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, 2010
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 [ ] No [ X ]
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
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 (Sec293.405 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.
$3,547,033 based upon a total of 1,730,260 shares held as of June 30, 2010 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 7,640,803
(Class) (Outstanding at March 31, 2011)
DOCUMENTS INCORPORATED BY REFERENCE
None
PART I
Item 1. Description of Business
GENERAL
Spindletop Oil & Gas Co. is an independent oil and gas company engaged in the
exploration, development, production and acquisitions 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.
("SOG") 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 22 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
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program focused principally in the Fort Worth Basin of North Texas. Today, the
Company has retained many of these wells as producing properties and holds a
large amount of acreage by production in that Basin.
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 with a focus on our Barnett Shale acreage.
From 2009 we split our focus by looking for value-priced acquisitions combined
with development drilling. In the current economic climate, we are continuing
our efforts to acquire producing properties and taking a more conservative
approach to development of our leasehold acreage. We are looking at growth
through acquisitions and limited drilling. With current lower natural gas
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.
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. 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.
- 4 -
Project Significant Areas
The Company owns various interests in wells located in 15 states and the
Company's operations are currently located in 6 of those states which include
Alabama, Arkansas, Louisiana, Oklahoma, New Mexico and Texas.
The Company holds approximately 92,293 gross acres under lease in 15 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 Percent
Properties Properties Total of Total
Gross Net Gross Net Gross Net Gross Net
Geographic Area Acres Acres Acres Acres Acres Acres Acres Acres
------ ------ ------ ----- ------ ------ ----- ----
North Texas Including
the Fort Worth Basin
& Bend Arch 7,282 6,750 2,070 221 9,352 6,971 10.1 33.0
East Texas 2,613 2,245 7,629 543 10,242 2,788 11.1 13.2
Gulf Coast Texas 3,903 2,307 2,930 223 6,833 2,530 7.4 12.0
West Texas 788 618 2,664 109 3,452 727 3.7 3.4
Texas Panhandle 640 640 1,280 75 1,920 715 2.1 3.4
Alabama 1,160 634 1,469 135 2,629 769 2.8 3.6
Arkansas 2,936 2,587 4,329 116 7,265 2,703 7.9 12.8
Louisiana 723 506 2,938 138 3,661 644 4.0 3.0
New Mexico 1,524 980 360 4 1,884 985 2.0 4.7
Oklahoma 237 166 33,405 1,020 33,642 1,186 36.3 5.6
Utah - - 2,729 487 2,729 487 3.0 2.3
Wyoming - - 1,800 134 1,800 134 2.0 0.6
Kansas - - 640 184 640 184 0.7 0.9
North Dakota - - 1,262 138 1,262 138 1.4 0.7
Montana - - 2,570 113 2,570 113 2.8 0.5
Colorado - - 1,200 64 1,200 64 1.3 0.3
Mississippi - - 80 - 80 - 0.1 0.0
California - - 892 6 892 6 1.0 0.0
Michigan - - 240 6 240 6 0.3 0.0
Total 21,806 17,433 70,487 3,716 92,293 21,150 100.0 100.0
The majority of the Company's net acres (63.4%) are located in Texas.
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A breakout of the Company's most significant oil and gas reserves by geographic
area is as follows:
North Texas Including
the Fort Worth Basin
& Bend Arch 1,413,993 BOE 66.31 %
East Texas 231,895 BOE 10.87 %
Gulf Coast Texas 106,265 BOE 4.98 %
West Texas 55,550 BOE 2.60 %
Panhandle Texas 51,768 BOE 2.43 %
Total Texas 1,859,471 BOE 87.19 %
Oklahoma 97,747 BOE 4.59 %
New Mexico 91,187 BOE 4.28 %
Alabama 40,760 BOE 1.91 %
Arkansas 17,030 BOE 0.80 %
Louisiana 15,948 BOE 0.75 %
North Dakota 5,213 BOE 0.24 %
Wyoming 2,833 BOE 0.13 %
California 1,162 BOE 0.05 %
Montana 1,062 BOE 0.05 %
Kansas 272 BOE 0.01 %
Michigan 70 BOE 0.00 %
Total 2,132,755 BOE 100.00 %
North Texas - Fort Worth Basin & Bend Arch
The Fort Worth Basin-Bend Arch Province has been the focal point of the Company
since its inception. Our technical personnel have an average of 22 years of
exploration, drilling, completing, and production experience extracting natural
gas and oil from both conventional and unconventional hydrocarbon deposits
found across the basin. Furthermore, the Company maintains comprehensive and
extensive dossiers of geologic and engineering data gathered from the province.
Exploration and development drilling for hydrocarbons across the Fort Worth
Basin-Bend Arch Province remain strong.
The Fort Worth Basin-Bend Arch Province is a major United States onshore
natural gas-prone expanse containing multiple pay zones that range in depth
from one thousand to nine thousand (1,000-9,000) feet. Improved advances in
fracturing and stimulation technologies, which have unlocked natural gas and
oil reserves from the hydrocarbon bearing Barnett Shale Formation; and thus,
continue to bolster vigorous exploration and development activities that target
conventional and unconventional reservoir reserves throughout the province.
The Barnett Shale is a thick blanket type natural gas bearing stratigraphic
zone found throughout the Fort Worth Basin-Bend Arch Province. The natural gas
reserves in place are significant; however, as a consequence of the extreme low
permeability character of the shales, it has been technically challenging to
produce these reserves. According to the United States Geological Survey
assessment, an estimated 26.7 trillion cubic feet (TCF) of undiscovered natural
gas, 98.5 MMBO of undiscovered oil, as well as a mean of 1.1 BBNGL of
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undiscovered natural gas liquids reserves remain within the 54,000 square mile
Fort Worth Basin-Bend Arch Province. More than 98 percent or approximately
26.2 TCF of the undiscovered natural gas is contained in the organic-rich
Mississippian Barnett Shale. Combined, recent advances in hydraulic
fracturing, completion procedures, as well as refined horizontal well drilling
technologies continue to enable economic recovery of natural gas reserves from
tight-gas reservoirs throughout the Fort Worth Basin-Bend Arch Province.
Undiscovered conventional reservoir natural gas reserves are estimated to be
467 billion cubic feet of gas (BCFG) the majority of which is dissolved in
conventional oil accumulations (source: United States Geological Survey Energy
Resource Program).
The Company has 9,352 gross acres under lease across the prolific Fort Worth
Basin-Bend Arch Province the majority of which, is held by production from the
more shallow producing zones. The Company uses recent and emerging
technologies, as well as proven extant practices to develop and produce oil and
natural gas from the portfolio. Additionally, the Company has a dedicated
well-trained team of employees and professional staff continually seeking low-
risk profitable acquisition opportunities throughout the Fort Worth Basin-Bend
Arch Province.
Barnett Shale
During the fourth quarter of 2008, the Poston #1 well, located on our Godley
North Block, in Johnson County, Texas was drilled to the Barnett Shale
Formation at a depth of 6,754 ft. and cased. The well was completed, placed
on-line and went into sales with an initial rate of 400 mcfgpd on August 2,
2010. The well is located in the Newark, E. (Barnett Shale) field. The Company
owns a 91.0% working interest in this well. The well is currently producing at
a rate of 40 mcfgpd and 2 bswpd.
Additional Company activities in the North Texas area include the following:
North Texas
During the third quarter of 2010, the Company acquired non-operating working
interests in 29 natural gas wells in Jack, Palo Pinto, Parker, and Wise
Counties, Texas. At the time of acquisition, gross production from these wells
was approximately 416 mcfgpd and 3.4 bopd. Net production attributable to the
Company's acquired interest was approximately 87 mcfgpd and 0.8 bopd. Working
interests acquired range from 21.25% to 40.00%. Net revenue interests acquired
range from 16.42% to 30.00%.
East Texas
The Company participated for a 45.00% non-operated working interest in the
drilling of two wells operated by Giant Energy Co., LP, a related entity. The
two wells are located in Nacogdoches County, Texas. The Giant Gas Unit #1 well
was spud on November 11, 2009 and reached a total depth of 9,700 ft. on
December 6, 2009. Production casing was set to a depth of 9,616 ft. through
the Travis Peak Formation. The Giant Gas Unit #2 well was spud on June 1, 2010
and reached a total depth of 9,608 ft. on July 7, 2010. Production casing was
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set to a depth of 9,605 ft. through the Travis Peak Formation. The wells are
currently being worked on.
West Texas
During the first half of 2010, the Company participated in the drilling of four
non-operated wells located in the Fuhrman-Mascho field in Andrews County,
Texas. Three of the wells were cased, completed and placed in production
during the second quarter of 2010. The fourth well was cased and completed on
July 2, 2010 and placed in production on July 11, 2010. The Miles #13, #14,
#15, and #16 wells had initial production rate of 148 bopd, 69 bopd, 99 bopd,
and 76 bopd respectively, and 30 mcfgpd, 30 mcfgpd, 28 mcfgpd, and 16 mcfgpd
respectively from the San Andres formation at an approximate depth of 4,750 ft.
All of the wells on this lease are currently producing at a combined rate of
203 bopd and 95 mcfgpd. The Company owns a 4.69% working interest and a 3.28%
net revenue interest in these wells.
Texas Panhandle
During the third quarter of 2010, the Company acquired operations of two wells
in its Spearman SE block in Ochiltree County, Texas; the Pope #140-3 and Pope
#140-4. The Company has a 100.00% working interest and an 81.25% net revenue
interest in both of these wells. At the time of acquisition, the Pope #140-3
well was producing at a rate of 4 mcfgpd from the Horizon (Oswego) field from a
perforated interval at 6,920 ft. - 6,930 ft. in the Oswego Formation. The Pope
#140-4 well was producing at a rate of 24 mcfgpd from the Lips (Mississippian)
field from a perforated interval at 8,294 ft. - 8,396 ft. in the Mississippian
Formation. The Pope #3 well is currently producing at a rate of 3 mcfgpd and
the Pope #4 well is currently producing at a rate of 23 mcfgpd.
South Texas
During the second quarter of 2010, the Company acquired working interests in
five natural gas wells in Victoria County, Texas. The Company assumed
operatorship of three of these wells effective April 1, 2010.
The Vaquero #1 well produces gas from the Rob Welder (Wilcox 9100) field in the
Wilcox Group from a perforated interval of 9,314-9,346 ft. Current production
from the Vaquero #1 is approximately 6 mcfgpd. The Vaquero "A" #2 well
produces gas from the Welder Ranch field from a perforated interval of
12,026 - 12,090 ft. in the Wilcox Group. Current production from this well is
approximately 4 mcfgpd. The Rob Welder #1 well produces gas from the McFaddin
(5700) field from a perforated interval at 5,660 - 5,658 ft. in the Yegua
Formation. Current production from this well is approximately 109 mcfgpd and
4 bswpd. The working interests in these three wells are 94.63%, 85.00%, and
100.00% with net revenue interests of 64.69%, 58.13%, and 68.00% respectively.
The interests acquired in the two remaining wells were non-operated working
interests. The Company acquired a 25.00% non-operating working interest and
17.00% net revenue interest in the Welder Ranch #1 well which produces gas from
the Rob Welder (Wilcox 10,400) field from the perforated interval of
10,480 ft.- 10,520 ft. in the Wilcox Group. Current gross production from this
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well is approximately 11 mcfgpd. The Company acquired a 24.17% non-operating
working interest and 16.44% net revenue interest in the Welder Ranch A #2 well
which produces gas from the Marshall (Middle Wilcox) field from a perforated
interval of 10,306 - 10,312 ft. in the Middle Wilcox Group. Current gross
production from this well is approximately 99 mcfgpd and 0.4 bopd.
The Company acquired a 33.06% operated working interest and a 22.5% net revenue
interest in the State Tract 39A-#1 gas well in Chambers County, Texas effective
July 1, 2010. The State Tract 39A-#1 well produces gas from the Turtle Beach
(Vicksburg) field from a perforated interval at 11,111 ft. - 11,148 ft. in the
Vicksburg Formation. Gross gas production from this well at the time of
acquisition was approximately 1,294 mcfgpd and 3 bopd. Production attributable
to the Company's acquired interest was approximately 292 mcfgpd and 0.5 bopd.
