured at fair value) at fair value.
In December 2007, the FASB issued SFAS No. 141 (revised 2007) ("SFAS l4lR"),
"Business Combinations. " SFAS l4lR establishes principles and requirements for
how the acquirer of a business recognizes and measures in its financial
statements the identifiable assets acquired, the liabilities assumed, and any
noncontrolling interest in the acquiree. The statement also provides guidance
for recognizing and measuring the goodwill acquired in the business combination
and determines what information to disclose to enable users of the financial
statements to evaluate the nature and financial effects of the business
combinations. SFAS 141R is effective for financial statements issued for fiscal
years beginning after December 15, 2008. Accordingly, any business combinations
the Company engages in will be recorded and disclosed following existing
accounting principles until January 1, 2009. The Company expects SFAS 141R will
affect the Company's consolidated financial statements when effective, but the
nature and magnitude of the specific effects will depend upon the nature, term
and size of the acquisitions, if any, the Company consummates after the
effective date.
In December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in
Consolidated Financial Statements." effective for financial statements issued
for fiscal years beginning after December 15, 2008. SFAS No. 160 states that
accounting and reporting for minority interests will be recharacterized as
noncontrolling interests and classified as a component of equity. SFAS No. 160
applies to all entities that prepare consolidated financial statements, except
not-for-profit organizations, and will impact the recording of minority
interest. The Company is currently evaluating the effects the adoption of SFAS
No. 160 will have on its financial position and results of operations.
In March 2008, the FASB issued SFAS No. 161, "Disclosures about Derivative
Instruments and Hedging Activities - an amendment of FASB Statement No. 133"
effective for interim periods after November 15, 2008. SFAS No. 161 requires
enhanced disclosures about an entity's derivative and hedging activities and
- 64 -
thereby improves the transparency of financial reporting. The Company
currently does not have any derivative instruments or hedging activities that
required adoption of SFAS No. 161.
In May 2008, the FASB issued SFAS No. 163, " Accounting for Financial Guarantee
Insurance Contracts-an interpretation of FASB Statement No. 60" effective for
financial statements issued for fiscal years beginning after December 15, 2008,
and interim periods within those fiscal years beginning after May 23, 2008.
This statement requires expanded disclosures about financial guarantee
insurance contract. The Company currently does not have any guarantee
insurance contracts that require disclosure under SFAS No. 163.
3. ACCOUNTS RECEIVABLE
December 31,
----------------------------
2008 2007
------------ ------------
Trade $ 640,000 $ 370,000
Accrued receivable 884,000 1,057,000
------------ ------------
1,524,000 1,427,000
Less: Allowance for losses (14,000) (14,000)
------------ ------------
$ 1,510,000 $ 1,413,000
============ ============
Accrued receivables are receivables from purchasers of oil and gas. These
revenues are booked from check stub detail after receipt of the check for sales
of oil and gas products. These payments are for sales of oil and gas produced
in the reporting period, but for which payment has not yet been received until
after the closing date of the reporting period. Therefore these sales are
accrued as receivables as of the balance sheet date. Revenues for oil and gas
production that has been sold but for which payment has not yet been received
is accrued in the period sold.
4. ACCOUNTS PAYABLE
December 31,
----------------------------
2008 2007
------------ ------------
Trade payables $ 544,000 $ 699,000
Production proceeds payable 1,990,000 1,070,000
Prepaid drilling costs 834,000 414,000
Other 420,000 89,000
----------- ------------
$ 3,788,000 $ 2,272,000
=========== ============
- 65 -
5. NOTES PAYABLE
December 31,
----------------------------
2008 2007
------------ ------------
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. $ 1,200,000 $ 1,320,000
Less current maturities 120,000 120,000
------------ ------------
Total notes payable, long-term portion $ 1,080,000 $ 1,200,000
============ ============
Estimated annual maturities for long-term debt are as follows:
2009 $ 120,000
2010 120,000
2011 120,000
2012 120,000
2013 120,000
thereafter 480,000
-----------
$ 1,080,000
===========
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 ending December 31,
2008, 2007 and 2006 includes $180,000, $240,000 and $240,000, respectively,
related to this agreement. Effective October 1, 2008, this agreement was
terminated.
- 66 -
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 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 issued by a bank for the
benefit of an company in favor of the Railroad Commission of Texas. This
letter of credit was 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. This
letter of credit are secured by a restriction of certain funds of the Company
on deposit at the bank 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.
The Company and Giant entered into a joint Barnett Shale horizontal drilling
and development program dated August 22, 2006, and later amended on October 20,
2006 (the "Agreement") with an unrelated third party company. (See "Joint
Drilling Development of North Texas Barnett Shale Leasehold" on page 6).
