UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.WASHINGTON, DC 20549
FORM 10-K
(Mark One)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 5(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2006
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2007
or
[ ] TRANSITION REPORT PURSUANT OT SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File NumberNo. 000-18774
SPINDLEOTPSPINDLETOP OIL & GAS CO.
(Exact name of registrant as specified in its charter)
Texas 75-2063001
(State or other jurisdiction IRS(IRS Employer
of Incorporationincorporation or organizationorganization) Identification NumberNo.)
12850 Spurling Rd., Suite 200, Dallas, TX 75230
(Address of principal executive office)offices) (Zip Code)
(972) 644-2581
(Registrant's Telephone Number,telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act
NONEAct:
Title of Each Class Name of each exchange on which registered
None N/A
Securities registered pursuant to Section 12(g) of the ActAct:
Common Stock, $0.01 par value
Indicate by check mark if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act. Yes [ ] No [ X ]
Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Act. Yes [ X ] No [ 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
registrantCompany was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [ X ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K (Sec.(Sec 229.405 of this chapter) is not contained herein, and
will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of thisthe
Form 10-K or any amendment to this Form 10-K. [ X ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [ ] No [ X ]
Indicate by check mark whether the registrant is a large accelerated filer,
an accelerated filer or a non-accelerated filer.filer or a smaller reporting company
See definitions of "accelerated filer and large"large accelerated filer", "accelerated filer", and "smaller
reporting company" in Rule 12b-2 of the Exchange Act (check(Check one).:
Large accelerated filer [ ] Accelerated filer [ ]
Non-accelerated filer [X][ ] 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]
The[ X ]
State the aggregate market value of the shares of voting and non-voting common equity
held by non-affiliates of the Registrant, computed by reference to the
closing price at which the common
equity was last sold, which wasor the salesaverage bid and asked price of the Common Stock on the (OTC) Stock Exchangesuch common equity,
as of June 30, 2006 (thethe last business day of the Registrant'sregistrant's most recently completed second
fiscal quarter) was $8,296,799quarter. $9,351,430
$9,351,430 based upon a total of 1,468,4601,700,260 shares held as of June 30, 200629, 2007 by
persons believed to be non-affiliates of the Registrant. TheRegistrant; 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 sixty60 days of this filing, would yield a different value.
AsAPPLICABLE 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 March 31, 2007, there were 7,595,803the 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, stock outstanding.as of the latest practicable date.
Common Stock, $0.01 par value 7,610,803
(Class) (Outstanding at April 14, 2008)
DOCUMENTS INCORPORATED BY REFERENCE
NONENone
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PART I
Item 1. Description Ofof Business
GENERAL
Spindletop Oil & Gas Co. is an independent oil and gas company engaged in the
exploration, development and production of oil and natural gas; the rental of
oilfield equipment; and through one of its subsidiaries, the gathering and
marketing of natural gas. The terms the "Company", "We", "Us" or Spindletop
are used interchangeably herein to refer to Spindletop Oil & Gas Co. and its
wholly owned subsidiaries, Prairie Pipeline Co. ("PPC") and Spindletop Drilling
Company ("SDC").
The Company has focused its oil and gas operations principally in Texas,
although we operate properties in six states including: Texas, Oklahoma, New
Mexico, Louisiana, Alabama and Arkansas. We operate a majority of our projects
through the drilling and production phases. Our staff has a great deal of
experience in the operations arena. We have traditionally leveraged the risks
associated with drilling by obtaining industry partners to share in the costs
of drilling. However, we typically retain a controlling interest in the
prospects we drill.
In addition, the Company, through PPC, owns approximately 26.1 miles of
pipelines located in Texas, which are used for the gathering of natural gas.
These gathering lines are located in the Fort Worth Basin and are being
utilized to transport the Company's natural gas as well as natural gas produced
by third parties.
Website Access to Our Reports
- -----------------------------
We make available free of charge through our website, www.spindletopoil.com ,
our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports
on form 8-K, and all amendments to those reports as soon as reasonably
practicable after such material is electronically filed with the Securities and
Exchange Commission. Information on our website is not a part of this report.
Operating Approach
- ------------------
We believe that a major attribute of the Company is its long history with, and
extensive knowledge of, the Fort Worth Basin of Texas. Our technical staff has
an average of over 2728 years oil and gas experience, most of it in the Fort
Worth Basin.
One of our strengths has been the ability of the Company to look at cost
effective ways to grow our production. We have traditionally increased our
reserve base in one of two ways. Initially, in the 1970's and 1980's, the
Company obtained its production through an exploration and development drilling
program focused principally in Texas. Today, the Company has retained many of
these wells as producing properties and holds a large amount of acreage by
production.
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From the 1990's through 2003, the Company took advantage of the lower product
prices by cost effectively adding to its reserve base through value-priced
acquisitions. We found that through selective purchases we could make
producing property acquisitions that were more cost effective than drilling.
During this time period, the Company acquired a large number of operated and
non-operated oil and gas properties in various states.
From 2003 to the present, we have returned our focus to a strategy of
development drilling. With higher product prices, we believe that it has been
more cost effective to drill on the Company's leasehold acreage rather than to
purchase production with escalated acquisition costs.
Our strategic focus in our drilling program is currently on the Barnett Shale
play located in the Fort Worth Basin of North Texas. The organic rich Barnett
Shale has been the source rock for the producing formations in the Fort Worth
Basin. As an unconventional fractured reservoir, the Barnett Shale itself has
become an attractive target due to technological advances in the drilling and
stimulation of tight gas formations. This technology driven play has the
potential of long life wells with the opportunity for multiple re-stimulations
which can significantly increase the commercial life of Barnett Shale wells.
The Company entered into a joint Barnett Shale horizontal drilling development
program with an unrelated company during the third quarter of 2006. Under the
terms of the Agreement, two Barnett Shale horizontal wells were drilled on the
Company's acreage of during the fourth quarter of 2006. The Hutcheson # 2H and
# 3H wells, located in the northeast quarter of Parker County, Texas were
completed during the first quarter of 2007. The Hutcheson # 2H well was placed
in production on February 20, 2007 at a rate of 1,174 thousand cubic feet of
gas per day("MCFG/D"). The Hutcheson # 3H well was placed in production on
March 15, 2007 at a rate of 1,057 MCFG/D. The Company holds a 50% working
interest in the wells.
During the first quarter of 2007, the third Barnett Shale horizontal well was
drilled on the Company's acreage under the terms of the Agreement. The
Harms # 4H well, located in the northeast quarter of Parker County, Texas was
drilled to a measured depth of 9,526 ft. and cased. This well is currently
awaiting completion. The Company holds a 50% working interest in the well.
It is anticipated that seven additional Barnett Shale horizontal wells will be
drilled during 2007 under the Agreement.
Strategic Business Plans
- ------------------------
One of our key strategies is to enhance shareholder value through
implementation of plans for controlled growth and development. The Company's
long-term focus is to grow its oil and gas production through a strategic
combination of selected property acquisitions, to the extent feasible, and an
exploration and development program primarily based on developing its leasehold
acreage. Additionally, the Company will continue to rework existing wells to
increase production and reserves.
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The Company's primary area of operation has been and will continue to be in
Texas with an emphasis in the geological province known as the Ft.Fort Worth
Basin. The Company is beginning to drill and develop its Fort Worth Basin
producing properties into the Barnett Shale formation. We want to capitalize
on our strengths which include a goodan extensive knowledge of the Fort Worth Basin,
experience in operations in this geographic area, development of lease
holdings, and utilization of existing infrastructure to minimize costs.
The Company will continue to generate and evaluate prospects using its own
technical staff. The Company intends to fund operations primarily from cash
flow generated by operations.
The Company will attempt to expand its pipeline system. Expansion will be
dependent upon success in its exploration programs, since the majority of its
existing pipelines are connected to wells that the Company operates.
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Significant Project Areas
- -------------------------The Company owns various interests in wells located in 16 states and the
Company's operations are currently located in six of those states which include
Alabama, Arkansas, Louisiana, Oklahoma, New Mexico and Texas.
The Company has operations and well interestsapproximately 21,969 gross acres under lease in 16 states; however, thesix states.
The majority of the leases are held by production. A breakout of the Company's
leasehold acreage by geographic area is as follows:
North Texas Including
the Fort Worth Basin 9,857 gross acres 44.87 %
Arkansas 2,936 gross acres 13.36 %
East Texas 2,592 gross acres 11.80 %
Gulf Coast Texas 2,341 gross acres 10.65 %
Alabama 1,480 gross acres 6.74 %
West Texas 748 gross acres 3.41 %
Louisiana 723 gross acres 3.29 %
Texas Panhandle 640 gross acres 2.91 %
New Mexico 415 gross acres 1.89 %
Oklahoma 237 gross acres 1.08 %
Total 21,969 gross acres 100.00 %
The majority of our wells are located within a two-hour drive from our
corporate headquarters, located in Dallas, Texas which provides for more
effective oversight of operations.
The majority of the Company's net reserves (86.40%(76.27%) are located in Texas.