Currently, this well is shut-in.
On July 29, 2010 the Company spud its Hynes #28 well in Bee County, Texas. The
well was drilled to a depth of 3,500 ft. to test the Catahoula Sands. The well
was cased and completed and placed into production on August 14, 2010. The
well's IPP (initial potential pumping) was 17 bopd and 20 bswpd from the
Papalote, E. (3250-B) field at a perforated interval of 3,244 ft. - 3,346 ft.
from the Catahoula Formation. The company owns a 100.00% working interest and
a 60.84% net revenue interest in this well. The well is currently producing at
a rate of approximately 10.5 bopd and 12 bswpd.
Additional Company activities outside of Texas include the following:
Oklahoma
Effective August 1, 2010, the Company acquired operations and working interests
in four wells located in Major County and Canadian County, Oklahoma as follows:
The Irvan #1-22 well, located in Major County, produces natural gas from the
N. Homestead field from a perforation interval ranging from 7,158 ft. - 7,306
ft. from the Inola and Chester formations. At the time of acquisition, the
Irvan #1-22 well was producing natural gas at a rate of 6 mcfgpd and is
currently producing at the same rate. The Company acquired a 100.00% working
interest and a 75.00% net revenue interest in this well.
The Tobe #1-21 well, located in Major County, produces natural gas from the
N. Homestead field from a perforation interval ranging from 7,158 ft. - 7,232
ft. from the Red Fork and Inola Formations. At the time of acquisition, the
Tobe #1-21 well was shut-in and not producing. The Company acquired a 92.31%
working interest and a 73.29% net revenue interest in this well.
The Faith #1-21 well, located in Canadian County, produces natural gas from the
Watonga-Chickasha field from a perforation interval ranging from 10,882 ft. -
0,952 ft. from the Morrow Formation. At the time of acquisition, the
Faith #1-21 well was shut-in and not producing. The Company acquired an 83.33%
working interest and a 66.67% net revenue interest in this well.
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The Lottie Jones #33-4 well, located in Canadian County, produces natural gas
from the El Reno field from a perforation interval ranging from 8,750 ft. -
10,366 ft. from the Viola, Hunton, Mississippian and Red Fork formations. At
the time of acquisition, the Lottie Jones #4 well was shut-in and not
producing. The Company acquired a 97.43% working interest and a 74.64% net
revenue interest in this well.
These wells were acquired for their behind the pipe potential. The Company
plans to rework them at a future date and place them back into production, if
successful.
New Mexico
Effective December 1, 2010, the Company acquired operations and working
interests in four oil wells located in the Fowler East Field, one oil well
located in the Teague Field, and one well located in the Dollarhide Field,
Lea County, New Mexico as follows:
The Greenback State #1 well produces approximately 2 bopd, 1 mcfgpd, and 3
bswpd, from a perforation interval of 11,685 ft. - 11,839 ft. in the
Ellenberger Formation. The Company acquired a 100.00% working interest and
80.25% net revenue interest in this oil well.
The Greenback State #2 well produces 4.2 bopd, 4 mcfgpd, and 30 bswpd from an
open hole interval of 11,581 ft. - 11,641 ft. from the Ellenberger Formation.
The Company acquired a 100.00% working interest and 77.75% net revenue
interest.
The Greenback State #3 well produces 9.6 bopd, 8 mcfgpd, and 113 bswpd from an
open hole interval between 11,630 ft. - 11,756 ft. in the Ellenberger
Formation. The Company acquired a 100.00% working interest and 77.75% net
revenue interest.
The Greenback State #7-1 well is producing from an open hole interval between
11,462 ft. - 11,568 ft. in the Ellenberger Formation. The well produces 16.3
bopd, 10 mcfgpd, and 96 bswpd. The Company acquired an 80.0% working interest
and 70.0% net revenue interest.
The Greenback Federal #1 well produces from a perforation interval of 7,103 ft.
7,311 ft. from the Abo Formation. The well is currently producing
Approximately 0.2 bopd. The Company acquired a 100.00% working interest and
82.50% net revenue interest.
The Hunt #23-1 well is producing approximately 3.1 bopd and 52 bswpd from an
open hole interval between 10,928 ft.-11,017 ft. in the Ellenberger Formation.
The Company acquired a 97.10% working interest and a net revenue interest of
77.05%.
Effective December 1, 2010, the Company acquired non-operating working
interests in four oil wells in the Monument Abo Field, Lea County New Mexico
as follows:
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The Foster #3 well produces approximately 20.8 bopd and 25 mcfgpd from a
perforation interval of 7,323 ft. -7,428 ft. from the Abo Zone. The Company
acquired a working interest of 40.37% and a net revenue interest of 29.27%.
The Royal Wulff #1 well produces from an interval of 7,258 ft. - 7,360 ft.
from the Abo Formation. The well is currently shut in. The Company acquired
a working interest of 40.25% and a Net Revenue interest of 30.19%.
The Royal Coachman #1 well produces approximately .033 mcfgpd from a
perforation interval of 7,330 ft. - 7,444 ft. in the Abo Formation. The Company
purchased a working interest of 38.61% and a net revenue interest of 28.96%.
The Royal Trude #1 well produces approximately .09 bopd and 0.19 mcfgpd from a
perforation interval of 7,298 ft. - 7,315 ft. in the Abo Formation. The Company
purchased a working interest of 12.00% and a net revenue interest of 9.00%.
The production rates referenced above for these New Mexico properties are as of
the effective date.
For all of the aforementioned wells, the Company cautions that the initial
production rates of new wells or production rates at the effective date of
acquisition may not be an indicator of stabilized production rates or an
indicator of the ultimate recoveries obtained.
Oil and Natural Gas Reserves
----------------------------
The net proved crude oil and gas reserves of the Company as of December 31,
2010 were 362,350 barrels of oil and condensate and 10.622 BCFG of natural gas.
Based on SEC guidelines, the reserves were classified as follows:
Proved Developed Producing 327,750 BO and 8.106 BCFG
Proved Developed Non-Producing 34,120 BO and 0.648 BCFG
Proved Undeveloped 480 BO and 1.868 BCFG
Total Proved Reserves 362,350 BO and 10.622 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 five years) underlying the Company's
properties. Shut-in uneconomic wells and insignificant non-operated interests
were excluded.
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On a BOE (barrel of oil equivalent) basis (6 MCF/BOE), the net reserves are:
Natural Gas Reserves 1,770,405 BOE 83%
Oil Reserves 362,350 BOE 17%
Total Reserves 2,132,755 BOE 100%
Proved Developed Producing 1,678,946 BOE 79%
Proved Developed Non-Producing 142,077 BOE 7%
Proved Undeveloped 311,732 BOE 14%
Total Proved Reserves 2,132,755 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 1,864,327 BOE 87%
Non Operated Wells 268,428 BOE 13%
Total 2,132,755 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 1,793 mcfgpd. 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.
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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 one to five years, and
in some instances as long as ten 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, 2010:
Year Ended December 31, (1)
--------------------------------
Purchaser 2010 2009 2008
----------------------------------------- -------- -------- --------
Enbridge Energy Partners
(formerly Enbridge North Texas) 26% 36% 26%
Crosstex Gulf Coast Mktg 16% 23% 42%
Eastex Crude Company 7% 7% 3%
Shell Trading (US) Company 7% 6% 5%
Kinder Morgan 5% -% -%
Enterprise Crude Oil LLC(Teppco Crude Oil, LP) 5% 4% 2%
Conoco Phillips Company 4% 1% -%
Targa Midstream Service, LIM 3% 3% 6%
Navajo Refining Co. 3% 3% 1%
Genesis 2% 2% 1%
DCP Midstream, LP 2% -% -%
ETC Texas Pipeline 2% 1% 1%
Sunoco Partners Marketing 2% -% -%
Devon Gas Services, LP -% 1% 2%
Gateway Gathering & Marketing -% -% 1%
(1) Percent of Total Oil & Gas Sales
- 13 -
Oil and gas is sold to approximately 102 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 two percent of the Company's oil and gas
revenues during the three years ended December 31, 2010.
The Company currently has no hedged contracts.
Prospective Drilling Activities
The Company's primary oil and gas prospect generation and 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. The Company does not own any drilling rigs and all
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 leases under prospects, and carrying out exploratory
drilling on the prospective leasehold 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
limited 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 drilling of such prospect will normally
require the Company to fund the development activities.
Special Tax Provisions
See Footnote 8 to Consolidated Financial Statements regarding the accounting
for income taxes.
- 14 -
Employees
The Company employs or contracts for the services of a total of approximately
sixty-two people. Twenty-seven are full-time employees. The remainder, are
part-time employees or independent contractors. We believe that our
relationships with our employees are good.
In order to effectively utilize our resources, we employ the services of
independent consultants and contractors to perform a variety of professional
and technical services, including in the areas of lease acquisition, land
related documentation and contracts, drilling and completion work, pumping,
inspection, testing, maintenance and specialized services. We believe that it
can be more cost effective to utilize the services of consultants and
independent contractors for some of these services.
We depend to a large extent on the services of certain key management personnel
and officers, and the loss of any these individuals could have a material
adverse effect on our operations. The Company does not maintain key-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 United States
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.
- 15 -
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.
"BSWPD" means barrels of salt water per day.
"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.
"Gas" means natural gas.
- 16 -
"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
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
- 17 -
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
onclusive 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.
- 18 -
"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.
- 19 -
Item 1A. Risk Factors
Risks related directly to our Company
One 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.
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 recent years. 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
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.
- 20 -
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
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
- 21 -
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 $2,187,000 will be required to
fully develop some of these reserves in the next twelve month period. 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. These estimates have been prepared
by Company personnel for 2010 and 2009 and by Netherland, Sewell & Associates,
Inc., independent petroleum engineers for 2008. There are numerous
uncertainties inherent in estimating quantities of reserves of oil and gas and
in projecting future rates of production and the timing of development
expenditures, including many factors beyond our control. The reserve estimates
in this annual report are based on various assumptions, including, for example,
constant oil and gas prices, operating expenses, capital expenditures and the
availability of funds, and therefore, are inherently imprecise indications of
future net cash flows. Actual future production, cash flows, taxes, operating
expenses, development expenditures and quantities of recoverable oil and gas
reserves may vary substantially from those assumed in the estimates. Any
significant variance in these assumptions could materially affect the estimated
quantity and value of reserves set forth in this prospectus. Additionally, our
reserves may be subject to downward or upward revision based upon actual
production performance, results of future development and exploration,
prevailing oil and gas prices and other factors, many of which are beyond our
control.
The present value of future net reserves discounted at 10% (the "PV-10") of
proved reserves referred to in this annual report should not be construed as
the current market value of the estimated proved reserves of oil and gas
attributable to our properties. In accordance with applicable requirements of
the SEC, the estimated discounted future net cash flows from proved reserves
are generally based on prices and costs as of the date of the estimate, whereas
actual future prices and costs may be materially higher or lower. Actual
future net cash flows also will be affected by: (i) the timing of both
production and related expenses; (ii) changes in consumption levels; and (iii)
governmental regulations or taxation. In addition, the calculation of the
present value of the future net cash flows using a 10% discount as required by
the SEC is not necessarily the most appropriate discount factor based on
interest rates in effect from time to time and risks associated with our
- 22 -
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."
Unless we replace our oil and natural gas reserves, our reserves and production
will decline, which would adversely affect our cash flows and income.
Unless we conduct successful development, exploitation and exploration
activities or acquire properties containing proved reserves, our proved
reserves will decline as those reserves are produced. Producing oil and
natural gas reservoirs generally are characterized by declining production
rates that vary depending upon reservoir characteristics and other factors.
Our future oil and natural gas reserves and production, and, therefore our cash
flow and income, are highly dependent on our success in efficiently developing
and exploiting our current reserves and economically finding or acquiring
additional recoverable reserves. We may be unable to make such acquisitions
because we are:
- unable to identify attractive acquisition candidates or negotiate
acceptable purchase contracts with them;
- unable to obtain financing for these acquisitions on economically
acceptable terms; or
- outbid by competitors.