Effective September 19, 2008, the unrelated third party terminated the
Agreement in accordance with provisions contained in the Agreement, and
subsequent amendments.
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, 2006, the Company issued 10,000 shares of restricted
common stock to a key employee pursuant to an employment package. 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.
Effective March 22, 2007, the Company issued 5,000 shares of restricted common
stock to a key employee pursuant to an employment package. 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. This transaction
- 67 -
was recorded in accordance with FAS 123-R that became effective
January 1, 2006.
Effective August 15, 2007, the Company issued 10,000 shares of restricted
common stock to a key employee pursuant to an employment package. 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 76,668 to 66,668 shares. This transaction
was recorded in accordance with FAS 123-R that became effective January 1, 2006
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 2008, 2007 and 2006, respectively. As of
December 31, 2008 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, 2008 and 2007,
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 2008, 2007 and 2006 as a
result of the following:
2008 2007 2006
----------- ---------- ----------
Computed expected tax expense $ 1,910,000 $ 944,000 $ 493,000
Miscellaneous timing differences
related to book and tax depletion
differences and the expensing of
intangible drilling costs (576,000) (508,000) (493,000)
----------- ---------- ----------
Expected Federal income tax $ 1,334,000 $ 436,000 $ -
=========== ========== ==========
- 68 -
Income tax expense for the years ended December 31, 2008, 2007 and 2006
consisted of the following:
2008 2007 2006
----------- ---------- ----------
Federal income taxes $ 1,334,000 $ 436,000 $ -
State income taxes 163,000 - -
----------- ---------- ----------
Current income tax provision $ 1,497,000 $ 436,000 $ -
=========== ========== ==========
Deferred income taxes reflect the effects of temporary differences between the
tax bases of assets and liabilities and the reported amounts of those assets
and liabilities for financial reporting purposes. Deferred income taxes also
reflect the value of net operating losses, investment tax credits and an
offsetting valuation allowance. The Company's total deferred tax assets and
corresponding valuation allowance at December 31, 2008 and 2007 consisted of
the following:
December 31,
----------------------------
2008 2007
------------ ------------
Deferred tax assets
Depreciation, depletion and amortization (44,000) 22,000
Other, net 9,000 9,000
------------ ------------
Total (35,000) 31,000
Deferred tax liabilities
Expired leasehold (54,000) (58,000)
Intangible drilling costs (2,368,000) (1,828,000)
------------ ------------
Net deferred tax liability (2,457,000) (1,855,000)
============ ============
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 $79,000, $86,000, and $94,000 for the years 2008, 2007 and 2006,
respectively. Also included are cash payments for taxes of $1,300,000, $-0-,
and $445,000 in 2008, 2007 and 2006, respectively.
Excluded from the Consolidated Statements of Cash Flows were the effects of
certain non-cash investing and financing activities, as follows:
- 69 -
2008 2007 2006
----------- ----------- -----------
Addition (reduction) of Oil & Gas
Properties by recognition of
Asset Retirement Obligation $ 65,000 289,000 $ (22,000)
----------- ----------- -----------
$ 65,000 $ 289,000 $ (22,000)
=========== =========== ===========
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
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, 2008 the Company had approximately $5,775,000 in checking
and money market accounts at one bank, and approximately $3,634,000 in a second
bank, including $1,400,000 of short-term certificates of deposit. The Company
also had approximately $2,856,000, including $1,000,000 of short-term
certificates of deposit invested at ten other banking institutions. Cash
amounts on deposit at these institutions exceed current per account FDIC
protection limits by approximately $6,339,000.
Most of the Company's business activity is located in Texas. Accounts
receivable as of December 31, 2008 and 2007 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,
2008 and 2007 follow:
-------- 2008 ------ -------- 2007 -------
Carrying Fair Carrying Fair
Amount Value Amount Value
----------- ----------- ----------- -----------
Cash $10,468,000 $10,468,000 $ 6,325,000 $ 6,325,000
Accounts receivable 1,510,000 1,510,000 1,413,000 1,413,000
The fair value amounts for each of the financial instruments listed above
approximate carrying amounts due to the short maturities of these instruments.
- 70 -
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, 2008 the Company has acquired bonds and letters of credit
issued in favor of various state regulatory agencies as mandated by state law
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 seven letters of credit from a bank 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 $250,000. These letters of credit
have expiration dates that range from February 26, 2009 through March 31, 2010
and are fully secured by funds on deposit with the bank 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, 2008, 2007 and 2006 follows.