A breakout of the Company's most significant reserves by geographic area is
as follows:
North Texas Including
the Fort Worth Basin Texas 1,817,5131,926,404 BOE 70.2470.32 %
West Texas 186,448233,909 BOE 7.218.53 %
East Texas 137,475166,239 BOE 5.316.07 %
Oklahoma 112,507107,448 BOE 4.353.92 %
Gulf Coast Texas 65,11972,348 BOE 2.522.64 %
Louisiana 60,23157,319 BOE 2.332.09 %
Alabama 56,87453,383 BOE 2.201.95 %
New Mexico 44,12648,169 BOE 1.711.76 %
Arkansas 35,90838,979 BOE 1.391.42 %
Panhandle Texas 29,09618,316 BOE 1.12 %
Kansas 22,228 BOE 0.860.67 %
North Dakota 9,0778,406 BOE 0.350.31 %
Wyoming 6,3304,990 BOE 0.240.18 %
Montana 4,2073,430 BOE 0.160.13 %
Michigan 477232 BOE 0.020.01 %
Total 2,587,6162,739,572 BOE 100.00 %
The majority of our wells are located within a two-hour drive from our
corporate headquarters, which provides for more effective oversight of
operations.- 5 -
Fort Worth Basin TexasBasin/Bend ArchProvince
The Fort Worth Basin has been the focal point of the Company since its
inception. Our technical personnel have an average of 2728 years of exploration,
drilling and production experience in the Basin. We also have an extensive
collection of geologic and engineering data.
- 5 -
The Fort Worth Basin is a gas prone region with multiple pay zones ranging in
depth from 1000-9000 feet. The basin is currently experiencing a drilling boom
due to increased natural gas prices and advances in fracturing technology that
have unlocked natural gas reserves from the Barnett Shale Formation.
The Barnett Shale is a thick blanket type formation covering the entire basin.
The natural gas reserves in place are significant; however, due to the
extremely low permeability of the shale, it has been technically difficult to
recover these reserves. Recent advances in hydraulic fracturing and horizontal
well technology have enabled economic recovery of natural gas reserves in the
Fort Worth Basin.
According to the U.S. Geological Survey, it is estimated that there is
approximately 26.7 trillion cubic feet (TCF) of undiscovered natural gas, 98.5
million barrels of undiscovered oil, and 1.1 billion barrels of undiscovered
natural gas liquids (condensate) in the Bend Arch-Fort Worth Basin Province and
more than 98 percent, or 26.2 TCF, of the undiscovered natural gas is located
in the Barnett Shale.
The Company has large lease-holdings9,204 gross acres under lease in the Bend Arch and Fort Worth
Basin the majority of it held by production from shallower producing zones.
We are planning to drill new into the Barnett Shale Formation on some of these
leases. We are also actively seeking and acquiring new leases in the Barnett
Shale play.trend.
Joint Drilling Development of North Texas Barnett Shale Leasehold
The Company along with Giant Energy Corp. (a related entity), entered into a
joint Barnett Shale horizontal drilling development program with an unrelated
company ("the Agreement") during the third quarter of 2006. Under the terms
of the Agreement, two Barnett Shale horizontal wells were drilled on the
Company's Springtown Block located in the northeast quarter of Parker County,
Texas during the fourth quarter of 2006. The Hutcheson # 2H and # 3H wells
were drilled off the same surface site and were drilled to a total measured
depth of 9,750 ft. and 8,351 ft., respectively. Both wells were fraced and
completed during the first quarter of 2007. The Hutcheson # 2H well was placed
in production on February 21, 2007 at a rate of 1,177 Mcf of gas per day. The
Hutcheson # 3H well was placed in production on March 15, 2007 at a rate of
1,057 Mcf gas per day. These two Barnett Shale wells drilled on the Company's
Springtown Block have produced 0.162 Bcf of gas through March 31, 2008 and have
a current average combined flow rate of 230 Mcf of gas per day.
During the second quarter of 2007, the third Barnett Shale horizontal well was
drilled on the Company's acreage under the terms of the Agreement. The Harms
#4H well is located in the northeast quarter of Parker County, Texas on the
Company's Springtown block. It was drilled to a total measured depth of 9,526
ft. During the third quarter of 2007, the well was fraced and flowed back with
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gas volumes in excess of 1,000 Mcf of gas per day, however, the gas production
was erratic because of downhole fluid loading. The well was subsequently
placed on a gas lift system but it was later removed after it was determined
that the well could not be produced economically due to the large volume of
salt water produced with the natural gas. It was concluded that frac
stimulation reached the underlying Ellenburger Formation and that the large
amount of salt water was coming from that formation. On November 1, 2007, the
Company acquired the remainder of the working interest and it now owns 100%
working interest in this well. The Company believes that the well could
produce gas in commercial quantities if the salt water was re-injected in the
ground rather than trucked away for disposal. The Company is looking at the
feasibility of converting an existing wellbore on the lease to a salt water
disposal well. The Harms #4H well is currently shut in.
During the second quarter of 2007, Wilson-Harris #2H well located on our
Cresson Block in the southeast quarter of Parker County, Texas, was drilled to
a measured depth of 9,150 ft. The well was fraced and completed in the Barnett
Shale and was placed in production in September 2007. The daily gas production
peaked at 4,070 Mcf gas per day after continuing to clean up for several days.
During the third quarter of 2007, three other wells were drilled on our Cresson
Block in the southeast quarter of Parker County, Texas. The Wilson-Harris #3H
well was drilled to a measured depth of 8,755 ft. The well was fraced and
completed in the Barnett Shale and was placed in production in September 20,
2007. The daily gas production peaked at 3,977 Mcf gas per day after
continuing to clean up for several days. The Wilson-Harris #4H well was
drilled to a measured depth of 7,040 ft. The well was fraced and completed in
the Barnett Shale and was placed in production in September 27, 2007. The
daily gas production peaked at 2,722 Mcf gas per day after continuing to clean
up for several days. The Fitzwilliam #2H well was drilled to a measured depth
of 9,350 ft. The well was fraced and completed in the Barnett Shale and was
placed in production in October 2007. The daily gas production peaked at
1,553 Mcf gas per day after continuing to clean up for several days. The
Company holds a 50% working interest in all three wells. These four Barnett
Shale wells drilled on the Company's Cresson Block have produced 0.883 Bcf of
gas and 1,331 bbls of oil through March 31, 2008 and have an average current
combined flow rate of 3,560 Mcf of gas per day and 7 bbls of oil per day.
During the fourth quarter of 2007, two other wells were drilled, the Buxton
G.U. #1H well, located on our Weatherford, W block and the Fuller G.U. #1H well
located on our Weatherford, SW block. Both wells are located in the southwest
quarter of Parker County, Texas. The Buxton #1H well was drilled to a total
measured depth of 8,850 ft. and the Fuller G.U. #1H was drilled to a measured
depth of 9,076 ft. Both wells were sand fraced in February 2008 and are
currently being flowed back. The flow back frac water is monitored and the high
chlorides measured, infer that the frac stimulations of both wells may have
penetrated into the underlying Ellenburger Formation. The flow back of both
wells will continue until it is determined whether or not these wells will be
able to produce gas in commercial quantities. The Company holds a 50% working
interest in both of these wells.
In the first quarter of 2008, the McKeon G.U. #1H well, located on our Peaster,
SW block in the northwest quarter of Parker County, Texas, was spud and is
currently being drilled. The Company holds a 50% working interest in this well.
- 7 -
Additionally, two wells were drilled on leasehold acreage owned by Giant Energy
Corp. under the terms of the Agreement in 2007. The Company anticipates that
up to eight additional Barnett Shale horizontal wells will be drilled during
the next twelve months under the Agreement. To date eleven (11) wells have
been drilled and one (1) well is currently being drilled. Nine (9) of those
wells were drilled on the Company's leasehold and two (2) wells were drilled on
the Giant Energy leasehold. It is anticipated that 8 additional wells may be
drilled within the next twelve months. Under the terms of the Agreement, the
unrelated company acting as Operator of the new wells has full control of the
selection of the drillsites and the drilling and completion phases of the new
wells including selecting the landing points of the horizontal wells and the
completion and fracing techniques utilized for these wells. The Company will
obtain operations of the wells within ninety days of the date of first sales
and will then operate them thereafter.
Company's Development of North Texas Barnett Shale Leasehold outside of the
Joint Drilling Development Project
The Company drilled two vertical Barnett Shale wells in Denton County, Texas
during the last quarter of 2007.2006. The Olex US # 7 well reached its total depth
of 8,803 ft. on December 6, 200606 and production casing was set to the bottom.
The Olex US # 6 well reached its total depth of 8,870 ft. on December 30, 2006
and was production casing was also set to the bottom.
The Olex USU.S. # 7 well was drilled to a depth
of 8,840 ft. and completed during the first quarter of 2007 and was placed into production in March 2007 at a rate
of 1,253 MCFG/DMcf of gas per day and 15 barrelsbbls of oil per day
(BO/D) from the Upper and Lower
Barnett Shale. The Olex USU.S. # 6 well is
currently beingwas drilled to a depth of 8,870 ft. and
completed and placed into production in April 2007 at an initial rate of 1,769
Mcf gas per day and 35 bbls of oil per day from the Upper and Lower Barnett
Shale. The company owns a 53% and 52.5% working interest in the Olex U.S. #6
and #7 wells, respectively. The Olex U.S. lease is surrounded by productive
Barnett Shale gas wells and with existing field spacing rules, an additional 27
vertical wells could be drilled on this lease. Joint Drilling Development of North Texas Barnett Shale Leasehold.
The Company entered into a joint Barnett Shale horizontal drilling development
program with an unrelated company during the third quarter of 2006. Under the
terms of the Agreement,These two Barnett Shale horizontal wells were
drilled on the Company's acreageSpringtown Krum Block have produced 0.306 Bcf of duringgas
and 6,978 bbls of oil through March 31, 2008 and have a current average
combined flow rate of 550 Mcf of gas per day and 6 bbls of oil per day.