If we are unable to develop, exploit, find or acquire additional reserves to
replace our current and future production, our cash flow and income will
decline as production declines, until our existing properties would be
incapable of sustaining commercial production.
There are risks in acquiring producing oil and gas properties, including
difficulties in integrating acquired properties into our business, additional
liabilities and expenses associated with acquired properties, diversion of
management attention, increasing the scope, geographic diversity and complexity
of our operations.
One of our business strategies includes growing our reserve base through
acquisitions. Our failure to integrate acquired properties successfully into
our existing business, or the expense incurred in consummating future
acquisitions, could result in unanticipated expenses and losses. In addition,
we may assume cleanup or reclamation obligations or other unanticipated
liabilities in connection with these acquisitions. The scope and cost of these
obligations may ultimately be materially greater than estimated at the time of
the acquisition.
We are continually investigating opportunities for acquisitions. In connection
with future acquisitions, the process of integrating acquired operations into
our existing operations may result in unforeseen operating difficulties and may
require significant management attention and financial resources that would
otherwise be available for the ongoing development or expansion of existing
operations. Our ability to make future acquisitions may be constrained by our
ability to obtain additional financing.
- 23 -
Possible future acquisitions could result in our incurring debt, contingent
liabilities and expense, all of which could have a material effect on our
financial condition and operating results.
Acquisitions may prove to be worth less than we paid because of uncertainties
in evaluating recoverable reserves and potential liabilities.
Successful acquisitions require an assessment of a number of factors, including
estimates of recoverable reserves, exploration potential, recovery
applicability from waterflood and Enhanced Oil Recovery techniques ("EOR"),
future oil and natural gas prices, operating costs and potential environmental
and other liabilities. Such assessments are inexact and their accuracy is
inherently uncertain. In connection with our assessments, we perform a review
of the acquired properties which we believe is generally consistent with
industry practices. However, such a review will not reveal all existing or
potential problems. In addition, our review may not permit us to become
sufficiently familiar with the properties to fully assess their deficiencies
and capabilities. We do not inspect every well or property. Even when we
inspect a well or property, we do not always discover structural, subsurface
and environmental problems that may exist or arise. We are generally not
entitled to contractual indemnification for pre-closing liabilities, including
environmental liabilities. Normally, we acquire interests in properties on an
"as is" basis with limited remedies for breaches of representations and
warranties. As a result of these factors, we may not be able to acquire oil
and natural gas properties that contain economically recoverable reserves or be
able to complete such acquisitions on acceptable terms.
Additionally, significant acquisitions can change the nature of our operations
and business depending upon the character of the acquired properties, which may
have substantially different operating and geological characteristics or be in
different geographic locations than our existing properties. It is our current
intention to continue focusing on acquiring properties with development and
exploration potential located in onshore United States. To the extent that we
acquire properties substantially different from the properties in our primary
operating regions or acquire properties that require different technical
expertise, we may not be able to realize the economic benefits of these
acquisitions as efficiently as in our prior acquisitions.
We cannot control activities on properties we do not operate. Failure to fund
capital expenditure requirements may result in reduction or forfeiture of our
interests in some of our non-operated projects.
We do not operate some of the properties in which we have an interest and we
have limited ability to exercise influence over operations for these properties
or their associated costs. As of December 31, 2010, approximately 13% of our
crude oil and natural gas proved reserves were operated by other companies.
Our dependence on other operators and other working interest owners for these
projects and our limited ability to influence operations and associated costs
could materially adversely affect the realization of our targeted return on
capital in drilling or acquisition activities and our targeted production
- 24 -
growth rate. The success and timing of drilling, development and exploitation
activities on properties operated by others depend on a number of factors that
are beyond our control, including the operator's expertise and financial
resources, approval of other participants for drilling wells and utilization of
technology.
When we are not the majority owner or operator of a particular crude oil or
natural gas project, we may have no control over the timing or amount of
capital expenditures associated with such project. If we are not willing or
able to fund our capital expenditures relating to such projects when required
by the majority owner or operator, our interests in these projects may be
reduced or forfeited.
We are subject to risks associated with the current United States Government
Administration's proposed budget features.
The Obama administration has 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,
- 25 -
development drilling of oil and gas reserves involve a high degree of risk that
no commercial production will be obtained and/or that production will be
insufficient to recover drilling and completion costs. The cost of drilling,
completing and operating wells is often uncertain. Our drilling operations may
be curtailed, delayed or canceled as a result of numerous factors, including
title problems, weather conditions, compliance with governmental requirements
and shortages or delays in the delivery of equipment. Furthermore, completion
of a well does not assure a profit on the investment or a recovery of drilling,
completion and operating costs.
We depend on our key management personnel and technical experts and the loss of
any of these individuals could adversely affect our business.
If we lose the services of our key management personnel, technical experts or
are unable to attract additional qualified personnel, our business, financial
condition, results of operations, development efforts and ability to grow could
suffer. We have assembled a team of engineers and geologists who have
considerable experience in applying advanced drilling and completion techniques
to explore for and to develop crude oil and natural gas. We depend upon the
knowledge, skill and experience of these experts to assist us in improving the
performance and reducing the risks associated with our participation in crude
oil and natural gas exploration and development projects. In addition, the
success of our business depends, to a significant extent, upon the abilities
and continued efforts of our management, particularly Chris Mazzini, our Chief
Executive Officer, President and Chairman of the Board. We do not have an
employment agreement with or key man life insurance on Mr. Mazzini or any of
our other employees.
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
- 26 -
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 market and is currently
quoted on the OTC Bulletin Board ("OTCBB"), 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 United States stock market has from time to time experienced
extreme price and volume fluctuations that have affected the market price for
many companies and which often have been unrelated to the operating performance
of these companies. These broad market fluctuations may adversely affect the
market price of our securities.
We do not intend to declare dividends in the foreseeable future.
Our Board of Directors presently intends to retain all of our earnings for the
expansion of our business. We therefore do not anticipate the distribution of
cash dividends in the foreseeable future. Any future decision of our Board of
Directors to pay cash dividends will depend, among other factors, upon our
earnings, financial position and cash requirements.
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, 2010, 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.
- 27 -
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, 2010, we had working capital of $5,685,000. 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
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.
- 28 -
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 our 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, 2010, approximately 76%
of our gas production is currently sold to nine 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 2010, 2009, and
2008, and experienced fluctuations similar to those seen in natural gas prices
for the year. We believe that oil prices will continue to fluctuate in
response to changes in the policies of the Organization of Petroleum Exporting
Countries ("OPEC"), changes in demand from many Asian countries, current events
in the Middle East, security threats to the United States, and other factors
associated with the world political and economic environment. As a result of
the many uncertainties associated with levels of production maintained by OPEC
and other oil producing countries, the availabilities of worldwide energy
supplies and competitive relationships and consumer perceptions of various
energy sources, we are unable to predict what changes will occur in crude oil
and natural gas prices.
We may be responsible for additional costs in connection with abandonment of
properties.
We are responsible for payment of plugging and abandonment costs on its oil and
gas properties pro rata to our working interest. Based on our experience, we
anticipate that in most cases, the ultimate aggregate salvage value of lease
and well equipment located on our properties 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.
- 29 -
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
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
- 30 -
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
regulations of certain states limit the rate at which oil and gas can be
produced from our properties. However, we do not believe we will be affected
materially differently by these statutes and regulations than any other
similarly situated oil and gas company.
We may not have enough insurance to cover all of the risks we face, which could
result in significant financial exposure.
We maintain insurance coverage against some, but not all, potential losses in
order to protect against the risks we face. We may elect not to carry
insurance if our management believes that the cost of insurance is excessive
relative to the risks presented. If an event occurs that is not covered, or
not fully covered, by insurance, it could harm our financial condition, results
of operations and cash flows. In addition, we cannot fully insure against
pollution and environmental risks.
- 31 -
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
- 32 -
the prevention of oil spills and liability for damages resulting from such
spills in waters of the United States. The "responsible party" includes the
owner or operator of an onshore facility or vessel or the lessee or permittee
of, or the holder of a right of use and easement for, the area where an onshore
facility is located. OPA assigns liability to each responsible party for oil
spill removal costs and a variety of public and private damages from oil
spills. Few defenses exist to the liability for oil spills imposed by OPA.
OPA also imposes financial responsibility requirements. Failure to comply with
ongoing requirements or inadequate cooperation in a spill event may subject a
responsible party to civil or criminal enforcement actions.
We own or lease properties that for many years have produced oil and gas. We
also own natural gas gathering systems. It is not uncommon for such properties
to be contaminated with hydrocarbons. Although we or previous owners of these
interests may have used operating and disposal practices that were standard in
the industry at the time, hydrocarbons or other wastes may have been disposed
of or released on or under the properties or on or under other locations where
such wastes have been taken for disposal. These properties may be subject to
federal or state requirements that could require us to remove any such wastes
or to remediate the resulting contamination. In addition to properties that we
operate, we have interests in many properties which 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,
-----------------------------------
2010 2009 2008
----------- ----------- -----------
Gas and Oil Properties, net (1):
Proved developed gas reserves-Mcf (2)
Proved developed producing 8,106,000 8,166,000 8,280,000
Proved developed non-producing 648,000 2,507,000 2,603,000
Proved undeveloped gas reserves-Mcf (3) 1,868,000 1,848,000 2,877,000
----------- ----------- -----------
Total proved gas reserves-Mcf 10,622,000 12,521,000 13,760,000
=========== =========== ===========
- 33 -
Proved Developed Crude Oil and
Condensate reserves-Bbls (2)
Proved developed producing 328,000 284,000 225,000
Proved developed non-producing 34,000 13,000 28,000
Proved Undeveloped crude oil and
Condensate reserves-Bbls (3) -0- 26,000 9,000
----------- ----------- -----------
Total proved crude oil and condensate
Reserves-Bbls 362,000 323,000 262,000
=========== =========== ===========
(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 2008 through 2010.
(4) Reserve amounts are rounded to the nearest thousand.
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, 2010.
Gas Wells Oil Wells Total Wells
---------------------- --------------------- ---------------------
Gross Net Gross Net Gross Net
---------- ---------- ---------- ---------- ---------- ----------
374 97.24 153 63.06 527 160.30
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, 2010.
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. Undrilled acreage held
by production under the terms of a lease is included in the Developed Acre
category total shown below.
- 34 -
Undeveloped Acreage Developed Acreage Total Acreage
---------------------- --------------------- ---------------------
Gross Net Gross Net Gross Net
---------- ---------- ---------- ---------- ---------- ----------
7,215 3,398 92,294 21,152 99,509 25,550
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,
-----------------------------------------
2010 2009 2008
------------- ------------- -------------
Gross Net Gross Net Gross Net
------ ------ ------ ------ ------ ------
Exploratory Wells (1):
Productive - - - - - -
Non-Productive - - - - - -
------ ------ ------ ------ ------ ------
Total - - - - - -
------ ------ ------ ------ ------ ------
Development Wells (2):
Productive 10.000 1.391 9.000 1.261 11.000 1.962
Non-Productive - - - - - -
------ ------ ------ ------ ------ ------
Total 10.000 1.391 9.000 1.261 11.000 1.962
------ ------ ------ ------ ------ ------
Total Exploration & Development
Wells:
Productive 10.000 1.391 9.000 1.261 11.000 1.962
Non-Productive - - - - - -
------ ------ ------ ------ ------ ------
Total 10.000 1.391 9.000 1.261 11.000 1.962
------ ------ ------ ------ ------ ------
- 35 -
(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
2010 2009 2008 2007 2006
-------- -------- -------- -------- --------
Oil and Gas Production, net:
Natural Gas (Mcf) 823,957 866,416 1,231,835 880,662 671,527
Crude Oil & Condensate (Bbl) 31,526 25,875 32,663 24,472 25,443
Average Sales Price per Unit
Produced:
Natural Gas ($/Mcf) $ 4.89 $ 4.13 $ 8.41 $ 6.63 $ 5.55
Crude Oil & Condensate($/Bbl)$ 74.35 $ 56.55 $ 71.21 $ 65.17 $ 53.14
Average Production Cost per
Equivalent Barrel (1) (2) $ 15.48 $ 14.37 $ 14.98 $ 14.36 $ 15.14
(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, 2010.