Sale of Oil & Gas Properties
----------------------------
Effective June 1, 2007, the Company sold its working interest and operations in
the Federal 2-33 well located in Lea County, New Mexico to an unrelated party
for $20,000 in cash.
- 71 -
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.
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, 2008:
Year Ended December 31, (1)
--------------------------------
Purchaser 2008 2007 2006
----------------------------------------- -------- -------- --------
Crosstex Energy Services, LP 42% 26% 3%
Enbridge Energy Partners
(formerly Enbridge North Texas 26% 36% 38%
Targa Midstream Service, LIM
(formerly Dynegy Midstream Services, LIM 6% 3% -%
Shell Trading (US) Company 5% 6% 8%
Eastex Crude Company 3% 2% -%
Devon Gas Services, L.P 2% 2% 4%
Teppco Crude Oil, LP 2% 5% 3%
Genesis 1% -% -%
Gateway Gathering & Marketing 1% -% -%
ETC Texas Pipeline 1% 2% 5%
Navajo Refining Co. 1% 2% -%
Plains Marketing, L.P. -% 1% 6%
(1) Percent of Total Oil & Gas Sales
Oil and gas is sold to approximately 96 different purchasers 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, 2008.
The Company currently has no hedged contracts.
- 72 -
Certain revenues, costs and expenses related to the Company's oil and gas
operations are as follows:
Year Ended December 31,
-----------------------------------
2008 2007 2006
----------- ----------- -----------
Capitalized costs relating to oil
and gas producing activities:
Unproved properties $ 1,821,000 $ 1,100,000 $ 428,000
Proved properties 11,813,000 9,941,000 7,674,000
----------- ----------- -----------
Total capitalized costs 13,634,000 11,041,000 8,102,000
Accumulated amortization (6,340,000) (5,249,000) (4,631,000)
----------- ----------- -----------
Total capitalized costs, net $ 7,294,000 $ 5,792,000 $ 3,471,000
=========== =========== ===========
Year Ended December 31,
-----------------------------------
2008 2007 2006
----------- ----------- -----------
Costs incurred in oil and gas property
acquisition, exploration and
development:
Acquisition of properties $ 28,000 $ 1,516,000 $ -
Development costs 2,509,000 1,423,000 1,283,000
----------- ----------- -----------
Total costs incurred $ 2,537,000 $ 2,939,000 $ 1,283,000
=========== =========== ===========
Year Ended December 31,
-----------------------------------
2008 2007 2006
----------- ----------- -----------
Results of Operations from producing
activities:
Sales of oil and gas $12,690,000 $ 7,437,000 $ 5,076,000
----------- ----------- -----------
Production costs 3,521,000 2,459,000 2,106,000
Amortization of oil and gas
Properties 1,091,000 619,000 435,000
----------- ----------- -----------
Total production costs 4,612,000 3,078,000 2,541,000
----------- ----------- -----------
Total net revenue $ 8,078,000 $ 4,359,000 $ 2,535,000
=========== =========== ===========
- 73 -
Year Ended December 31,
-----------------------------------
2008 2007 2006
----------- ----------- -----------
Sales price per equivalent Mcf $ 8.89 $ 7.24 $ 6.16
=========== =========== ===========
Production costs per equivalent Mcf $ 2.47 $ 2.39 $ 2.55
=========== =========== ===========
Amortization per equivalent Mcf $ 0.76 $ 0.60 $ .53
=========== =========== ===========
Year Ended December 31,
-----------------------------------
2008 2007 2006
----------- ----------- -----------
Results of Operations from gas
gathering and equipment rental
activities:
Revenue $ 179,000 $ 179,000 $ 140,000
----------- ----------- -----------
Operating expenses 40,000 50,000 50,000
Depreciation 8,000 7,000 10,000
----------- ----------- -----------
Total costs 48,000 57,000 60,000
----------- ----------- -----------
Total net revenue $ 131,000 $ 122,000 $ 80,000
=========== =========== ===========
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, 2008:
Year Ended December 31,
-----------------------------------
2008 2007 2006
----------- ----------- -----------
Revenues: (3)
Oil and gas exploration, production
and operations $12,959,000 $ 7,649,000 $ 5,230,000
Gas gathering, compression and
equipment rental 179,000 179,000 140,000
Real estate rental 509,000 512,000 430,000
----------- ----------- -----------
$13,647,000 $ 8,340,000 $ 5,800,000
=========== =========== ===========
- 74 -
Depreciation, depletion and
Amortization expense:
Oil and gas exploration, production
and operations $ 1,110,000 $ 673,000 $ 471,000
Gas gathering, compression and
equipment rental 8,000 8,000 10,000
Real estate rental 97,000 47,000 47,000
----------- ----------- -----------
$ 1,215,000 $ 728,000 $ 528,000
=========== =========== ===========
Income from operations:
Oil and gas exploration, production
and operations $ 8,290,000 $ 4,493,000 $ 2,653,000
Gas gathering, compression and
equipment rental 131,000 122,000 80,000
Real estate rental 92,000 100,000 53,000
----------- ----------- -----------
8,513,000 4,715,000 2,786,000
Corporate and other (1) (5,344,000) (2,907,000) (1,866,000)
----------- ----------- -----------
Consolidated net income (loss) $ 3,169,000 $ 1,808,000 $ 920,000
=========== =========== ===========
Identifiable Assets net of DDA:
Oil and gas exploration, production
and operations $ 7,333,000 $ 5,851,000 $ 3,507,000
Gas gathering, compression and
equipment rental 7,000 15,000 23,000
Real estate rental 1,968,000 2,026,000 2,076,000
----------- ----------- -----------
$ 9,308,000 $ 7,892,000 $ 5,606,000
Corporate and other (2) 11,981,000 7,739,000 7,418,000
----------- ----------- -----------
Consolidated total assets $21,289,000 $15,631,000 $13,024,000
=========== =========== ===========
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.