In addition to the fourth quarter of 2006. The Hutcheson # 2H and
# 3H wells, locatedCompany's Barnett Shale development drilling activities,
the Company has worked on or participate in the northeast quarterfollowing projects:
West Texas
SDC recompleted one of Parker County, Texas were
completed duringits existing wells in Ward Co., TX on its Pyote Block.
The company deepened its University "17-40" well #1 to a depth of 13,926 ft.
The Atoka Formation was perforated from 13,622 ft to13,739 ft. and the first quarter of 2007. The Hutcheson # 2H well was
placed into production in production on February 20,November 2007 producing dry gas. As of March 2008,
the well is flowing at aan average rate of 1,174 MCFG/D. The Hutcheson
# 3H well was placed in production on March 15, 20/07 at a rate625 Mcf of 1,057
MCFG/D. The Company holds a 50%gas per day from the
Atoka. SDC owns 75% working interest in the wells.
During the first quarter of 2007, the third Barnett Shale horizontal well was
drilled on the Company's acreage under the terms of the Agreement. The
Harms # 4H well, located in the northeast quarter of Parker County,this well.
East Texas was
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drilled to a measured depth of 9,526 ft. and cased. This well is currently
awaiting completion. The Company holds a 50% working interest in the well.
It is anticipated that seven additional Barnett Shale horizontal wells will be
drilled during 2007 under the Agreement.
Other than the Barnett Shale, the Company has other opportunities to optimize
existing natural gas production.
Arkansas
The Company participated during 2006 in the drilling of three development
wells in the Arkoma Basin of Arkansas. Two were completed as gas wells
(Marshall #9 and Paul X #5) and one was plugged (Paul X #4). The Marshall #9
well went online September 27, 2006 producing at a rate of 468 MCFG/D.
The Paul X #5 well went online July 7, 2006 producing at a rate of 1,339 MCFG/D
Montana
The Company has participated in the drilling and completion of one 2,000six 10,300 ft.
development wells in the Blocker (Cotton Valley) field of Harrison County,
Texas during 2007. The Lenora Allen Gas Unit #3, #4, #5, #6, #7 and #8 were
all completed as gas wells from the Cotton Valley Formation. The Company holds
a 2.6% working interest in each well.
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Oklahoma
SDC participated in the drilling of a well in the Bowdoin gas field located in Phillips County,
Montana.
Texas
A companyRoger Mills Co., Oklahoma. The
Chamberlain #5-2 well was drilled to which we granted a farm-out on a lease in Bee County, Texas, has
drilleddepth 13,350 ft. and was cased and
completed a secondin the Cherokee/Redfork Formation. The well on this lease duringhad an initial potential
of 1,751 Mcfgpd and 7 bbls of oil per day. The well was placed into production
in the first quarter of 2006. The Spindletop #2 well went into production at2007. SDC owns a rate of 178 MCFG/D and
22 BO/D during the first quarter of 2006 from a sand at 9,060 ft. The Company
has retained a 5.625% overriding royalty0.00628 % working interest in this
well. In 2006,SDC has elected to participate in a company torecently proposed offset well, the
Chamberlain #6-2 well which we granted a farm out on a leaseis currently being cased.
The Company participated in Ochiltree
County, Texas has drilledthe drilling of two wells on this leasein Canadian County,
Oklahoma during 2007. The Virginia #1-30 well drilled to a total depth of
11,325 ft. The well was completed in the Mississippian, Hunton, Viola and
they are both currently
producing gas. The Pope 140 #3Simpson with an initial potential of 1,429 Mcfgpd and Pope 140 #4 wells were both18 bbls of oil per day
and was placed into production in Januarythe third quarter of 2007. The average daily production forsecond well,
the first monthBetty #1-30 was 59 MCFG/D from the Oswego and 400 MCFG/D from the Missippian Chester,
respectively.drilled to a total depth of 11,475 ft. The Company has retained a 12.5% overriding royalty interest in
these wells
A company to which we granted a farm out on a lease in Parker County, Texas
drilled a well on this lease during the last quarter of 2005 . The Koonsman
#1H well was
completed in the Mississippian, Hunton and Viola and had an initial potential
of 1,234 Mcfgpd and 18 bbls of oil per day and was placed into production
during the first quarter of 2006. The well had an average daily sales volume of 156 MCFG/D for the first
month.2008. The Company retainedowns a 5.00% overriding royalty2.2 % working interest
in this well.
Oklahoma
The Company participated in the drilling of the Dahlenburg 1-34 well located in
Caddo Co., OK, to approximately 12,950 feet to test the Springer Formation.
The Dahlenburg 1-34 well was spud on October 4, 2006 and the date of first
production was February 23, 2007.
The Company participated in the drilling of the Creach #4-2 well, a 13,300 ft.
Redfork well in Roger Mills, Co., OK. The well was completed and placed into
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production at a rate of 1,242 MCFG/D and 5 BO/D during the second quarter of
2006.
The Company also participated in the drilling of two development Hoxbar wells
in the Elk City Unit located in Beckham Co., OK. Both wells were completed
during the fourth quarter of 2006.
The Company participated in the drilling of a Chester well in Beaver Co., OK.
The Miller #2-3 well was drilled and cased in the fourth quarter of 2006 and
placed into production in the first quarter of 2007.both wells.
Oil and Natural Gas Reserves
- ----------------------------
The net crude oil and gas reserves of the Company as of December 31, 20062007 were
483,623345,154 barrels of oil and condensate and 14,781,813 MCF (thousand14.367 BCFG (billion cubic feet) of
natural gas. Based on SEC guidelines, the reserves were classified as follows:
Proved Developed Producing 290,905292,548 BO and 5.310.205 BCFG
Proved Developed Non-Producing 49,96541,665 BO and 2.00.741 BCFG
Proved Undeveloped 15,75210,941 BO and 6.03.419 BCFG
Total Proved Reserves 356,622345,154 BO and 13.414.367 BCFG
Only reserves that fell within the Proved classification were considered.
Other categories such as Probable or Possible Reserves were not considered.
No value was given to the potential future development of behind pipe reserves,
untested fault blocks, or the potential for deeper reservoirs (other than
Barnett Shale proved undeveloped reserves directly offset by producing wells)
underlying the Company's properties. Shut-in uneconomic wells and insignificant
non-operated interests were excluded.
On a barrel of oil equivalent basis (6MCF/BOE), the net reserves are
Natural Gas Reserves 2,230,9942,394,461 BOE 86%87%
Oil Reserves 356,622345,154 BOE 14%13%
Total Reserves 2,587,6162,739,615 BOE 100%
Proved Developed Producing 1,177,6001,993,420 BOE 46%73%
Proved Developed Non-Producing 388,688165,373 BOE 15%6%
Proved Undeveloped 1,021,328580,822 BOE 39%21%
Total Proved Reserves 2,587,6162,739,615 BOE 100%
- 9 -
The Company has operational control over the majority of these reserves and can
therefore to a large extent control the timing of development and production.
The Company's Operated Wells 2,363,6322,544,536 BOE 91%93%
Non Operated Wells 223,984195,079 BOE 9%7%
Total 2,587,6162,739,615 BOE 100%
Financial Information Relating to Industry Segments
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The Company has three identifiable business segments: exploration, development
and production of oil and natural gas, gas gathering, and commercial real
- 8 -
estate investment. Footnote 15 to the Consolidated Financial Statements filed
herein sets forth the relevant information regarding revenues, income from
operations and identifiable assets for these segments.
Narrative Description of Business
- ---------------------------------
The Company is engaged in the exploration, development and production of oil
and natural gas, and the gathering and marketing of natural gas. The Company
is also engaged in commercial real estate leasing through the acquisition and
partial occupancy of its corporate headquarters office building.
Principal Products, Distribution and Availability
The principal products marketed by the Company are crude oil and natural gas
which are sold to major oil and gas companies, brokers, pipelines and
distributors, and oil and gas properties which are acquired and sold to oil
and gas development entities. Reserves of oil and gas are depleted upon
extraction, and the Company is in competition with other entities for the
discovery of new prospects.
The Company is also engaged in the gathering and marketing of natural gas
through its subsidiary PPC, which owns 26.1 miles of pipelines and currently
gathers approximately 714 MCF1,112 Mcf of gas per day. Natural gas is gathered for a
fee. Substantially all of the gas gathered by the Company is gas produced
from wells that the Company operates and in which it owns a working interest.
In December, 2004, the Company purchased land and a two story commercial office
building in Dallas, Texas, which it has moved into and uses as its principal
headquarters office. The Company leases the remainder of the building to non-
related third party commercial tenants at prevailing market rates.
Patents, Licenses and Franchises
Oil and gas leases of the Company are obtained from the owner of the mineral
estate. The leases are generally for a primary term of 1 to 5 years, and in
some instances as long as 10 years, with the provision that such leases shall
be extended into a secondary term and will continue during such secondary term
as long as oil and gas are produced in commercial quantities or other
operations are conducted on such leases as provided by the terms of the leases.
It is generally required that a delay rental be paid on an annual basis during
- 10 -
the primary term of the lease unless the lease is producing. Delay rentals are
normally $1.00 to $5.00$25.00 per net mineral acre.
The Company currently holds interests in producing and non-producing oil and
gas leases. The existence of the oil and gas leases and the terms of the oil
and gas leases are important to the business of the Company because future
additions to reserves will come from oil and gas leases currently owned by the
Company, and others that may be acquired, when they are proven to be
productive. The Company is continuing to purchase oil and gas leases in areas
where it currently has production, and also in other areas.