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 28
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.
- 36 -
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 two inches to four 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 1,793,
1,659, and 1,520, MCF per day for 2010, 2009, and 2008 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
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.
- 37 -
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 2008, 2009, and 2010.
Price Per Share
High Low
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
2009
First Quarter 3.19 1.75
Second Quarter 2.50 1.70
Third Quarter 2.45 1.50
Fourth Quarter 2.95 1.65
2010
First Quarter 1.99 1.65
Second Quarter 5.50 1.60
Third Quarter 2.25 1.39
Fourth Quarter 2.25 1.45
During the First Quarter of 2011, subsequent to year end, the following high
and low prices were recorded for the Company's common stock.
Price Per Share
High Low
2011
First Quarter $ 2.79 $ 2.10
There is no amount of common stock that is subject to outstanding warrants to
purchase, or securities convertible into, common stock of the Company.
According to the transfer records of the Company at March 31, 2011, common
stock of the Company was held by approximately 547 holders of record.
- 38 -
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, 2010 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, 2005 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, 2010, the
Company did not repurchase any of its equity securities. The Board of
Directors has not approved nor authorized any standing repurchase program.
- 39 -
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
2010 2009 2008 2007 2006
----------- ----------- ----------- ----------- -----------
Total Revenue $ 7,656,000 6,913,000 $14,064,000 $ 8,707,000 $ 6,174,000
Net Income 447,000 39,000 3,521,000 1,808,000 920,000
Earnings per Share $ 0.06 $ 0.01 $ 0.46 $ 0.24 $ 0.12
As of December 31,
2010 2009 2008 2007 2006
----------- ----------- ----------- ----------- -----------
Total Assets $20,777,000 $20,386,000 $21,289,000 $15,631,000 $13,024,000
Long-Term Debt 840,000 960,000 1,080,000 1,200,000 1,320,000
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
---------------------
2010 Compared to 2009
Oil revenue for 2010 was approximately $ 2,368,000 compared to $1,485,000 for
2009, an increase of approximately $883,000 or 59%. This was due in large part
to an increase in oil prices from an average of $56.55 per bbl in 2009 to an
average of $74.35 per bbl in 2010; an increase of $17.80 per bbl or 31%. In
addition to the increase in prices, oil sales increased from approximately
25,875 bbls in 2009 to approximately 31,526 bbls in 2010, an increase of 5,651
bbls or 22%.
- 40 -
Gas revenue for 2010 was approximately $3,934,000 compared to $3,582,000 for
2009, an increase of approximately $352,000 or 10%. Gas sales decreased from
approximately 866,000 mcf in 2009 to approximately 824,000 mcf in 2010, a
decrease of 42,000 mcf or 5%. Gas prices increased an average of $0.76 per mcf
or 18% from an average of $4.13 per mcf in 2009, to an average of $4.89 per mcf
in 2010.
Revenue from gas gathering for 2010 was $179,000, a decrease of $13,000 or 7%
from $192,000 in 2009. This was due primarily to the decrease in gas volume
sold.
Real estate income was down 11% or $55,000 from $503,000 in 2009 to $448,000 in
2010. This was due to the expiration of three rental contracts in 2010 which
were not renewed.
Interest income for 2010 was $158,000, a decrease of $50,000 from $208,000 in
2009 or 24%.
The interest rate on certain deposit accounts at one of the banks in which the
Company is a depositor was decreased significantly toward the end of the year
resulting in an approximate $18,000 reduction in interest income received. In
addition, certificate of deposit rates decreased from an average of 3.3% in
2009 to an average of 1.8% in 2010 resulting in a decrease of approximately
$14,000. Also, in 2009, an interest payment of approximately $18,000 was
received from the Texas State Comptroller that was not received in 2010.
Other income for 2010 was $250,000, a decrease of $376,000 or over 60% from
$626,000 in 2009. Approximately $100,000 of this decrease is due to ad valorem
service fees charged by the Company in 2009 over those charged in 2010. An
additional $20,000 was due to gain on divestitures in 2009 that did not exist
in 2010. The majority of the remaining amount is due to recognition of turnkey
income in 2009 that did not occur in 2010.
Lease operating expenses increased to $1,901,000 in 2010 from $1,640,000 in
2009 an increase of $261,000 or 16%. Approximately $120,000 of this increase
comes from new wells in 2010 and another $52,000 comes from increased work over
costs. Expenses to plug non-economical wells increased by $37,000 and finally,
there was an increase in expenses from non-operated wells of approximately
$29,000.
Production taxes, gathering, transportation and marketing expenses for 2010
were approximately $712,000 compared to $807,000 in 2009, a net decrease of
$95,000. This 12% decrease is due in part to the decrease in volume sold.
Additionally, there have been reductions in severance taxes paid due to the
low-volume tax exemptions.
Depreciation and amortization for 2010 was $1,042,000 compared to $997,000 for
2009, an increase of $45,000, or 4.5%. The Company re-evaluated its proved oil
and gas reserves as of December 31, 2010, and decreased its estimated total
proved reserves by approximately 277,000 BOE to 2,133,000 BOE at the end of
2010 compared to 2,410,000 BOE at the end of 2009, a decrease of approximately
11.5%. Sales of oil and gas products during 2010 decreased by approximately
- 41 -
31,000 BOE from approximately 200,000 BOE in 2009 to approximately 169,000 BOE
in 2010, a decrease of 15.5%. (See Footnote 18 to the Financial Statements).
This resulted in a decrease in the depletion rate factor from 7.662% in 2009 on
an unamortized full cost pot base of $11,368,000 to a depletion rate factor of
7.336% on an unamortized full cost pot base of $12,496,000 in 2010.
ARO expense for 2010 was $48,000 down from $86,000 in 2009; a decrease of
$38,000 or 44%.
General and administrative expenses for 2010 were $3,467,000 compared to
$3,332,000 for 2009, an increase of approximately $135,000 between years or 4%.
This increase is due mainly to payroll and associated employee benefit costs of
approximately $175,000. This was offset by a decrease in SEC related costs of
approximately $40,000 as the Company brought the preparation of its annual
reserve report in house as opposed to having it prepared by an outside third
party.
2009 Compared to 2008
Oil revenue for 2009 was approximately $1,485,000 compared to $2,326,000 for
2008, a decrease of approximately $841,000 or 36.16%. This was due to a
decrease in average oil prices from $71.21 per bbl in 2008 to $56.55 per bbl in
2009, a decrease of $14.66 per bbl or 20.59%. In addition to the decrease in
oil prices, oil sales decreased from approximately 32,650 bbls in 2008 to
approximately 25,875 bbls in 2009, a decrease of 6,775 bbls or 20.75%.
Gas revenue for 2009 was approximately $3,582,000 compared to $10,364,000 for
2008, a decrease of approximately $6,782,000 or 65.44%. This was due primarily
to a drop in average gas prices from $8.41 per Mcf in 2008 to $4.13 per Mcf in
2009, a decrease of $4.28 per MCF or 50.89%. In addition to the decrease in
gas prices, gas sales decreased from approximately 1,232,000 Mcf in 2008 to
approximately 866,000 Mcf in 2009, a decrease of 366,000 Mcf or 29.71%.
Lease operating expenses for 2009 were $1,640,000 compared to $2,552,000 in
2008, a net decrease of $912,000 or 35.74%. Production taxes, gathering,
transportation and marketing expenses for 2009 were approximately $807,000
compared to $969,000 in 2008, a net decrease of $162,000 or 16.75%. For
presentation purposes the Company split out amounts for production taxes,
gathering, transportation and marketing expenses separately from lease
operating expenses. In prior years, these amounts were presented together
under the line item description of lease operating expenses. There have been
no changes to total expenses for the each of the periods shown, and the
presentation for 2008 has been restated to conform to the new presentation.
The Company believes the separate reporting of the amounts gives a better look
at the results of the Company's expenses to operate its leases. Approximately
$413,000 of the decrease in lease operating expenses is due to reduced workover
costs. Another $250,000 of the drop is due to high cost wells being shut in
during 2009. Nearly $100,000 is due to reduced water production on wells which
in 2008 had significant water hauling expenses. The remaining decrease in lease
operating expenses is due to cost containment. The decrease in production
taxes, gathering, transportation and marketing expenses is due to overall
production being down from 2008 to 2009.
- 42 -
Depreciation and amortization for 2009 was $997,000 compared to $1,215,000 for
2008, a decrease of $218,000, or 17.94%. The Company re-evaluated its proved
oil and gas reserves as of December 31, 2009, and decreased its estimated total
proved reserves by approximately 145,000 BOE to 2,410,000 BOE at the end of
2009 compared to 2,555,000 BOE at the end of 2008, a decrease of approximately
5.68%. Sale of oil and gas products during 2009 decreased by approximately
38,000 BOE from approximately 238,000 BOE in 2008 to approximately 200,000 BOE
in 2009, a decrease of 15.97%. (See Footnote 18 to the Financial Statements).
This resulted in a decrease in the depletion rate factor from 8.520% in 2008 to
7.662% in 2009. In addition to the lower depletion rate, the overall decrease
in the amount of amortization was caused by a reduction between years in the
estimated cost basis on which the depletion rate factor was applied. This
decrease was primarily due to a reduction in the estimated future cost of
developing proved undeveloped properties by approximately $1,794,000 in the
2009 reserve report.
General and administrative expenses for 2009 were $3,332,000 compared to
$3,198,000 for 2008, an increase of approximately $134,000 between years or
4.19%. This increase is due mainly to payroll costs and associated employee
benefit costs. Personnel costs and benefits accounted for approximately
$2,970,000 of the total general and administrative costs in 2009 as compared to
$2,649,000 in 2008. A portion of the increase in salary and benefits was due
to personnel added to the Company's payroll as the result of the termination of
the Management Services Contract between the Company and Giant Energy on
September 30, 2008. Effective October 1, 2008, Chris Mazzini, Michelle
Mazzini, President and Vice President of the Company respectively, became
employees of Spindletop Oil & Gas Co. which eliminated the monthly management
fee.
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.
- 43 -
Item 8. Consolidated Financial Statements And
Schedules Index At Page 54
Item 9. Changes In And Disagreements With Accountants On Accounting And
Financial Disclosure
None
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including
our Principal Executive Officer and Principal Financial and Accounting Officer,
we conducted an evaluation of the effectiveness of our disclosure controls and
procedures (as defined in Rule 13a-15(e)) of the Securities Exchange Act of
1934, as amended (the "Exchange Act"), which are designed to ensure that
information required to be disclosed by us in the reports that we file or
submit under the Exchange Act is recorded, processed, summarized and reported
within the time periods specified by the SEC's rules and forms. Disclosure
controls and procedures include, without limitation, controls and procedures
designed to ensure that information required to be disclosed by us in the
reports that we file or submit under the Exchange Act is accumulated and
communicated to our management, including our Principal Executive Officer and
Principal Financial and Accounting Officer, as appropriate to allow timely
decisions regarding required disclosure. Based on this evaluation, our
Principal Executive Officer and Principal Financial and Accounting Officer
concluded that our disclosure controls and procedures were effective as of the
end of the period covered by this report.
Management's Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate
internal control over financial reporting for the Company. Our internal control
over financial reporting is designed to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial
statements in accordance with generally accepted accounting principles. There
are inherent limitations to the effectiveness of any system of internal control
over financial reporting. These limitations include the possibility of human
error, the circumvention of overriding of the system and reasonable resource
constraints. Because of its inherent limitations, our internal control over
financial reporting may not prevent or detect misstatements. Projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions or that the
degree of compliance with policies or procedures may deteriorate.
Management assessed the effectiveness of the Company's internal controls over
financial reporting as of December 31, 2010. In making this assessment,
management used the criteria set forth in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). Based on management's assessments and those criteria,
- 44 -
management has concluded that Company's internal control over financial
reporting was effective as of December 31, 2010.