- 75 -
16. SUPPLEMENTARY INCOME STATEMENT INFORMATION
The following items were charged directly to expense:
Year Ended December 31,
-----------------------------------
2008 2007 2006
----------- ----------- -----------
Maintenance and repairs $ 21,000 $ 8,000 $ 31,000
Production taxes 337,000 455,000 290,000
Taxes, other than payroll and
income taxes (13,000) 49,000 37,000
17. QUARTERLY DATA (UNAUDITED)
The table below reflects selected quarterly information for the years ended
December 31, 2008, 2007 and 2006.
Year Ended December 31, 2008
----------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
---------- ---------- ---------- ----------
Revenue $3,410,000 $3,553,000 $4,482,000 $2,619,000
Expense (1,502,000) (2,052,000) (1,975,000) (2,915,000)
---------- ---------- ---------- ----------
Operating income 1,908,000 1,501,000 2,507,000 (296,000)
Current tax provision (321,000) (540,000) (859,000) 223,000
Deferred tax provision (410,000) 56,000 30,000 (278,000)
---------- ---------- ---------- ----------
Net income 1,177,000 1,017,000 1,678,000 (351,000)
========== ========== ========== ==========
Earnings per share
of common stock
Basic and Diluted $0.15 $0.13 $0.22 ($0.04)
- 76 -
Year Ended December 31, 2007
----------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
---------- ---------- ---------- ----------
Revenue $1,417,000 $2,160,000 $1,988,000 $3,142,000
Expense (999,000) (1,296,000) (1,440,000) (2,197,000)
---------- ---------- ---------- ----------
Operating income 418,000 864,000 548,000 945,000
Current tax provision (111,000) (177,000) (10,000) (138,000)
Deferred tax provision (91,000) (173,000) (147,000) (120,000)
---------- ---------- ---------- ----------
Net income 216,000 514,000 391,000 687,000
========== ========== ========== ==========
Earnings per share
of common stock
Basic and Diluted $0.03 $0.07 $0.05 $0.09
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 and Diluted $0.06 $0.02 $0.04 $0.00
- 77 -
18. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
The Company's net proved oil and natural gas reserves as of December 31, 2008,
2007, and 2006 have been estimated by Netherland, Sewell & Associates, Inc.
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.
Changes in Estimated Quantities of Proved Oil and Gas Reserves (Unaudited):
Crude Oil Natural Gas
Bbls Mcf
------------ ------------
Quantities of Proved Reserves:
------------------------------
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
Sales of reserves in place - -
Acquired properties - -
Extensions and discoveries 12,239 1,485,603
Revisions of previous estimates 765 375,862
Production (24,472) (880,662)
------------ ------------
Balance December 31, 2007 345,154 14,366,765
Sales of reserves in place - -
Acquired properties - -
Extensions and discoveries 1,500 130,600
Revisions of previous estimates (52,279) 494,418
Production (32,663) (1,231,835)
------------ ------------
Balance December 31, 2008 261,712 13,759,948
============ ============
* May be described as a divestiture, not a change in engineering.
- 78 -
Proved Developed Reserves:
--------------------------
Balance December 31, 2006 340,870 7,352,511
Balance December 31, 2007 334,213 10,947,481
Balance December 31, 2008 252,948 10,882,637
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 2008 oil and gas prices. Lease operating costs, compression,
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
116 operated wells and 121 non-operated wells. Materially insignificant
operated and 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.