- 9 -
Dependence on Customers
The following is a summary of significant purchasers from oil and natural gas
produced by the Company for the three-year period ended December 31, 2006:2007:
Year Ended December 31, (1)
--------------------------------
Purchaser 2007 2006 2005 2004
- ----------------------------------------- -------- -------- --------
Enbridge Energy PartnersNorth Texas 36% 38% 39%
14%Crosstex Energy Services, LP 26% 3% 5%
Shell Trading (US) Company 6% 8% 7%
Teppco Crude Oil, LP 5% 3% -%
Targa Midstream Service, LIM
(formerly Dynegy Midstream Services, LIM 3% -% -%
Navajo Refining Co. 2% -% -%
Devon Gas Services, L.P 2% 4% 6%
ETC Texas Pipeline 2% 5% -%
Eastex Crude Company 2% -% -%
Empire Pipeline Corp 1% 3% -%
Duke Energy Field Services 1% -% -%
Plains Marketing, LP. 1% 6% 6% 6%
Devon Gas Services, L.P 4% 6% 12%
Crosstex Energy Services, Ltd 3% 5% 8%
Empire Pipeline Corp 3% -% -%
Teppco Refining 3% -% -%
Dynegy Midstream Services, LIM -% 5% 11%
Panther Pipeline North Texas, Inc. -% -% 13%
LIG Chemical Company -% -% 2%5%
(1) Percent of Total Oil & Gas Sales
Oil and gas is sold to approximately 110108 different purchasers (such as Devon
Gas Services, L.P., Enbridge Energy Partners (formerly Cantera Resources,
Inc.), Plains Marketing, L.P., Shell Trading (US) Company, Targa (formerly
Dynegy Midstream Services), Empire Pipeline Corporation, and Duke Energy Field
Services under market
sensitive, short-term contracts computed on a month to month basis.
Except as set forth above, there are no other customers of the Company that
individually accounted for more than 5% of the Company's oil and gas revenues
during the three years ended December 31, 2006.2007.
The Company currently has no hedged contracts.
Development Activities
The Company's primary oil and gas prospect acquisition efforts have been in
known producing areas in the United States with emphasis devoted to Texas.
The Company intends to use a portion of its available funds to participate in
drilling activities. Any drilling activity is performed by independent
- 11 -
drilling contractors. The Company does not refine or otherwise process its
oil and gas production.
Exploration for oil and gas is normally conducted with the Company acquiring
undeveloped oil and gas prospects, and carrying out exploratory drilling on
the prospect with the Company retaining a majority interest in the prospect.
Interests in the property are sometimes sold to key employees and associated
companies at cost. Also, interests may be sold to third parties with the
Company retaining an overriding royalty interest, carried working interest,
or a reversionary interest.
- 10 -
A prospect is a geographical area designated by the Company for the purpose of
searching for oil and gas reserves and reasonably expected by it to contain at
least one oil or gas reservoir. The Company utilizes its own funds along with
the issuance of common stock and options to purchase common stock in some
cases, to acquire oil and gas leases covering the lands comprising the
prospects. These leases are selected by the Company and are obtained directly
from the landowners, as well as from land men, geologists, other oil companies,
some of whom may be affiliated with the Company, and by direct purchase, farm-
in, or option agreements. After an initial test well is drilled on a property,
any subsequent development of such prospect will normally require the Company's
participation for the development of the discovery.
Special Tax Provisions
See Footnote 8 to Consolidated Financial Statements regarding the accounting
for income taxes.
Employees
The Company, on its own account and through a management contract with its
parent corporation,Giant
Energy Corp, employs or contracts for the services of a total of 48approximately
60 people. FourteenTwenty-five are full-time employees or contractors. The remainder
are part-time contractors or employees. We believe that our relationships with
our employees are good.
In order to effectively utilize our resources in respect to our development
program, we employ the services of independent consultants and contractors to
perform a variety of professional and technical services, including in the
areas of lease acquisition, land-related documentation and contracts, drilling
and completion work, pumping, inspection, testing, maintenance and specialized
services. We believe that it can be more cost effective to utilize the
services of consultants and independent contractors for some of these services.
We depend to a large extent on the services of certain key management personnel
and officers, and the loss of any these individuals could have a material
adverse effect on our operations. The Company does not maintain key-main life
insurance policies on its employees.
Financial information about foreign and domestic operations and export sales
- ----------------------------------------------------------------------------
All of the Company's business is conducted domestically, with no export sales.
- 12 -
Compliance with Environmental Regulations
- -----------------------------------------
Our oil and natural gas operations are subject to numerous U.S. Federal, state
and local laws and regulations relating to the protection of the environment,
including those governing the discharge of materials into the water and air,
the generation, management and disposal of hazardous substances and wastes and
clean-up of contaminated science. We could incur material costs, including
clean-up costs, fines and civil and criminal sanctions and third party claims
for property damage and personal injury as a result of violations of, or
liabilities under, environmental laws and regulations. Such laws and
- 11 -
regulations not only expose us to liability for our own activities, but may
also expose us to liability for the conduct of others or for actions by us that
were in compliance with all applicable laws at the time those actions were
taken. In addition, we could incur substantial expenditures complying with
environmental laws and regulations, including future environmental laws and
regulations which may be more stringent.
On June 21, 2007, the acting United States attorney for the Eastern District
of Texas filed an Information against Spindletop Drilling Company, ("SDC") has reached a tentative agreement withsubsidiary
of the registrant in a case styled The United States of America v. Spindletop
Drilling Company, Case No. 5:07CR16 filed in the United States Government concerningDistrict Court
for the Eastern District of Texas, Texarkana Division. The Information alleges
a violation of Title 16, USC Sec 703 (unlawful taking of migratory birds),
charges Spindletop Drilling Company with a Class B misdemeanor petty offense
advising that on or about September 6, 2006 in Titus County, Texas allegedly
took migratory birds including approximately twelve (12) Northern Mockingbirds
(Mimus Polyglottos) and one (1) Mourning Dove (Zenaida Macroura), all in
violation of 16 USC Sec 703 and 707(a). Spindletop Drilling Company owns and
operates an investigation conducted byoil pit located on the United
States Department"Pewitt D" lease located in Titus County,
Texas. Although Spindletop Drilling Company had netting in place, several
small birds were found in the pit in early September, 2006.
Although the incident was inadvertent, on June 26, 2007, in order to resolve
the matter, Spindletop Drilling Company entered into a plea agreement agreeing
to one count of the Interior,Information which charged a violation of 16 USC Sec 703
and stipulated and agreed that two years probation, $10,000 in restitution
payable to the National Fish and Wildlife Service related to the
accidental deaths of several birds on one of SDC's east Texas leases. Under
the terms of the tentative agreement, SDC would accept a misdemeanor citation
with respect to the Migratory Bird Treaty Act, pay a $10,000Foundation, no fine, and agree
to implement appropriatea $25
special assessment would best advance the objectives under the law. The court
gave final approval of this agreement on October 4, 2007.
During the three months ended March 31, 2007, Spindletop Drilling Company
corrected the netting on the property and implemented other safeguards to
further protect the migratory birds.birds and property in question.
Glossary of Oil and Gas Terms
The understanding,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.
- 13 -
"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.
"BTU" means British Thermal Units. British Thermal Unit means the quantity of
heat required to raise the temperature of one pound of water by one degree
Fahrenheit.
"Completion" means the installation of permanent equipment for the production
of oil or gas.
"Development Well" means a well drilled within the proved area of an oil or gas
reservoir to the depth of a strata graphic horizon known to be productive.
"Dry Hole" or "Dry Well" means a well found to be incapable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
"Exploratory Well" means a well drilled to find and produce oil or gas reserves
not classified as proved, to find a new production reservoir in a field
previously found to be productive of oil or gas in another reservoir or to
extend a known reservoir.
"Farm-Out" means an agreement pursuant to which couldthe 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.
"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.
"MCFG/D" means thousand cubic feet of gas per day.
"MMBTU" means ones million BTUs.
- 14 -
"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.
"Operator" means the individual or company responsible for the exploration,
development and production 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 implementedgenerated 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 earlyof 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 endapplication of April, 2007,
would resolvefluid
injection or other improved recovery techniques for supplementing the matternatural
forces and mechanisms of primary recovery will be included as "proved developed
reserves" only after testing by a pilot project or after the operation of an
installed program has confirmed through production response that increased
recovery will be achieved.
"Proved Reserves" means the estimated quantities of crude oil and natural gas
which upon analysis of geological and engineering data appear with reasonable
certainty to be recoverable in future years from known reservoirs under
existing economic and operating conditions, i.e., prices and costs as of the
date the estimate is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on escalations based
upon future conditions.
(i) Reservoirs are considered proved if either actual production or
conclusive formation tests support economic producibility. The area of
a reservoir considered proved includes (A) that portion delineated by
drilling and defined by gas-oil and/or oil-water contacts, if any; and
(B) the immediately adjoining portions not yet drilled, but which can
be reasonably judged as economically productive on the basis of
available geological and engineering data. In the absence of
information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.
- 15 -
(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 SDCgeology, 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 Companyexisting 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.
"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.
"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
- 16 -
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.