This annual report does not include an attestation report of the Company's
registered public accounting firm regarding internal control over financial
report. Management's report was not subject to attestation by the Company's
registered public accounting firm pursuant to rules of the Securities and
Exchange Commission that permit the Company to provide only management's report
in this annual report.
Changes in Internal Control over Financial Reporting
In preparation for management's report on internal control over financial
reporting, we documented and tested the design and operating effectiveness of
our internal control over financial reporting. There were no changes in our
internal controls over financial reporting (as such term is defined in Exchange
Act Rule 13a-15(f)) that occurred during the quarter ended December 31, 2010
that have materially affected, or are reasonably likely to materially affect,
our 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 53 Chairman of the Board, Director and
President
Michelle H. Mazzini 49 Director, Vice President, Secretary,
Treasurer
David E. Allard 52 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.
- 45 -
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.
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
telecommunications manufacturing corporation where her practice was broad-
ased. 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-
996) 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.
- 46 -
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 Department. 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
Texas A&M University in 1993. After graduation, he worked for Cox Resources
Corporation, an independent oil and gas company located in Dallas, Texas. Mr.
Chivvis worked in various engineering areas from operations to acquisitions of
oil and gas properties in Texas, Oklahoma, Louisiana, and Arkansas. He 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 35 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
- 47 -
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.
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
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.
- 48 -
Board Meetings and Committees
The Board of Directors met two times in 2010. The Board has established an
audit committee. The Board is small and all members of the Board serve on the
audit committee. The function of the audit committee is to assist the Board in
fulfilling its oversight responsibilities by reviewing the financial
information that will be provided to the shareholders and others, the systems
of internal controls that management and the Board of Directors have
established, and the audit process. The committee is comprised of Mr. David
Allard (Chairman), Mr. Chris Mazzini, and Ms. Michelle Mazzini. The committee
met two times in 2010.
With respect to nominations to the Board, compensation, financial planning,
strategies, and business alternatives, the Company does not have separate
committees as the Board is small and all members of the Board participate in
making recommendations and decisions on these matters.
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 from January 1, 2008 through October 31, 2008. In 2008,
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. Cash compensation including salaries and
bonuses, of $297,038 and $195,400 was paid to Mr. Mazzini in 2010 and 2009
respectively. Cash compensation including salaries and bonuses of $170,180 and
$143,700 was paid to Ms. Mazzini in 2010 and 2009 respectively.
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
- 49 -
Effective December 1, 2010, the Company issued 10,000 shares of restricted
common stock to a key employee pursuant to an employment package. The shares
were valued at $2.25 per share, the believed market value for free trading
shares at the time of issue. The amount was expensed as general and
administrative expense. The shares of common stock were issued out of Treasury
Stock and reduced the amount of the Company's common stock held in Treasury
from 46,668 to 36,668 shares.
Effective December 16, 2009, the Company issued 10,000 shares of restricted
common stock to a key employee pursuant to an employment package. The shares
were valued at $1.65 per share, the believed market value for free trading
shares at the time of issue. The amount was expensed as general and
administrative expense. The shares of common stock were issued out of Treasury
Stock and reduced the amount of the Company's common stock held in Treasury
from 56,668 to 46,668 shares.
Effective April 9, 2009, the Company issued 10,000 shares of restricted common
stock to a key employee pursuant to an employment package. The shares were
valued at $2.00 per share, the believed market value for free trading shares at
the time of issue. The amount was expensed as general and administrative
expense. The shares of common stock were issued out of Treasury Stock and
reduced the amount of the Company's common stock held in Treasury from 66,668
to 56,668 shares.
Compensation of Directors
Directors who are employees of the Company are not currently compensated for
their services on the Board. Mr. Allard was paid a director's fee of $12,500
in 2010, $15,000 in 2009 and $17,500 in 2008 to compensate him for his position
as the Board of Directors' Financial Expert. Mr. Allard receives $2,500 for
each Board of directors meeting during the year.
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 March 31, 2011 with respect to: (i) any person who is known
to the Registrant to be the owner of more than five percent 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
- 50 -
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. 3,000 (2) < 1%
Paul J. Orfalea
Lance W. Helfert
R. Atticus Lowe
1205 Coast Village Road
Montecito, California 93108
Enerjex Resources, Inc.
1600 NE Loop 410, Suite 104
San Antonio, Texas 78209 0 (3) 0%
Nadel and Gussman Energy, LLC 700,000 (3)(4) 9%
Stephen J. Heyman
James F. Adelson
15 East 5th Street, Suite 3200
Tulsa, Oklahoma 74103
-------------------------------
* "Beneficial Ownership" means the sole or shared power to vote, or direct the
voting of, a security or investment power with respect to a security, or any
combination thereof.
** Percentages are base upon 7,640,803 shares of Common Stock outstanding at
March 31, 2011
(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 a Schedule 13D/A filed with the Commission by these persons
for an event occurring December 31, 2010, each of the individually named
persons have shared power to vote or direct a vote as well as shared power to
dispose of or direct the disposition of the aggregate amount of stock owned.
Each person is listed as the beneficial owner of the aggregate amount of these
shares.
- 51 -
(3) According to a Schedule 13G filed with the Commission by Enerjex
Resources, Inc. for an event occurring December 31, 2010, Enerjex Resources,
Inc. owns beneficially 700,000 shares of the Company's Common Stock. According
to a Schedule 13D/A filed by West Coast Opportunity Fund, LLC, West Coast Asset
Management, Inc., R. Atticus Lowe, Lance W. Helfert and Paul J. Orfalea for
event occurring December 31, 2010, such group of "Reporting Persons" for which
West Coast Opportunity Fund, LLC is described as the "Fund" contributed its
interest in 700,000 shares to Enerjex Resources, Inc. in exchange for all
Enerjex Resources, Inc. Common Stock.
(4) According to Schedule 13G filed with the Commission with respect to an
event occurring January 19, 2011, these persons own the number of shares
reported. Such Schedule 13G does not identify any transaction involving the
acquisition of such shares. It is believed the 700,000 shares of the Company's
Common Stock reported as owned by Nadel and Gussman Energy, LLC were acquired
from Enerjex Resources, Inc.
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, its parent
company, Giant Energy Corp. and Giant NRG, LP, although MRO is contemplating
offering its services to unrelated third-parties. The Company benefits by
having immediate access to services.
- 52 -
Certain Business Relationships
------------------------------
The long-term debt, which is secured by the commercial office building, is also
guaranteed individually by Chris G. Mazzini and Michelle H. Mazzini, related
parties.
The management services agreement between Giant and the Company was in effect
from 1999 until September 30, 2008 when it terminated. 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, Giant entered into an Administrative Services Agreement
with the Company whereby Giant pays the Company $250 per month for the Company
providing administrative services to Giant.
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. See also note 6 to the Financial Statements.
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 2010, 2009
and 2008 by accounting firm, Farmer, Fuqua, & Huff, P.C.
Type of Fees 2010 2009 2008
------------------ ------- ------- -------
Audit Fees $41,000 $40,000 $31,000
Audit related fees - - -
Tax fees 4,000 - -
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
- 53 -
approval and pre-approval of audit services and permitted non-audit services.
The Board has the responsibility to engage and terminate Farmer, Fuqua, & Huff,
P.C. independent auditors, to pre-approve their performance of audit services
and permitted non-audit services, to approve all audit and non-audit fees, and
to set guidelines for permitted non-audit services and fees. All the fees for
2010, 2009 and 2008 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.
PART IV
(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 58
Consolidated Balance Sheets 58
Consolidated Statement of Operations 60
Consolidated Statement of Changes in
Stockholders' Equity 61
Consolidated Statements of Cash Flows 62
Notes to Consolidated Financial Statements 64
(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)
- 54 -
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
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 87 of this Report.
(c) The Index to Consolidated Financial Statements and Supplemental Schedules
is included following the signatures, beginning at page 57 of this Report.
- 55 -
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, 2011
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, 2011
Chris Mazzini (Chief Executive
Officer)
/s/ Michelle Mazzini
__________________________________ Vice President, Secretary, April 15, 2011
Michelle Mazzini Treasurer, Director
/s/ David E. Allard
__________________________________ Director April 15, 2011
David E. Allard
/s/ Robert E. Corbin
__________________________________ Controller (Principal April 15, 2011
Robert E. Corbin Financial and Accounting
Officer)
- 56 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
Index to Consolidated Financial Statements and Schedules
Page
Report of Independent Registered Public Accounting Firm 58
Consolidated Balance Sheets - December 31, 2010 and 2009 59
Consolidated Statements of perations for the years
Ended December 31, 2010, 2009 and 2008 61
Consolidated Statements of Changes in Shareholders'
Equity for the years ended December 31, 2010, 2009, and 2008. 62
Consolidated Statements of Cash Flows for the years ended
December 31, 2010, 2009 and 2008 63
Notes to Consolidated Financial Statements 64
Schedules for the years ended December 31, 2010, 2009 and 2008
II - Valuation and Qualifying Accounts 86
III - Real Estate and Accumulated Depreciation 87
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.
- 57 -
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, 2010 and
2009, and the related consolidated statements of operations, shareholders'
equity and cash flows for each of the years in the three-year period ended
December 31, 2010. 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, 2010 and 2009, and the consolidated
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 2010 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, 2010 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, 2011
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31
--------------------------
2010 2009
----------- -----------
ASSETS
Current Assets
Cash and cash equivalents $ 6,244,000 $ 9,153,000
Accounts receivable, trade 1,088,000 873,000
Income tax receivable 446,000 582,000
Other short-term investments 400,000 -
----------- -----------
Total current assets 8,178,000 10,608,000
----------- -----------
Property and Equipment, at cost
Oil and gas properties (full cost method) 17,884,000 15,080,000
Rental equipment 399,000 399,000
Gas gathering systems 145,000 145,000
Other property and equipment 245,000 187,000
----------- -----------
18,673,000 15,811,000
Accumulated depreciation and amortization (8,844,000) (7,904,000)
----------- -----------
Total property and equipment, net 9,829,000 7,907,000
----------- -----------
Real Estate Property, at cost
Land 688,000 688,000
Commercial office building 1,580,000 1,580,000
Accumulated depreciation (501,000) (400,000)
----------- -----------
Total real estate property, net 1,767,000 1,868,000
----------- -----------
Other assets
Other long-term investments 1,000,000 -
Other Assets 3,000 3,000
----------- -----------
Total other assets 1,003,000 3,000
----------- -----------
Total Assets $20,777,000 $20,386,000
=========== ===========
The accompanying notes are an integral part of these statements.
- 59 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - (Continued)
As of December 31
--------------------------
2010 2009
----------- -----------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable, current portion $ 120,000 $ 120,000
Accounts payable and accrued liabilities 2,276,000 2,995,000
Tax savings benefit payable 97,000 97,000
----------- -----------
Total current liabilities 2,493,000 3,212,000
----------- -----------
Non-current Liabilities
Notes payable, long-term portion 840,000 960,000
Asset Retirement Obligation 854,000 762,000
----------- -----------
Total non-current liabilities 1,694,000 1,722,000
----------- -----------
Deferred income tax payable 3,009,000 2,341,000
----------- -----------
Total liabilities 7,196,000 7,275,000
----------- -----------
Shareholders' Equity
Common stock, $.01 par value; 100,000,000
Shares authorized; 7,677,471 shares
issued and 7,640,803 shares outstanding
at December 31, 2010; 7,677,471 shares
issued and 7,630,803 shares outstanding at
December 31, 2009. 77,000 77,000
Additional paid-in capital 919,000 901,000
Treasury Stock at cost (18,000) (23,000)
Retained earnings 12,603,000 12,156,000
----------- -----------
Total shareholders' equity 13,581,000 13,111,000
----------- -----------
Total Liabilities and Shareholders' Equity $20,777,000 $20,386,000
=========== ===========
The accompanying notes are an integral part of these statements.