- 79 -
Standardized measure of discounted future net cash flows related to proved
reserves:
Year Ended December 31,
--------------------------------------
2008 2007 2006
------------ ------------ ------------
Future production revenue $ 83,207,000 $115,233,000 $ 81,294,000
Future development costs (4,476,000) (4,601,000) (4,778,000)
Future production costs (29,657,000) (26,806,000) (21,323,000)
------------ ------------ ------------
Future net cash flow before
Federal income tax 49,074,000 83,826,000 55,193,000
Future income taxes (13,741,000) (23,471,000) (15,454,000)
------------ ------------ ------------
Future net cash flows 35,333,000 60,355,000 39,739,000
Effect of 10% annual discounting (13,072,000) (18,141,000) (14,074,000)
------------ ------------ ------------
Standardized measure of
Discounted net cash flows $ 22,261,000 $ 42,214,000 $ 25,665,000
============ ============ ============
Changes in the standardized measure of discounted future net cash flows:
Year Ended December 31,
--------------------------------------
2008 2007 2006
------------ ------------ ------------
Beginning of the year $ 42,214,000 $ 25,665,000 $ 27,861,000
Oil and gas sales, net of
production costs (9,169,000) (4,978,000) (2,970,000)
Sales of reserves in place - - -
Net change in prices, net of
production costs (82,308,000) 20,449,000 (8,513,000)
Extensions, discoveries and additions 16,636,000 7,243,000 9,251,000
Changes in production rates,
timing and other - - -
Revisions of quantity estimate 54,243,000 (4,093,000) (1,592,000)
Effect of income tax (3,576,000) (4,638,000) (1,158,000)
Accretion of discount 4,221,000 2,566,000 2,786,000
------------ ------------ ------------
End of year $ 22,261,000 $ 42,214,000 $ 25,665,000
============ ============ ============
- 80 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2008, 2007, AND 2006
SCHEDULE II
Beginning Costs & Ending
Description Balance Expenses Deductions Balance
----------------------------- ----------- ----------- ----------- -----------
Allowance for
doubtful Accounts
December 31, 2006 $ 14,000 $ - $ - $ 14,000
========== ========== ========== ==========
December 31, 2007 $ 14,000 $ - $ - $ 14,000
========== ========== ========== ==========
December 31, 2008 $ 14,000 $ - $ - $ 14,000
========== ========== ========== ==========
- 81 -
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 $282,000
Gross Amounts at Which Carried at Close of Year
Life on which
Accumulated Depreciation Date
Land Buildings Total Depreciation Calculated Acquired
---------- ------------ ----------- ------------- ------------ -----------
$ 688,000 $ 1,580,000 $ 2,268,000 $ 300,000 (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, 2008 is as follows:
Investments in Accumulated
Real Estate Depreciation
------------ ------------
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
Acquisitions 34,000
Depreciation expense 84,000
------------ ------------
Balance, December 31, 2007 $ 2,230,000 $ 204,000
Acquisitions 38,000
Depreciation expense 96,000
------------ ------------
Balance, December 31, 2008 $ 2,268,000 $ 300,000
============ ============
- 82 -
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
- 83 -
EXHIBIT 21
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
Subsidiaries of the Registrant
Spindletop Drilling Company, incorporated September 5, 1975, under the laws of
the State of Texas, is a wholly owned subsidiary 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.
- 84 -
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 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;
(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
- 85 -
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 15, 2009
/s/ Chris G. Mazzini
CHRIS G. MAZZINI
Principal Executive Officer
- 86 -
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 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;
(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
- 87 -
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 15, 2009
/s/ Robert E. Corbin
ROBERT E. CORBIN
Principal Financial and
Accounting Officer
- 88 -
Exhibit 32
Certification Pursuant to 18 U.S.C. Section 1350
As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
In connection with the Annual Report of Spindletop Oil & Gas Co. (the
"Company"), on Form 10-K for the year ended December 31, 2008 as filed with
The Securities Exchange Commission on the date hereof (the "Report"), the
undersigned Principal Executive Officer and Principal Financial and Accounting
Officer of the Company, do hereby certify, pursuant to 18 U.S.C. Section 1350,
as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
The Report fully complies with the requirements of Section 13(a) or 15(d)
of the Securities Exchange Act of 1934; and
The information contained in the Report fairly presents, in all material
respects, the financial condition and result of operations of the Company.
Dated: April 15, 2009
/s/ Chris G. Mazzini
CHRIS G. MAZZINI
Principal Executive Officer
/s/ Robert E. Corbin
ROBERT E. CORBIN
Principal Financial and
Accounting Officer
- 89 -