Item 1A. Risk Factors
Risks related directly to our Company
- -------------------------------------
You should carefully consider the following risk factors, in addition to the
other information set forth in this Report, before investing in shares of our
common stock. Each of these risk factors could adversely affect our business,
operating results and financial condition, as well as adversely affect the
value of an investment in our common stock. Some information in this Report
may contain "forward-looking" statements that discuss future expectations of
our financial condition and results of operation. The risk factors noted in
this section and other factors could cause our actual results to differ
materially from those contained in any forward-looking statements.
We face significant competition, and many of our competitors have resources in
excess of our available resources.
The oil and gas industry is highly competitive. We encounter competition from
other oil and gas companies in all areas of our operations, including the
acquisition of producing properties and sale of crude oil and natural gas. Our
competitors include major integrated oil and gas companies and numerous
independent oil and gas companies, individuals and drilling and income
programs. Many of our competitors are large, well established companies with
substantially larger operating staffs and greater capital resources than us.
Such companies may be able to pay more for productive oil and gas properties
and exploratory prospects and to define, evaluate, bid for and purchase a
greater number of properties and prospects than our financial or human
resources permit. Our ability to acquire additional properties and to discover
reserves in the future will depend upon our ability to evaluate and select
suitable properties and to consummate transactions in this highly competitive
environment.
- 1217 -
Exploratory drilling is a speculative activity that may not result in
commercially productive reserves and may require expenditures in excess of
budgeted amounts.
Drilling activities are subject to many risks, including the risk that no
commercially productive oil or gas reservoirs will be encountered. There can
be no assurance that new wells drilled by us will be productive or that we will
recover all or any portion of our investment. Drilling for oil and gas may
involve unprofitable efforts, not only from dry wells, but also from wells
that are productive but do not produce sufficient net revenues to return a
profit after drilling, operating and other costs. The cost of drilling,
completing and operating wells is often uncertain. Our drilling operations may
be curtailed, delayed or canceled as a result of a variety of factors, many of
which are beyond our control, including economic conditions, mechanical
problems, pressure or irregularities in formations, title problems, weather
conditions, compliance with governmental requirements and shortages in or
delays in the delivery of equipment and services. In today's environment,
shortages make drilling rigs, labor and services difficult to obtain and could
cause delays or inability to proceed with our drilling and development plans.
Such equipment shortages and delays sometimes involve drilling rigs where
inclement weather prohibits the movement of land rigs causing a high demand for
rigs by a large number of companies during a relatively short period of time.
Our future drilling activities may not be successful. Lack of drilling success
could have a material adverse effect on our financial condition and results of
operations.
Our operations are also subject to all the hazards and risks normally incident
to the development, exploitation, production and transportation of, and the
exploration for, oil and gas, including unusual or unexpected geologic
formations, pressures, down hole fires, mechanical failures, blowouts,
explosions, uncontrollable flows of oil, gas or well fluids and pollution and
other environmental risks. These hazards could result in substantial losses to
us due to injury and loss of life, severe damage to and destruction of property
and equipment, pollution and other environmental damage and suspension of
operations. We participate in insurance coverage maintained by the operator of
its wells, although there can be no assurances that such coverage will be
sufficient to prevent a material adverse effect to us in such events.
The vast majority of our oil and gas reserves are classified as proved
reserves. Recovery of the Company's future proved undeveloped reserves will
require significant capital expenditures. Our management estimates that
aggregate capital expenditures of approximately $4,778,000$4,601,000 will be required to
fully develop some of these reserves in the next twenty-four months. No
assurance can be given that our estimates of capital expenditures will prove
accurate, that our financing sources will be sufficient to fully fund our
planned development activities or that development activities will be either
successful or in accordance with our schedule. Additionally, any significant
decrease in oil and gas prices or any significant increase in the cost of
development could result in a significant reduction in the number of wells
drilled and/or reworked. No assurance can be given that any wells will produce
oil or gas in commercially profitable quantities.
- 1318 -
We are subject to uncertainties in reserve estimates and future net cash flows.
This annual report contains estimates of our oil and gas reserves and the
future net cash flows from those reserves, which have been prepared by
Netherland, Sewell & Associates, Inc., independent petroleum engineers.
There are numerous uncertainties inherent in estimating quantities of
reserves of oil and gas and in projecting future rates of production and the
timing of development expenditures, including many factors beyond our control.
The reserve estimates in this annual report are based on various assumptions,
including, for example, constant oil and gas prices, operating expenses,
capital expenditures and the availability of funds, and, therefore, are
inherently imprecise indications of future net cash flows. Actual future
production, cash flows, taxes, operating expenses, development expenditures
and quantities of recoverable oil and gas reserves may vary substantially from
those assumed in the estimates. Any significant variance in these assumptions
could materially affect the estimated quantity and value of reserves set forth
in this prospectus. Additionally, our reserves may be subject to downward or
upward revision based upon actual production performance, results of future
development and exploration, prevailing oil and gas prices and other factors,
many of which are beyond our control.
The present value of future net reserves discounted at 10% (the "PV-10") of
proved reserves referred to in this annual report should not be construed as
the current market value of the estimated proved reserves of oil and gas
attributable to our properties. In accordance with applicable requirements of
the SEC, the estimated discounted future net cash flows from proved reserves
are generally based on prices and costs as of the date of the estimate, whereas
actual future prices and costs may be materially higher or lower. Actual
future net cash flows also will be affected by: (i) the timing of both
production and related expenses; (ii) changes in consumption levels; and
(iii) governmental regulations or taxation. In addition, the calculation of
the present value of the future net cash flows using a 10% discount as required
by the SEC is not necessarily the most appropriate discount factor based on
interest rates in effect from time to time and risks associated with our
reserves or the oil and gas industry in general. Furthermore, our reserves may
be subject to downward or upward revision based upon actual production, results
of future development, supply and demand for oil and gas, prevailing oil and
gas prices and other factors. See "Properties - Oil and Gas Reserves."
We are subject to various operating and other casualty risks that could result
in liability exposure or the loss of production and revenues.
Our oil and gas business involves a variety of operating risks, including, but
not limited to, unexpected formations or pressures, uncontrollable flows of
oil, gas, brine or well fluids into the environment (including groundwater
contamination), blowouts, fires, explosions, pollution and other risks, any of
which could result in personal injuries, loss of life, damage to properties and
substantial losses. Although we carry insurance at levels that we believe are
reasonable, we are not fully insured against all risks. We do not carry
business interruption insurance. Losses and liabilities arising from uninsured
or under-insured events could have a material adverse effect on our financial
condition and operations.
- 1419 -
From time to time, due primarily to contract terms, pipeline interruptions or
weather conditions, the producing wells in which we own an interest have been
subject to production curtailments. The curtailments range from production
being partially restricted to wells being completely shut-in. The duration of
curtailments varies from a few days to several months. In most cases, we are
provided only limited notice as to when production will be curtailed and the
duration of such curtailments. We are not currently experiencing any material
curtailment of our production.
We intend to increase our development and, to a lesser extent, exploration
activities. Exploration drilling and, to a lesser extent, development drilling
of oil and gas reserves involve a high degree of risk that no commercial
production will be obtained and/or that production will be insufficient to
recover drilling and completion costs. The cost of drilling, completing and
operating wells is often uncertain. Our drilling operations may be curtailed,
delayed or canceled as a result of numerous factors, including title problems,
weather conditions, compliance with governmental requirements and shortages or
delays in the delivery of equipment. Furthermore, completion of a well does not
assure a profit on the investment or a recovery of drilling, completion and
operating costs.
We depend to a large extent on the services of Chris G. Mazzini, our President,
Chairman of the Board, and Chief Executive Officer. The loss of the services
of Mr. Mazzini would have a material adverse effect on our operations. We have
not entered into any employment contracts with our executive officer and have
not obtained key personnel life insurance on Mr. Mazzini.
Certain of our affiliates control a majority of our outstanding common stock,
which may affect your vote as a shareholder.
Our executive officers, directors and their affiliates hold approximately 81%77%
of our outstanding shares of common stock. As a result, officers, directors
and their affiliates and such shareholders have the ability to exert
significant influence over our business affairs, including the ability to
control the election of directors and results of voting on all matters
requiring shareholder approval. This concentration of voting power may delay
or prevent a potential change in control.
Certain of our affiliates have engaged in business transactions with the
Company, which may result in conflicts of interest.
Certain officers, directors and related parties, including entities controlled
by Mr. Mazzini, the President and Chief Executive Officer, have engaged in
business transactions with the Company which were not the result of arm's
length negotiations between independent parties. Our management believes that
the terms of these transactions were as favorable to us as those that could
have been obtained from unaffiliated parties under similar circumstances. All
future transactions between us and our affiliates will be on terms no less
favorable than could be obtained from unaffiliated third parties and will be
approved by a majority of the disinterested members of our Board of Directors.
- 1520 -
Our common stock is traded on the Over-the-Counter Bulletin Board ("OTC BB"),
symbol "SPND".
The liquidity of our common stock may be adversely affected, and purchasers of
our common stock may have difficulty selling our common stock, if our common
stock does not continue to trade in that or another suitable trading market.
There is presently only a limited public market for our common stock, and there
is no assurance that a ready public market for our securities will develop.
It is likely that any market that develops for our common stock will be highly
volatile and that the trading volume in such market will be limited. The
trading price of our common stock could be subject to wide fluctuations in
response to quarter-to-quarter variations in our operating results,
announcements of our drilling results and other events or factors. In
addition, the U.S. stock market has from time to time experienced extreme price
and volume fluctuations that have affected the market price for many companies
and which often have been unrelated to the operating performance of these
companies. These broad market fluctuations may adversely affect the market
price of our securities.