- 60 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended December 31,
-----------------------------------
2010 2009 2008
----------- ----------- -----------
Revenues
Oil and gas revenue $ 6,302,000 $ 5,067,000 $12,690,000
Revenue from lease operations 319,000 317,000 269,000
Gas gathering, compression and
Equipment rental 179,000 192,000 179,000
Real estate rental income 448,000 503,000 509,000
Interest income 158,000 208,000 285,000
Other 250,000 626,000 132,000
----------- ----------- -----------
Total revenue 7,656,000 6,913,000 14,064,000
----------- ----------- -----------
Expenses
Lease operations 1,901,000 1,640,000 2,552,000
Production taxes, gathering & marketing 712,000 807,000 969,000
Pipeline and rental operations 33,000 34,000 40,000
Real estate operations 246,000 249,000 320,000
Depreciation and amortization 1,042,000 997,000 1,215,000
Accretion of asset retirement obligation 48,000 86,000 38,000
General and administrative 3,467,000 3,332,000 3,198,000
Interest expense 84,000 71,000 112,000
----------- ----------- -----------
Total expenses 7,533,000 7,216,000 8,444,000
----------- ----------- -----------
Income (loss) before income tax 123,000 (303,000) 5,620,000
----------- ----------- -----------
Current tax provision (benefit) (97,000) (226,000) 1,497,000
Deferred tax provision (benefit) (227,000) (116,000) 602,000
----------- ----------- -----------
(324,000) (342,000) 2,099,000
----------- ----------- -----------
Net income $ 447,000 $ 39,000 $ 3,521,000
=========== =========== ===========
Earnings per share of common stock
Basic & Diluted $ 0.06 $ 0.01 $ 0.46
=========== =========== ===========
Weighted Average Shares Outstanding
Basic and Diluted 7,631,652 7,618,940 7,610,803
=========== =========== ===========
The accompanying notes are an integral part of these statements.
- 61 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
Additional Treasury
Common Stock Paid-In Stock Retained
Shares Amount Capital Shares Amount Earnings
--------- -------- ---------- -------- -------- -----------
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
Issuance of 10,000
shares of Common Stock
out of Treasury Stock
as part of an employee
compensation package - - 15,000 (10,000) 5,000 -
Issuance of 10,000
shares of Common Stock
out of Treasury Stock
as part of an employee
compensation package - - 12,000 (10,000) 4,000 -
Net income - - - - - 39,000
--------- -------- ---------- -------- -------- -----------
Balance at
December 31, 2009 7,677,471 $ 77,000 $ 901,000 46,668 $(23,000)$12,156,000
Issuance of 10,000
shares of Common Stock
out of Treasury Stock
as part of an employee
compensation package - - 18,000 (10,000) 5,000 -
Net Income - - - - - 447,000
--------- -------- ---------- -------- -------- -----------
Balance at
December 31, 2010 7,677,471 $ 77,000 $ 919,000 36,668 $(18,000)$12,603,000
========= ======== ========== ======== ======== ===========
The accompanying notes are an integral part of these statements.
- 62 -
SPINDLETOP OIL & GAS CO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31,
-----------------------------------
2010 2009 2008
----------- ----------- -----------
Cash Flows from Operating Activities
Net income $ 447,000 $ 39,000 $ 3,521,000
Reconciliation of net income
to net cash provided by
Operating Activities
Depreciation and amortization 1,042,000 997,000 1,215,000
Accretion of asset retirement
Obligation 48,000 86,000 38,000
Loss on disposal of assets - - 8,000
Non-cash employee compensation 23,000 36,000 -
Changes in accounts receivable (215,000) 637,000 (97,000)
Changes in income tax receivable - (582,000) -
Changes in accounts payable (719,000) (794,000) 1,517,000
Changes in current taxes payable 136,000 (44,000) 35,000
Changes in deferred taxes payable 668,000 (116,000) 602,000
Changes in other short-term investments (400,000) - -
Changes in other long-term investments (1,000,000) - -
Changes in other assets - - (2,000)
----------- ----------- -----------
Net cash provided by operating
activities 30,000 259,000 6,837,000
----------- ----------- -----------
Cash flows from Investing Activities
Capitalized acquisition, exploration
and development costs (2,760,000) (1,437,000) (2,527,000)
Purchase of property and equipment (59,000) (17,000) (8,000)
Capitalized tenant improvements - - (39,000)
----------- ----------- -----------
Net cash used for investing activities
activities (2,819,000) (1,454,000) (2,574,000)
----------- ----------- -----------
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 (decrease)in cash (2,909,000) (1,315,000) 4,143,000
Cash at beginning of period 9,153,000 10,468,000 6,325,000
----------- ----------- -----------
Cash at end of period $ 6,244,000 $ 9,153,000 $10,468,000
=========== =========== ===========
The accompanying notes are an integral part of these statements.
- 63 -
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.
Certain balances for 2008 have been reclassified to conform to the 2010 and
2009 presentations.
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, 2010, 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.
The Company owns land along with a commercial office building which 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:
FASB Accounting Standards Codification
The Company presents its financial statements in accordance with generally
accepted accounting principles in the United States ("GAAP"). In June, 2009,
the Financial Accounting Standards Board ("FASB") completed its accounting
guidance codification project. The FASB Accounting Standards Codification
("ASC") became effective for the Company's financial statements issued
subsequent to June 30, 2009 and is the single source of authoritative
- 64 -
accounting principles recognized by the FASB to be applied to nongovernmental
entities in the preparation of financial statements in conformity with GAAP.
As of the effective date, the Company will no longer refer to the authoritative
guidance dictating its accounting methodologies under the previous accounting
standards hierarchy. Instead, the Company will refer to the ASC as the sole
source of authoritative literature.
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.
Cash and Cash Equivalents
-------------------------
The Company considers all highly liquid instruments with a maturity of three
months or less to be cash equivalents.
Other Investments
-----------------
Other short-term and long-term investments consist of certificates of deposit
with maturities of more than three months. Carrying amounts approximate fair
value.
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. For each cost center, capitalized
costs, less accumulated amortization and related deferred income taxes, shall
not exceed an amount (the cost center ceiling) equal to the sum of:
a) The present value of estimated future net revenues computed by applying
current prices of oil and gas reserves (with consideration of price
changes only to the extent provided by contractual arrangements) to
estimated future production of proved oil and gas reserves as of the
date of the latest balance sheet presented, less estimated future
expenditures (based on current costs) to be incurred in developing and
- 65 -
producing the proved reserves computed using a discount factor of ten
percent and assuming continuation of existing economic conditions; plus
b) The cost of properties not being amortized; plus
c) The lower of cost or estimated fair market value of unproven properties
included in the costs being amortized; less
d) Income tax effects related to differences between the book and tax basis
of the properties.
If unamortized costs capitalized within a cost center, less related deferred
income taxes, exceed the cost center ceiling (as defined), the excess is
charged to expense and separately disclosed during the period in which the
excess occurs. Amounts required to be written off will not be reinstated for
any subsequent increase in the cost center ceiling. Accordingly, no impairment
of oil and gas properties charge was recorded for 2010 or 2009.
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
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
- 66 -
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. ASC Topic 360, "Accounting for the Impairment or Disposal of Long-Lived
Assets", 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 2010
due to impairment of real estate holdings.
Accounting for Asset Retirement Obligations
-------------------------------------------
The Company adopted ASC Topic 410-20, "Accounting for Asset Retirement
Obligations" on December 31, 2005. The adoption of ASC Topic 410-20 resulted
in a cumulative effect adjustment to record a $239,000 increase in the carrying
value of oil and gas properties, and an asset retirement obligation liability
of the same amount. This statement requires the recording of a liability in
the period in which an asset retirement obligation ("ARO") is incurred, in an
amount equal to the discounted estimated fair value of the obligation that is
capitalized. Thereafter, each quarter, this liability is accreted up to the
final retirement cost. The determination of the ARO is based on an estimate of
the future cost to plug and abandon our oil and gas wells. The actual costs
could be higher or lower than current estimates.
The following table reflects the changes of the asset retirement obligations
during the period ending December 31;
2010 2009
------------ ------------
Carrying amount of asset retirement obligation $ 762,000 $ 667,000
Liabilities added 131,000 61,000
Liabilities divested or settled (87,000) (52,000)
Current period accretion expenses 48,000 86,000
------------ ------------
Carrying amount as of December 31, $ 854,000 $ 762,000
============ ============
- 67 -
Revenue Recognition
-------------------
The Company follows the "sales" (takes or cash) method of accounting for oil
and gas revenues. Under this method, the Company recognizes 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 the Company is 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, an interpretation of ASC Topic 740-10, "Accounting for
Uncertainty in Income Taxes" was issued. 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 the interpretation of ASC Topic 740-10
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, 2010.
The Company accounts for income taxes pursuant to ASC Topic 740-10 "Accounting
for Income Taxes" , 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.
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.
- 68 -
Share-Based Payments
--------------------
Effective January 1, 2006, the Company adopted ASC Topic 718-10, "Share-Based
Payment". ASC Topic 718-10 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. ASC Topic 718-10 is effective
for awards granted or modified after the date of adoption and for awards
granted prior to that date that have not vested. ASC Topic 718-10 does not
materially change the Company's existing accounting practices or the amount of
share-based compensation recognized in earnings.
Recently issued accounting pronouncements
-------------------------------------------
FASB Accounting Standards Update ("ASU") 2010-03 was issued in January 2010,
and aligns the current oil and natural gas reserve estimation and disclosure
requirements of ASC Topic 932 with those in the SEC Final Rule Modernization of
Oil and Gas Reporting issued December 31, 2008. Specifically, ASU No. 2010-03
introduces additional terms and re-defines others, (2) expands the definition
of the term oil and gas producing activities, (3) requires a reporting entity
to take into account its equity method investments in determining whether it
engages in significant oil and gas producing activities, (4) requires that an
un-weighted average of prices for the previous 12 months to be used to
determine whether proved reserves are economically producible, and (5) requires
separate disclosure of information about reserve quantities and financial
statement amounts for geographic areas representing 15% or more of proved
reserves. ASU 2010-03 is effective for entities with annual reporting periods
ending on or after December 31, 2009. The Company adopted both the FASB and
SEC rules as of December 31, 2009. The adoption did not have a material impact
on the consolidated financial statements.
In August 2009, the Financial Accounting Standards Board ("FASB") issued ASU
No. 2009-05, Fair Value Measurement and Disclosures: Measuring Liabilities at
Fair Value. ASU 2009-05 provides clarification on measuring liabilities at fair
value when a quoted price in an active market available. The Company adopted
ASU No. 2009-05 (ASC Topic 820-10). The adoption of this statement did not have
an impact on the consolidated financial statements.
The Company adopted FSP SFAS 107-1 and APB 28-1 (incorporated in ASC Topic
825), "Interim Disclosures about Fair Value of Financial Instruments". The
statement increases the frequency of fair value disclosures to a quarterly
nstead of annual basis. The guidance relates to fair value disclosures for any
financial instruments that are not currently reflected on the balance sheet at
fair value. The adoption of this statement did not have a material impact on
the consolidated financial statements.
The Company adopted FSP SFAS 157-4 (incorporated in ASC Topic 820),
"Determining Fair Value When the Volume and Level of Activity for the Asset and
Liability Have Significantly Decreased and Identifying Transactions That Are
Not Orderly". ASC 820 provides guidelines for a broad interpretation of when to
- 69 -
apply market-based fair value measures. The statement reaffirms management's
need to use judgment to determine when a market that was once active has become
inactive and in determining fair values in markets that are no longer active.
The Company adopted ASC Topic 815, "Disclosure about Derivative Instruments and
Hedging Activities" on January 1, 2009. ASC Topic 815 amends and expands the
disclosure requirements for derivatives and hedging activities with the intent
to provide users of financial statements with an enhanced understanding. The
adoption of this statement did not have an impact on the consolidated financial
statements.
The Company adopted ASC Topic 805, "Business Combinations" on January 1, 2009.
The revision broadens the definition of a business combination to include
transactions or other events in which control of one or more business is
obtained. Further, this statement establishes principles and requirements for
how an acquirer recognizes assets acquired, liabilities assumed and any non-
ontrolling interests acquired. The adoption of this statement did not have an
impact on the consolidated financial statements.
In January 2010, FASB issued ASU No. 2010-06, Fair Value Measurements and
Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements.