We do not intend to declare dividends in the foreseeable future.
Our Board of Directors presently intends to retain all of our earnings for the
expansion of our business. We therefore do not anticipate the distribution of
cash dividends in the foreseeable future. Any future decision of our Board of
Directors to pay cash dividends will depend, among other factors, upon our
earnings, financial position and cash requirements.
Our company employees and contract land professionals have reviewed title
records or other title review materials relating to substantially all of our
producing properties. The title investigation performed by us prior to
acquiring undeveloped properties is thorough, but less rigorous than that
conducted prior to drilling, consistent with industry standards. We believe we
have satisfactory title to all our producing properties in accordance with
standards generally accepted in the oil and gas industry. Our properties are
subject to customary royalty interests, liens incident to operating agreements,
liens for current taxes and other burdens, which we believe do not materially
interfere with the use of or affect the value of such properties. At December
31, 2006,2007, our leaseholds for some of our net acreage were being kept in force
by virtue of production on that acreage in paying quantities. The remaining
net acreage was held by lease rentals and similar provisions and requires
production in paying quantities prior to expiration of various time periods to
avoid lease termination.
We expect to make acquisitions of oil and gas properties from time to time
subject to available resources. In making an acquisition, we generally focus
most of our title and valuation efforts on the more significant properties.
It is generally not feasible for us to review in-depth every property we
purchase and all records with respect to such properties. However, even an in-depthin-
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
- 1621 -
property selection process, is a process that depends upon evaluation of
existing geological, engineering and production data, some or all of which may
prove to be unreliable or not indicative of future performance. To the extent
the seller does not operate the properties, obtaining access to properties and
records may be more difficult. Even when problems are identified, the seller
may not be willing or financially able to give contractual protection against
such problems, and we may decide to assume environmental and other liabilities
in connection with acquired properties.
Our business is highly capital-intensive requiring continuous development and
acquisition of oil and gas reserves. In addition, capital is required to
operate and expand our oil and gas field operations and purchase equipment.
At December 31, 2006,2007, we had working capital of $4,964,000.$5,241,000. We anticipate that
we will be able to meet our cash requirements for the next 12 months. However,
if such plans or assumptions change or prove to be inaccurate, we could be
required to seek additional financing sooner than currently anticipated.
We have funded our operations, acquisitions and expansion costs primarily
through the generation of our internally generated cash flow. Our success in
obtaining the necessary capital resources to fund future costs associated with
our operations and expansion plans is dependent upon our ability to:
(i) increase revenues through acquisitions and recovery of our proved
producing and proved developed non-producing oil and gas reserves; and
(ii) maintain effective cost controls at the corporate administrative office
and in field operations. However, even if we achieve some success with our
plans, there can be no assurance that we will be able to generate sufficient
revenues to achieve significant profitable operations or fund our expansion
plans.
We have substantial capital requirements necessary for undeveloped properties
for which we may not be able to obtain adequate financing.
Development of our properties will require additional capital resources.
We have no commitments to obtain any additional debt or equity financing and
there can be no assurance that additional financing will be available, when
required, on favorable terms to us. The inability to obtain additional
financing could have a material adverse effect on us, including requiring us
to curtail significantly our oil and gas acquisition and development plans or
farm-out development of our properties. Any additional financing may involve
substantial dilution to the interests of our shareholders at that time.
Oil and natural gas prices fluctuate widely and low prices could have a
material adverse impact on our business and financial results.
Our revenues, profitability and the carrying value of its oil and gas
properties are substantially dependent upon prevailing prices of, and demand
for, oil and gas and the costs of acquiring, finding, developing and producing
reserves. Our ability to obtain borrowing capacity, to repay future
indebtedness, and to obtain additional capital on favorable terms is also
substantially dependent upon oil and gas prices. Historically, the markets for
oil and gas have been volatile and are likely to continue to be volatile in the
future. Prices for oil and gas are subject to wide fluctuations in response
- 1722 -
to: (i) relatively minor changes in the supply of, and demand for, oil and gas;
(ii) market uncertainty; and (iii) a variety of additional factors, all of
which are beyond our control. These factors include domestic and foreign
political conditions, the price and availability of domestic and imported oil
and gas, the level of consumer and industrial demand, weather, domestic and
foreign government relations, the price and availability of alternative fuels
and overall economic conditions. Furthermore, the marketability of our
production depends in part upon the availability, proximity and capacity of
gathering systems, pipelines and processing facilities. Volatility in oil and
gas prices could affect our ability to market our production through such
systems, pipelines or facilities. As of December 31, 2006,2007, approximately 70%78%
of our gas production is currently sold to eight gas marketingpurchasing firms on a
month-to-month basis at prevailing spot market prices. Oil prices remained
subject to unpredictable political and economic forces during 2004,2007, 2006 and
2005, and
2006, and experienced fluctuations similar to those seen in natural gas prices
for the year. We believe that oil prices will continue to fluctuate in
response to changes in the policies of the Organization of Petroleum Exporting
Countries ("OPEC"), changes in demand from many Asian countries, current events
in the Middle East, security threats to the United States, and other factors
associated with the world political and economic environment. As a result of
the many uncertainties associated with levels of production maintained by OPEC
and other oil producing countries, the availabilities of worldwide energy
supplies and competitive relationships and consumer perceptions of various
energy sources, we are unable to predict what changes will occur in crude oil
and natural gas prices.
We may be responsible for additional costs in connection with abandonment of
properties.
We are responsible for payment of plugging and abandonment costs on its oil
Andand gas properties pro rata to our working interest. Based on our experience,
Wewe anticipate that in most cases, the ultimate aggregate salvage value of lease
and well equipment located on our properties will exceedshould equal to the costs of
abandoning such properties. There can be no assurance, however, that we will be
successful in avoiding additional expenses in connection with the abandonment
of any of our properties. In addition, abandonment costs and their timing may
change due to many factors, including actual production results, inflation
rates and changes in environmental laws and regulations.
Risks that Involve the Oil & Gas Industry in General.
- ---------------------------------------------------------------------------------------------------------
We are subject to various governmental regulations which may cause us to incur
substantial costs.
Our operations are affected from time to time in varying degrees by political
developments and federal, state and local laws and regulations. In particular,
oil and gas production related operations are or have been subject to price
controls, taxes and other laws and regulations relating to the oil and gas
industry. Failure to comply with such laws and regulations can result in
substantial penalties. The regulatory burden on the oil and gas industry
increases our cost of doing business and affects our profitability. Although
- 23 -
we believe we are in substantial compliance with all applicable laws and
- 18 -
regulations, because such laws and regulations are frequently amended or
reinterpreted, we are unable to predict the future cost or impact of complying
with such laws and regulations.
Sales of natural gas by us are not regulated and are generally made at market
prices. However, the Federal Energy Regulatory Commission ("FERC") regulates
interstate natural gas transportation rates and service conditions, which
affect the marketing of natural gas produced by us, as well as the revenues
received by us for sales of such production. Sales of our natural gas
currently are made at uncontrolled market prices, subject to applicable
contract provisions and price fluctuations that normally attend sales of
commodity products.
Since the mid-1980's, the FERC has issued a series of orders, culminating in
Order Nos. 636, 636-A and 636-B ("Order 636"), that have significantly altered
the marketing and transportation of natural gas. Order 636 mandated a
fundamental restructuring of interstate pipeline sales and transportation
service, including the unbundling by interstate pipelines of the sale,
transportation, storage and other components of the city-gate sales services
such pipelines previously performed. One of the FERC's purposes in issuing the
orders was to increase competition within all phases of the natural gas
industry. Order 636 and subsequent FERC orders issued in individual pipeline
restructuring proceedings have been the subject of appeals, and the courts have
largely upheld Order 636. Because further review of certain of these orders is
still possible, and other appeals may be pending, it is difficult to exactly
predict the ultimate impact of the orders on us and our natural gas marketing
efforts. Generally, Order 636 has eliminated or substantially reduced the
interstate pipelines' traditional role as wholesalers of natural gas, and has
substantially increased competition and volatility in natural gas markets.
While significant regulatory uncertainty remains, Order 636 may ultimately
enhance our ability to market and transport our natural gas, although it may
also subject us to greater competition, more restrictive pipeline imbalance
tolerances and greater associated penalties for violation of such tolerances.
The FERC has announced several important transportation-related policy
statements and proposed rule changes, including the appropriate manner in which
interstate pipelines release capacity under Order 636 and, more recently, the
price which shippers can charge for their released capacity. In addition, in
1995, the FERC issued a policy statement on how interstate natural gas
pipelines can recover the costs of new pipeline facilities. In January 1997,
the FERC issued a policy statement and a request for comments concerning
alternatives to its traditional cost-of-service rate making methodology. A
number of pipelines have obtained FERC authorization to charge negotiated rates
as one such alternative. While any additional FERC action on these matters
would affect us only indirectly, these policy statements and proposed rule
changes are intended to further enhance competition in natural gas markets.
We cannot predict what the FERC will take on these matters, nor can we predict
whether the FERC's actions will achieve its stated goal of increasing
competition in natural gas markets. However, we do not believe that we will
be treated materially differently than other natural gas producers and
marketers with which we compete.
- 1924 -
The price we receive from the sale of oil is affected by the cost of
transporting such products to market. Effective January 1, 1995, the FERC
implemented regulations establishing an indexing system for transportation
rates for oil pipelines, which, generally, would index such rates to inflation,
subject to certain conditions and limitations. These regulations could
increase the cost of transporting oil by interstate pipelines, although the
most recent adjustment generally decreased rates. These regulations have
generally been approved on judicial review. We are not able to predict with
certainty the effect, if any, of these regulations on its operations. However,
the regulations may increase transportation costs or reduce wellhead prices for
oil.
The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration for and production of oil and gas.
Such states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and gas properties,
the establishment of maximum rates of production from wells and the regulation
of spacing, plugging and abandonment of such wells. The statutes and
regulations of certain states limit the rate at which oil and gas can be
produced from our properties. However, we do not believe we will be affected
materially differently by these statutes and regulations than any other
similarly situated oil and gas company.
We are subject to various environmental risks which may cause us to incur
substantial costs.
Our operations and properties are subject to extensive and changing federal,
state and local laws and regulations relating to environmental protection,
including the generation, storage, handling and transportation of oil and gas
and the discharge of materials into the environment, and relating to safety and
health. The recent trend in environmental legislation and regulation generally
is toward stricter standards, and this trend will likely continue. These laws
and regulations may require the acquisition of a permit or other authorization
before construction or drilling commences and for certain other activities;
limit or prohibit construction, drilling and other activities on certain lands
lying within wilderness and other protected areas; and impose substantial
liabilities for pollution resulting from our operations. The permits required
for our various operations are subject to revocation, modification and renewal
by issuing authorities. Governmental authorities have the power to enforce
compliance with their regulations, and violations are subject to fines,
penalties or injunctions. In the opinion of management, we are in substantial
compliance with current applicable environmental laws and regulations, and we
have no material commitments for capital expenditures to comply with existing
environmental requirements. Nevertheless, changes in existing environmental
laws and regulations or in interpretations thereof could have a significant
impact on us. The impact of such changes, however, would not likely be any
more burdensome to us than to any other similarly situated oil and gas company.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, and similar state laws impose
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons that are considered to have contributed to the
- 2025 -
release of a "hazardous substance" into the environment. These persons include
the owner or operator of the disposal site or sites where the release occurred
and companies that disposed or arranged for the disposal of the hazardous
substances found at the site. Persons who are or were responsible for releases
of hazardous substances under CERCLA may be subject to joint and several
liability for the costs of cleaning up the hazardous substances that have been
released into the environment and for damages to natural resources.
Furthermore, neighboring landowners and other third parties may file claims for
personal injury and property damage allegedly caused by the hazardous
substances released into the environment.
We generate typical oil and gas field wastes, including hazardous wastes that
are subject to the federal Resources Conservation and Recovery Act and
comparable state statutes. The United States Environmental Protection Agency
and various state agencies have limited the approved methods of disposal for
certain hazardous and non-hazardous wastes. Furthermore, certain wastes
generated by our oil and gas operations that are currently exempt from
regulation as "hazardous wastes" may in the future be designated as "hazardous
wastes," and therefore be subject to more rigorous and costly operating and
disposal requirements.
The Oil Pollution Act ("OPA") imposes a variety of requirements on responsible
parties for onshore and offshore oil and gas facilities and vessels related to
the prevention of oil spills and liability for damages resulting from such
spills in waters of the United States. The "responsible party" includes the
owner or operator of an onshore facility or vessel or the lessee or permittee
of, or the holder of a right of use and easement for, the area where an onshore
facility is located. OPA assigns liability to each responsible party for oil
spill removal costs and a variety of public and private damages from oil
spills. Few defenses exist to the liability for oil spills imposed by OPA. OPA
also imposes financial responsibility requirements. Failure to comply with
ongoing requirements or inadequate cooperation in a spill event may subject a
responsible party to civil or criminal enforcement actions.
We own or lease properties that for many years have produced oil and gas.
We also own natural gas gathering systems. It is not uncommon for such
properties to be contaminated with hydrocarbons. Although we or previous
owners of these interests may have used operating and disposal practices that
were standard in the industry at the time, hydrocarbons or other wastes may
have been disposed of or released on or under the properties or on or under
other locations where such wastes have been taken for disposal. These
properties may be subject to federal or state requirements that could require
us to remove any such wastes or to remediate the resulting contamination. All
of our properties are operated by third parties over whom we have limited
control. Notwithstanding our lack of control over properties operated by
others, the failure of the previous owners or operators to comply with
applicable environmental regulations may, in certain circumstances, adversely
impact us.
Item 1B. Unresolved Staff Comments
None
- 2126 -
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,
-----------------------------------
2007 2006 2005 2004
----------- ----------- -----------
Gas and Oil Properties, net (1):
Proved developed gas reserves-Mcf (2) 10,948,000 7,353,000 7,110,000 6,888,000
Proved undeveloped gas reserves-Mcf (3) 3,419,000 6,033,000 7,672,000 6,844,000
----------- ----------- -----------
Total proved gas reserves-Mcf 14,367,000 13,386,000 14,782,000 13,732,000
=========== =========== ===========
Proved Developed Crude Oil and
Condensate reserves-Bbls (2) 334,000 341,000 434,000 390,000
Proved Undeveloped crude oil and
Condensate reserves-Bbls (3) 11,000 16,000 50,000 29,000
----------- ----------- -----------
Total proved crude oil and condensate
Reserves-Bbls 345,000 357,000 484,000 419,000
=========== =========== ===========
(1) The estimate of the net proved oil and gas reserves, future net revenues,
and the present value of future net revenues.
(2) "Proved Developed Oil and Gas Reserves" are reserves that can be expected
to be recovered through existing wells with existing equipment and operating
methods.
(3) "Proved Undeveloped Reserves" are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. See Footnote 18 to
the Financial Statements, Supplemental Reserve Information (Unaudited), for
further explanation of the changes for 20042005 through 20062007.
- 2227 -
Wells Drilled and Completed
- ---------------------------
The Company's working interests in exploration and development wells completed
during the years indicated were as follows:
Year Ended December 31,
-----------------------------------------
2007 2006 2005 2004
------------- ------------- -------------
Gross Net Gross Net Gross Net
------ ------ ------ ------ ------ ------
Exploratory Wells (1):
Productive - - - - - -
Non-Productive - - - - - -
------ ------ ------ ------ ------ ------
Total - - - - - -
------ ------ ------ ------ ------ ------
Development Wells (2):
Productive 17.000 4.714 10.000 0.627 14.000 1.639
10.000 1.171
Non-Productive - - 1.000 0.006 - - - -
------ ------ ------ ------ ------ ------
Total 17.000 4.714 11.000 0.633 14.000 1.639 10.000 1.171
------ ------ ------ ------ ------ ------
Total Exploration & Development
Wells:
Productive 17.000 4.714 10.000 0.627 14.000 1.639
10.000 1.171
Non-Productive - - 1.000 0.006 - - - -
------ ------ ------ ------ ------ ------
Total 17.000 4.714 11.000 0.633 14.000 1.639 10.000 1.171
------ ------ ------ ------ ------ ------
(1) An exploratory well is a well drilled to find and produce oil or gas in an
unprovenunproved 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.
- 2328 -
The following tables set forth additional data with respect to production from
Company-owned oil and gas properties, all located within the continental United
States:
For the years ended December 31
2007 2006 2005 2004 2003 2002
-------- -------- -------- -------- --------
Oil and Gas Production, net:
Natural Gas (Mcf) 880,662 671,527 655,568 577,099 540,799 499,081
Crude Oil & Condensate (Bbl) 24,472 25,443 21,323 23,098 28,747 9,553
Average Sales Price per Unit
Produced:
Natural Gas ($/Mcf) $ 6.63 $ 5.55 $ 6.74 $ 5.44 $ 4.33
$ 3.02
Crude Oil & Condensate($/Bbl)$ 65.17 $ 53.14 $ 52.50 $ 38.90 $ 25.14 $ 23.27
Average Production Cost per
Equivalent Barrel (1) (2) $ 14.36 $ 15.14 $ 13.38 $ 11.69 $ 10.41 $ 8.51
(1) Includes severance taxes and ad valorem taxes.
(2) Gas production is converted to equivalent barrels at the rate of six Mcf
per barrel, representing relative energy content of natural gas to oil.
The Company owns producing royalties and overriding royalties under properties
located in Texas. The revenue from these properties is not significant.
The Company is not aware of any major discovery or other favorable or adverse
event that is believed to have caused a significant change in the estimated
proved reserves since December 31, 2006.2007.
The Company currently has leases covering in excess of 7,3009,204 gross acres,
mostly held by existing production, in Clay, Denton, Eastland, Erath, Hood,
Palo Pinto, Parker, and Tarrant Counties, Texas, (currently held by production), that the Company believes may
have drilling locations infor the Barnett Shale Formation. The Company has
included some of these potential locations in its calculation of proven
undeveloped oil and gas reserves.reserves but the Company has not included any of its
probable or possible locations. See Footnote 18 to the Financial Statement for
an expanded description of this activity.
OFFICE SPACE
On December 27, 2004, the Company acquired a commercial office building. The
property acquired is a two story multi-tenant, garden office building with a
sub-grade parking garage. The 2526 year old building contains approximately
46,286 rentable square feet and sits on a 1.4919 acre block of land situated
in north Dallas, Texas in close proximity to hotels, restaurants and shopping
areas (the Galleria/Valley View Mall) with easy access to Interstate Highway
635 (LBJ Freeway) and Dallas Parkway (North Dallas Toll Road). The Company
occupies approximately 8,668 rentable square feet of the building as its
primary office headquarters, and leases the remaining space in the building
to non-
relatednon-related third party commercial tenants at prevailing market rates.