ASU 2010-06 requires reporting entities to provide information about movements
of assets among Levels 1 and 2 of the three-tier fair value hierarchy
established by ASC Topic 820. The guidance is effective for any fiscal year
that begins after December 15, 2010 and should be used for quarterly and annual
filings. The Company adopted the provisions of ASU 2010-06 on January 1, 2010
and this standard did not impact the Company's consolidated financial
statements.
Subsequent Events
-----------------
The Company has evaluated subsequent events through the issuance date of April
15, 2011.
3. ACCOUNTS RECEIVABLE
December 31,
----------------------------
2010 2009
------------ ------------
Trade $ 127,000 $ 95,000
Accrued receivable 976,000 792,000
------------ ------------
1,103,000 887,000
Less: Allowance for losses (15,000) (14,000)
------------ ------------
$ 1,088,000 $ 873,000
============ ============
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
------------------------------------ 70 -
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,
----------------------------
2010 2009
------------ ------------
Trade payables $ 505,000 $ 1,736,000
Production proceeds payable 1,535,000 976,000
Prepaid drilling costs 236,000 283,000
----------- ------------
$ 2,276,000 $ 2,995,000
=========== ============
5. NOTES PAYABLE
December 31,
----------------------------
2010 2009
------------ ------------
Note payable to a bank with monthly principal
payments of $10,000 plus accrued 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 a commercial office building, plus a
guarantee by certain related parties.
The note matures in November, 2018. $ 960,000 $ 1,080,000
Less current maturities 120,000 120,000
------------ ------------
Total notes payable, long-term portion $ 840,000 $ 960,000
============ ============
Estimated annual maturities for long-term debt are as follows:
2011 120,000
2012 120,000
2013 120,000
2014 120,000
2015 120,000
thereafter 360,000
-----------
$ 960,000
===========
- 71 -
6. RELATED PARTY TRANSACTIONS
From 1999 through September 30, 2008, Giant Energy Corp. ("Giant") charged the
Company a fee pursuant to a management services agreement. Giant is wholly
owned by Chris Mazzini, President of the Company. General and administrative
expense for the year ending December 31, 2008 was $180,000 related to this
agreement. Effective October 1, 2008, this agreement was terminated.
On October 1, 2008, Giant entered into an Administrative Services Agreement
with the Company whereby Giant agreed to pay the Company $250 per month for the
Company providing administrative services to Giant.
The Company also 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. 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.
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. 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 ASC Topic 718-10, "Share-Based
Payment". ASC Topic 718-10 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. ASC Topic 718-10 is effective
for awards granted or modified after the date of adoption and for awards
granted prior to that date that have not vested. ASC Topic 718-10 does not
- 72 -
materially change the Company's existing accounting practices or the amount of
share-based compensation recognized in earnings.
Effective April 9, 2009, the Company issued 10,000 shares of restricted common
stock to a key employee pursuant to an employment package. The shares were
valued at $2.00 per share, the believed market value for free trading shares at
the time of issue. The amount was expensed as general and administrative
expense. The shares of common stock were issued out of Treasury Stock and
reduced the amount of the Company's common stock held in Treasury from 66,668
to 56,668 shares.
Effective December 16, 2009, the Company issued 10,000 shares of restricted
common stock to a key employee pursuant to an employment package. The shares
were valued at $1.65 per share, the believed market value for free trading
shares at the time of issue. The amount was expensed as general and
administrative expense. The shares of common stock were issued out of Treasury
Stock and reduced the amount of the Company's common stock held in Treasury
from 56,668 to 46,668 shares.
Effective December 1, 2010, the Company issued 10,000 shares of restricted
common stock to a key employee pursuant to an employment package. The shares
were valued at $2.25 per share, the believed market value for free trading
shares at the time of issue. The amount was expensed as general and
administrative expense. The shares of common stock were issued out of Treasury
Stock and reduced the amount of the Company's common stock held in Treasury
from 46,668 to 36,668 shares.
8. INCOME TAXES
The Company accounts for income taxes pursuant to ASC Topic 740-10, "Accounting
for Income Taxes". ASC Topic 740-10 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, totaled $ -0-, $ -0-,
and $ -0- in 2010, 2009 and 2008, respectively. As of December 31, 2010 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, 2010, the Company owes $97,000 to
Exploration's unsecured creditors.
In calculating tax savings benefits described above, consideration was given to
the alternative minimum tax, where applicable, and the tax effects of temporary
differences, as shown below:
- 73 -
Income tax differed from the amounts computed by applying an effective United
States federal income tax rate of 34% to pretax income in 2010, 2009 and 2008
as a result of the following:
2010 2009 2008
----------- ---------- ----------
Computed expected tax expense (benefit)$ 42,000 $ (104,000) $1,910,000
Miscellaneous timing differences
related to book and tax depletion
differences and the expensing of
intangible drilling costs (139,000) (122,000) (576,000)
----------- ---------- ----------
Expected Federal
income tax expense(benefit) $ (97,000) $ (226,000) $1,334,000
=========== ========== ==========
Income tax expense (benefit) for the years ended December 31, 2010, 2009 and
2008 consisted of the following:
2010 2009 2008
----------- ---------- ----------
Federal income taxes (benefit) $ (97,000) $ (226,000) $1,334,000
State income taxes - - 163,000
----------- ---------- ----------
Current income tax provision (benefit)$ (97,000) $ (226,000 $1,497,000
=========== ========== ==========
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, 2010 and 2009 consisted of
the following:
December 31,
----------------------------
2010 2009
------------ ------------
Deferred tax assets
Depreciation, depletion and amortization 320,000 422,000
Other, net 16,000 9,000
------------ ------------
Total 336,000 431,000
Deferred tax liabilities
Expired leasehold (231,000) (54,000)
Intangible drilling costs (3,114,000) (2,718,000)
------------ ------------
Net deferred tax liability (3,009,000) (2,341,000)
============ ============
- 74 -
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 $84,000, $71,000, and $79,000 for the years 2010, 2009 and 2008,
respectively. Also included are cash payments for taxes of $-0-, $400,000,
and $1,300,000 in 2010, 2009 and 2008, respectively.
Excluded from the Consolidated Statements of Cash Flows were the effects of
certain non-cash investing and financing activities, as follows:
2010 2009 2008
----------- ----------- -----------
Addition (reduction) of Oil & Gas
Properties by recognition of
Asset Retirement Obligation $ 45,000 8,000 $ 65,000
----------- ----------- -----------
$ 45,000 $ 8,000 $ 65,000
=========== =========== ===========
10. EARNINGS PER SHARE
Earnings per share ("EPS") are calculated in accordance with ASC Topic 260-10,
"Earnings per Share", 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 ASC Topic 260-10 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, 2010 the Company had approximately $2,192,000 in checking
and money market accounts at one bank, and approximately $2,863,000 in a second
bank. The Company also had approximately $2,900,000, including $400,000 of
short-term certificates of deposit and $1,000,000 of long-term certificates of
deposit invested at eight other banking institutions. Cash amounts on deposit
at these institutions exceed current per account FDIC protection limits by
approximately $2,623,000.
Most of the Company's business activity is located in Texas. Accounts
receivable as of December 31, 2010 and 2009 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.
- 75 -
12. FINANCIAL INSTRUMENTS
The estimated fair value of the Company's financial instruments at December 31,
2010 and 2009 follows:
-------- 2010 ------ -------- 2009 -------
Carrying Fair Carrying Fair
Amount Value Amount Value
----------- ----------- ----------- -----------
Cash $ 6,244,000 $ 6,244,000 $ 9,153,000 $ 9,153,000
Short-term certificates 400,000 400,000 - -
Accounts receivable 1,088,000 1,088,000 873,000 873,000
The fair value amounts for each of the financial instruments listed above
approximate carrying amounts due to the short maturities of these instruments.
13. COMMITMENTS AND CONTINGENCIES
In connection with the Plan of Reorganization discussed in Note 1, the Company
agreed to pay, in cash, to Exploration's unsecured creditors, as defined, one-
half of the future reduction of Federal income taxes which were directly
related to any allowed carryovers of Exploration's net operating losses and
investment tax credits existing at the time of the reorganization.
The Company's oil and gas exploration and production activities are subject to
Federal, State and environmental quality and pollution control laws and
regulations. Such regulations restrict emission and discharge of wastes from
wells, may require permits for the drilling of wells, prescribe the spacing of
wells and rate of production, and require prevention and clean-up pollution.
Although the Company has not in the past incurred substantial costs in
complying with such laws and regulations, future environmental restrictions or
requirements may materially increase the Company's capital expenditures, reduce
earnings, and delay or prohibit certain activities.
At December 31, 2010 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 seven, $5,000 single-well bonds totaling $35,000 and three
$10,000 single well bonds with an insurance company, for wells the Company
operates in Alabama. The $5,000 bonds are written for a three year period and
the $10,000 bonds are written for a one year period.
The Company has 11 letters of credit from a bank issued for the benefit of
various state regulatory agencies in Texas, Oklahoma, and Louisiana, ranging in
amounts from $15,000 to $50,000 and totaling $413,000. These letters of credit
have expiration dates that range from January 1, 2011 through March 31, 2014
and are fully secured by funds on deposit with the bank in business money
market accounts.
- 76 -
14. ADDITIONAL OPERATIONS AND BALANCE SHEET INFORMATION
Certain information about the Company's operations for the years ended
December 31, 2010, 2009 and 2008 follows.
Sale of Oil & Gas Properties
In March, 2010, the Company sold its working interest and operations in the
Robertson 20-12 well located in Lamar County, Alabama to an unrelated party
for $5,000 in cash.
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, 2010:
Year Ended December 31, (1)
--------------------------------
Purchaser 2010 2009 2008
----------------------------------------- -------- -------- --------
Enbridge Energy Partners
(formerly Enbridge North Texas) 26% 36% 26%
Crosstex Gulf Coast Mktg 16% 23% 42%
Eastex Crude Company 7% 7% 3%
Shell Trading (US) Company 7% 6% 5%
Kinder Morgan 5% -% -%
Enterprise Crude Oil LLC(Teppco Crude Oil, LP) 5% 4% 2%
Conoco Phillips Company 4% 1% -%
Targa Midstream Service, LIM 3% 3% 6%
Navajo Refining Co. 3% 3% 1%
Genesis 2% 2% 1%
DCP Midstream, LP 2% -% -%
ETC Texas Pipeline 2% 1% 1%
Sunoco Partners Marketing 2% -% -%
Devon Gas Services, LP -% 1% 2%
Gateway Gathering & Marketing -% -% 1%
(1) Percent of Total Oil & Gas Sales
Oil and gas is sold to approximately 102 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 two percent of the Company's oil and gas
revenues during the three years ended December 31, 2010.
The Company currently has no hedged contracts.
- 77 -
Certain revenues, costs and expenses related to the Company's oil and gas
operations are as follows:
Year Ended December 31,
-----------------------------------
2010 2009 2008
----------- ----------- -----------
Capitalized costs relating to oil
and gas producing activities:
Unproved properties $ 2,064,000 $ 1,874,000 $ 1,820,000
Proved properties 15,820,000 13,206,000 11,813,000
----------- ----------- -----------
Total capitalized costs 17,884,000 15,080,000 13,633,000
Accumulated amortization (8,129,000) (7,212,000) (6,340,000)
----------- ----------- -----------
Total capitalized costs, net $ 9,755,000 $ 7,868,000 $ 7,293,000
=========== =========== ===========
Year Ended December 31,
-----------------------------------
2010 2009 2008
----------- ----------- -----------
Costs incurred in oil and gas property
acquisition, exploration and
development:
Acquisition of properties $ 458,000 $ 121,000 $ 28,000
Development costs 2,346,000 1,327,000 2,509,000
----------- ----------- -----------
Total costs incurred $ 2,804,000 $ 1,448,000 $ 2,537,000
=========== =========== ===========
Year Ended December 31,
-----------------------------------
2010 2009 2008
----------- ----------- -----------
Results of Operations from producing
activities:
Sales of oil and gas $ 6,302,000 $ 5,067,000 $12,690,000
----------- ----------- -----------
Production costs 2,613,000 2,447,000 3,521,000
Amortization of oil and gas
Properties 916,000 871,000 1,091,000
----------- ----------- -----------
Total production costs 3,529,000 3,318,000 4,612,000
----------- ----------- -----------
Total net revenue $ 2,773,000 $ 1,749,000 $ 8,078,000
=========== =========== ===========
- 78 -
Year Ended December 31,
-----------------------------------
2010 2009 2008
----------- ----------- -----------
Sales price per equivalent Mcf $ 6.22 $ 4.96 $ 8.89
=========== =========== ===========
Production costs per equivalent Mcf $ 2.58 $ 2.40 $ 2.47
=========== =========== ===========
Amortization per equivalent Mcf $ 0.90 $ 0.85 $ .76
=========== =========== ===========
Year Ended December 31,
-----------------------------------
2010 2009 2008
----------- ----------- -----------
Results of Operations from gas
gathering and equipment rental
activities:
Revenue $ 179,000 $ 192,000 $ 179,000
----------- ----------- -----------
Operating expenses 33,000 34,000 40,000
Depreciation 1,000 7,000 8,000
----------- ----------- -----------
Total costs 34,000 41,000 48,000
----------- ----------- -----------
Total net revenue $ 145,000 $ 151,000 $ 131,000
=========== =========== ===========
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, 2010:
Year Ended December 31,
-----------------------------------
2010 2009 2008
----------- ----------- -----------
Revenues: (3)
Oil and gas exploration, production
and operations $ 6,621,000 $ 5,384,000 $12,959,000
Gas gathering, compression and
equipment rental 179,000 192,000 179,000
Real estate rental 448,000 503,000 509,000
----------- ----------- -----------
$ 7,248,000 $ 6,079,000 $13,647,000
=========== =========== ===========
- 79 -
Depreciation, depletion and
Amortization expense:
Oil and gas exploration, production
and operations $ 940,000 $ 890,000 $ 1,110,000
Gas gathering, compression and
equipment rental 1,000 7,000 8,000
Real estate rental 101,000 100,000 97,000
----------- ----------- -----------
$ 1,042,000 $ 997,000 $ 1,215,000
=========== =========== ===========
Income from operations:
Oil and gas exploration, production
and operations $ 3,020,000 $ 1,961,000 $ 8,240,000
Gas gathering, compression and
equipment rental 145,000 151,000 131,000
Real estate rental 101,000 154,000 142,000
----------- ----------- -----------
3,266,000 2,266,000 8,513,000
Corporate and other (1) (2,819,000) (2,227,000) (4,992,000)
----------- ----------- -----------
Consolidated net income (loss) $ 447,000 $ 39,000 $ 3,521,000
=========== =========== ===========
Identifiable Assets net of DDA:
Oil and gas exploration, production
and operations $ 9,829,000 $ 7,906,000 $ 7,333,000
Gas gathering, compression and
equipment rental - 1,000 7,000
Real estate rental 1,767,000 1,868,000 1,968,000
----------- ----------- -----------
11,596,000 9,775,000 9,308,000
Corporate and other (2) 9,181,000 10,611,000 11,981,000
----------- ----------- -----------
Consolidated total assets $20,777,000 $20,386,000 $21,289,000
=========== =========== ===========
Note (1): Corporate and other includes general and administrative expenses,
other non-operating income and expense and income taxes.
Note (2): Corporate and other includes cash, accounts and notes receivable,
inventory, other property and equipment and intangible assets.
Note (3): All reported revenues are from external customers.
16. SUPPLEMENTARY INCOME STATEMENT INFORMATION
The following items were charged directly to expense:
Year Ended December 31,
-----------------------------------
2010 2009 2008
----------- ----------- -----------
Maintenance and repairs $ 15,000 $ 15,000 $ 21,000
Production taxes 256,000 233,000 337,000
Taxes, other than payroll and
income taxes 4,000 77,000 (13,000)
- 80 -
17. QUARTERLY DATA (UNAUDITED)
The table below reflects selected quarterly information for the years ended
December 31, 2010, 2009 and 2008.
Year Ended December 31, 2010
----------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
---------- ---------- ---------- ----------
Revenue $1,968,000 $1,765,000 $1,831,000 $2,092,000
Expense (1,523,000) (1,631,000) (1,810,000) (2,569,000)
---------- ---------- ---------- ----------
Operating income (loss) 445,000 134,000 21,000 (477,000)
Current tax (provision) benefit (31,000) (63,000) 244,000 (53,000)
Deferred tax (provision) benefit (59,000) 76,000 (39,000) 249,000
---------- ---------- ---------- ----------
Net income (loss) 355,000 147,000 226,000 (281,000)
========== ========== ========== ==========
Earnings (loss) per share
of common stock
Basic and diluted $0.05 $ 0.02 $0.03 ($0.04)
Year Ended December 31, 2009
----------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
---------- ---------- ---------- ----------
Revenue $1,479,000 $1,749,000 $1,390,000 $2,295,000
Expense (1,660,000) (1,750,000) (1,813,000) (1,993,000)
---------- ---------- ---------- ----------
Operating income (loss) (181,000) (1,000) (423,000) 302,000
Current tax (provision) benefit - - 14,000 212,000
Deferred tax (provision) benefit 59,000 1,000 139,000 (83,000)
---------- ---------- ---------- ----------
Net income (loss) (122,000) - (270,000) 431,000
========== ========== ========== ==========
Earnings (loss) per share
of common stock
Basic and diluted ($0.02) $ - ($0.04) $0.07
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)
- 81 -
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)
18. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
The Company's net proved oil and natural gas reserves as of December 31, 2010
and 2009 have been estimated by Company personnel. The Company's net proved
oil and natural gas reserves as of December 31, 2008 were estimated by
Netherland, Sewell & Associates, Inc.
All estimates are in accordance generally accepted petroleum engineering and
evaluation principles and definitions and with guidelines established by the
Securities and Exchange Commission.
Our policies and practices regarding internal control over the estimating of
reserves are structured to objectively and accurately estimate our oil and
natural gas reserve quantities and present values in compliance with the U.S.
Securities and Exchange Commission ("SEC") regulations and accounting
principles generally accepted in the United States of America. We maintain an
internal staff of petroleum engineers and geosciences professionals who work
closely with the accounting and financial departments to insure the integrity,
accuracy and timeliness of data used in the estimation process. The data used
in our reserve estimation process is based on historical results for
production, oil and natural gas prices received, lease operating expenses and
development costs incurred, ownership interest and other required data.
Historical oil and gas prices, lease operating expenses, and ownership
interests are provided by and verified by the Company's accounting department.
The Petroleum Engineer responsible for the supervision and preparation of the
Company's internally generated reserve report has a Bachelor of Science degree
in Petroleum Engineering from a major university and has experience in
preparing economic evaluations and reserve estimates. He meets the
requirements regarding qualifications, objectivity and confidentiality set
forth in the Standards Pertaining to the Engineering and Auditing of Oil and
Gas Reserves Information promulgated by the Society of Petroleum Engineers.
The Company has established a written internal control procedure to verify that
the data entered into our engineering evaluation software is complete and
correct. These internal control procedures establish the source of the data
both internally and externally, the personnel that will collect the data and
testing of the data collected to insure its accuracy. A summary of the
procedures are shown below:
Accordingly, the following reserve estimates were based on existing economic
and operating conditions. Oil and gas prices for 2010 and 2009 were calculated
- 82 -
using a 12-month average price, calculated as the unweighted arithmetic of the
first-day-of-the month price for each month of each year. Oil and gas prices
in effect at December 31, were used for 2008. 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, 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
Sales of reserves in place - -
Acquired properties 16,300 1,810
Extensions and discoveries 25,630 -
Revisions of previous estimates 45,113 (374,211)
Production (25,875) (866,417)
------------ ------------
Balance December 31, 2009 322,880 12,521,130
Sales of reserves in place - (62,930)
Acquired properties 59,580 290,940
Extensions and discoveries 1,570 172,880
Revisions of previous estimates 9,846 (1,475,633)
Production (31,526) (823,957)
------------ ------------
Balance December 31, 2010 362,350 10,622,430
* May be described as a divestiture, not a change in engineering.
Proved Developed Reserves:
--------------------------
Balance December 31, 2008 252,948 10,882,637
Balance December 31, 2009 296,770 10,672,610
Balance December 31, 2010 361,870 8,754,920
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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 for 2010 and 2009 was
computed using a 12-month average price, calculated as the un-weighted
arithmetic average of the first-day-of-the month price for each month of the
year. The future net cash flow for 2008 was calculated using year-end 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
115 operated wells and 113 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.
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Standardized measure of discounted future net cash flows related to proved
reserves:
Year Ended December 31,
--------------------------------------
2010 2009 2008
------------ ------------ ------------
Future production revenue $ 72,465,000 $ 61,140,000 $ 83,207,000
Future development costs (2,187,000) (2,807,000) (4,476,000)
Future production costs (32,386,000) (23,501,000) (29,657,000)
------------ ------------ ------------
Future net cash flow before
Federal income tax 37,892,000 34,832,000 49,074,000
Future income taxes (10,610,000) (9,753,000) (13,741,000)
------------ ------------ ------------
Future net cash flows 27,282,000 25,079,000 35,333,000
Effect of 10% annual discounting ( 8,577,000) (8,969,000) (13,072,000)
------------ ------------ ------------
Standardized measure of
Discounted net cash flows $ 18,705,000 $ 16,110,000 $ 22,261,000
============ ============ ============
Changes in the standardized measure of discounted future net cash flows:
Amounts for 2009 and 2008 are restated from previously issued report to more
closely align with SEC reporting rules.
Year Ended December 31,
--------------------------------------
2010 2009 2008
------------ ------------ ------------
Beginning of the year $ 16,110,000 $ 22,261,000 $ 42,214,000
Sales of Oil and gas, net of
production costs (3,510,000) (2,493,000) (8,724,000)
Net changes in prices and
Production costs 3,713,000 (7,333,000) (19,493,000)
Extensions, discoveries, additions
Less related costs 377,000 256,000 305,000
Development costs incurred 1,936,000 1,263,000 2,387,000
Net changes in future
development cost (581,000) (1,494,000) (1,173,000)
Revisions of previous
quantity estimates (2,131,000) (172,000) 347,000
Net change in purchase and sales
Of minerals in place 1,318,000 168,000 -
Accretion of discount 1,611,000 2,226,000 4,221,000
Net change in income taxes 152,000 1,596,000 1,971,000
Other (290,000) (168,000) 206,000
------------ ------------ ------------
End of year $ 18,705,000 $ 16,110,000 $ 22,261,000
============ ============ ============
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SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2010, 2009, AND 2008
SCHEDULE II
Beginning Costs & Ending
Description Balance Expenses Deductions Balance
----------------------------- ----------- ----------- ----------- -----------
Allowance for
doubtful Accounts
December 31, 2008 $ 14,000 $ - $ - $ 14,000
========== ========== ========== ==========
December 31, 2009 $ 14,000 $ - $ - $ 14,000
========== ========== ========== ==========
December 31, 2010 $ 14,000 $ 24,000 $ 23,000 $ 15,000
========== ========== ========== ==========
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SCHEDULE III
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
REAL ESTATE AND ACCUMULATED DEPRECIATION
Initial Cost to Corporation Total Cost
----------------------------------------------------------------- Subsequent
Description Encumbrances Land Buildings To Acquist'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 $ 501,000 (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, 2010 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
Depreciation expense 100,000
------------ ------------
Balance, December 31, 2009 $ 2,268,000 $ 400,000
- 87 -
Depreciation expense 101,000
------------ ------------
Balance, December 31, 2010 $ 2,268,000 $ 501,000
============ ============
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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
- 89 -
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.
- 90 -
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
-91-
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, 2011
/s/ Chris G. Mazzini
CHRIS G. MAZZINI
Principal Executive Officer
-92-
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
-93-
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, 2011
/s/ Robert E. Corbin
ROBERT E. CORBIN
Principal Financial and
Accounting Officer
-94-
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, 2010 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, 2011
/s/ Chris G. Mazzini
CHRIS G. MAZZINI
Principal Executive Officer
/s/ Robert E. Corbin
ROBERT E. CORBIN
Principal Financial and
Accounting Officer
- 95 -