On March 17, 2008, the Company entered into an agreement with an existing
- 2429 -
tenant to take back 1,649 RSF of office space. The Company is currently
expanding its current office space to accommodate its growing staff and will
occupy 10,317 RSF after the expansion project is completed.
The address of the Company's principal executive offices is One Spindletop
Centre, 12850 Spurling Road, Suite 200, Dallas, Texas 75230. The telephone
number is (972) 644-2581.
PIPELINES
The Company owns, through its subsidiary, PPC, 26.1 miles of natural gas
pipelines in Parker, Palo Pinto and Eastland Counties, Texas. These pipelines
are steel and polyethylene and range in size from 2 inches to 4 inches. These
pipelines primarily gather natural gas from wells operated by the Company and
in which the Company owns a working interest, but also for other parties.
The Company normally does not purchase and resell natural gas, but gathers gas
for a fee. The fees charged in some cases are subject to regulations by the
State of Texas and the Federal Energy Regulatory Commission. Average daily
volumes of gas gathered by the pipelines owned by the Company were 1,112, 714,
821,
and 806821 MCF per day for 2007, 2006, 2005, and 20042005 respectively.
Oilfield Production Equipment
The Company owns various natural gas compressors, pumping units, dehydrators
and various other pieces of oil field production equipment.
Substantially all of the equipment is located on oil and gas properties
operated by the Company and in which it owns a working interest. The rental
fees are charged as lease operating fees to each property and each owner.
Chris G. Mazzini and Michelle H. Mazzini, through a limited partnership in
which they are limited partners, started an oil field service company which
provides roustabout, swabbing and completion services at rates which are at or
below market to the Company. The oil field service company plans to expand
equipment and services they provide. This oil field services company does work
exclusively for the Company and its parentrelated company Giant Energy Corp. The
Company benefits by having immediate access to services in a tight market.
Item 3. Legal Proceedings
Neither the Registrant nor its subsidiaries nor any officers or directors is a
party to any material pending legal proceedings for or against the Company or
its subsidiary nor are any of their properties subject to any proceedings.
During the fourth quarter of the fiscal year covered by this report, no
proceeding previously reported was terminated.
- 30 -
Item 4. Submission Of Matters Of Security Holders To A Vote
During the fourth quarter of the registrant's fiscal year covered by this
report, no matter was submitted to a vote of security holders of the
registrant.
- 25 -
PART II
Item 5. Market For The Company's Common Stock, Related Stockholder Matters And
Issuer Purchases Of Equity Securities.
The Company's common stock trades over-the-counter under the symbol "SPND".
Prior to 2004, no significant public trading market had been established for
the Company's common stock. The Company does not believe that listings of bid
and asking prices for its stock are indicative of the actual trades of its
stock, since trades are made infrequently. However during 2004, there was a
material increase in the number of shares traded and a material increase in the
stock price. The following table shows high and low trading prices for each
quarter in 2004, 2005, 2006 and 2006.2007.
Price Per Share
High Low
2004
First Quarter 2.00 .70
Second Quarter 1.50 1.00
Third Quarter 2.45 1.30
Fourth Quarter 2.55 1.60
2005
First Quarter 5.50 2.00
Second Quarter 3.55 2.05
Third Quarter 4.20 1.90
Fourth Quarter 4.80 3.11
2006
First Quarter 5.15 3.26
Second Quarter 6.00 4.57
Third Quarter 6.25 4.95
Fourth Quarter 7.00 4.50
2007
First Quarter 6.10 5.00
Second Quarter 6.10 4.05
Third Quarter 5.55 5.00
Fourth Quarter 5.70 5.15
During the First Quarter of 2006,2008, subsequent to year end, the following high
and low prices were recorded for the Company's common stock.
Price Per Share
High Low
20072008
First Quarter 6.106.50 5.00
There is no amount of common stock that is subject to outstanding warrants to
purchase, or securities convertible into, common stock of the Company.
As of March 31, 2007,2008, there were approximately 574566 record holders of the
Company's Common Stock.
- 31 -
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, 2007 with the cumulative total return of the Standard and
Poor's 500 Stock Index and of the Dow Jones U.S. Exploration and Production
Index (formerly Dow Jones Secondary Oil Stock Index). The comparison assumes
$100 was invested on December 31, 2003 in the Company's Common Stock and in
each of the foregoing indices and assumes reinvestment of dividends. The
Company paid no dividends on its Common Stock during the five-year period.
Stock Performance Chart
(See Chart in PDF Format filed Separately)
The Company has not paid any dividends since its reorganization and it is not
contemplated that it will pay any dividends on its Common Stock in the
foreseeable future. The Business Loan Agreement entered into between the
- 26 -
Company and JPMorgan Chase Bank for the purpose of acquiring the commercial
office building contains restrictions on the payment of dividends in the event
a default under terms of the Business Loan Agreement has occurred and is
continuing or would result from the payment of such dividends or distributions.distributions
The Registrant currently serves as its own stock transfer agent and registrar.
During the fourth quarter of the fiscal year ended December 31, 2006,2007, the
Company did not repurchase any of its equity securities. The Board of
Directors has not approved nor authorized any standing repurchase program.
- 32 -
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
2007 2006 2005 2004 2003 2003 2002
----------- ----------- ----------- ----------- -----------
Total Revenue $6,174,000$8,707,000 $ 6,174,000 $ 6,395,000 $ 4,515,000 $ 2,458,000
$ 2,084,000
Net Income (Loss) 1,808,000 920,000 1,417,000 1,266,000 987,000
382,000
Earnings per Share $ 0.24 $ 0.12 $ 0.19 $ 0.16 $ 0.13
$ 0.05
As of December 31,
2007 2006 2005 2004 2003 2002
----------- ----------- ----------- ----------- -----------
Total Assets $15,631,000 $13,024,000 $11,387,000 $ 9,715,000 $ 5,395,000
$ 3,764,000
Long-Term Debt 1,200,000 1,320,000 1,440,000 - - -
Item 7. Management's Discussion And Analysis Of Financial Condition And
Results Of Operations
Liquidity and Capital Resources
The Company's operating capital needs, as well as its capital spending program
are generally funded from cash flow generated by operations. Because future
cash flow is subject to a number of variables, such as the level of production
and the sales price of oil and natural gas, the Company can provide no
assurance that its operations will provide cash sufficient to maintain current
levels of capital spending. Accordingly, the Company may be required to seek
additional financing from third parties in order to fund its exploration and
development programs.
- 27 -
Results of Operations:
- ---------------------------------------------
2007 Compared to 2006
Oil revenues increased in 2007 over 2006 by approximately $243,000 an increase
of 18%. This was due to an increase in average oil prices from $53.14 per bbl
in 2006 to $65.17 per bbl in 2007 offset slightly by a decrease in production
from approximately 25,400 bbls in 2006 to approximately 24,500 bbls in 2007.
Decreased production of approximately 900 bbls or 3.5% came primarily from
mechanical issues associated with some of the Companies operated wells.
Gas revenue increased in 2007 from 2006 by approximately $2,118,000, an
increase of 56.9%. This was due primarily to an increase in average gas prices
from $5.55 per Mcf in 2006 to $6.63 per Mcf in 2007, combined with an increase
in production from approximately 672,000 Mcf in 2006 to approximately 881,000
Mcf in 2007, an increase of 31.1%. The majority of the increase in gas
- 33 -
production was from our new Barnett Shale horizontal gas wells. Approximately
$495,000 of the increase was from our Olex wells in Denton County, Texas. Our
new Barnett Shale horizontal gas wells accounted for approximately $1,414,000
of the increase over 2006 sales. Gas sales from non-operated wells decreased
by approximately $345,000 as compared with 2006.
Interest income is up approximately $24,000 due to the Company's policy of
investing excess cash funds in higher earning money market accounts and
certificates of deposit as opposed to checking accounts, as well as the higher
level of cash balances earning interest during 2007 as compared to 2006.
Interest rates were also slightly higher than in the previous year.
Lease operating expenses were $353,000 (17%) higher in 2007 because costs to
operate have increased. As oil and gas prices have escalated, the costs of oil
field services and equipment have also increased.
Amortization of the full cost pot (depletion) increased by approximately
$183,000 in 2007. This increase was due to the undepleted basis of the full
cost pot increasing from an estimated $8.6 million in 2006 to an estimated
$10.5 million in 2007, with the depletion rate increasing from 5.041% in 2006
to 5.883% in 2007.
General and administrative expenses increased approximately $687,000 between
years. Almost all of the increase was due to direct and indirect personnel
costs of salary, contract labor, payroll taxes, benefits and associated
expenses associated with the increased number of technical and professional
personnel added to the Company's staff during 2007. Additionally, a portion
of the increase is attributable to the outsourcing of the Company's payroll
and benefits to Administaff, a Professional Employer Organization.
The decrease in other revenues is due mainly to receipt of approximately
$24,000 more received in 2006 over the amounts received in 2007 for farm-outs
of leasehold interests held by the Company.
The increase in interest expense for 2007 was due to approximately $48,000 of
interest expense paid to interest owners on funds that had been suspended
awaiting the completion of title work to determine and verify the ownership of
the respective interests.
2006 Compared to 2005
Oil revenues increased in 2006 over 2005 by approximately $233,000, an increase
of 20.8%. This was due to an increase in average oil prices from $52.50 per
bbl in 2005 to $53.14 per bbl in 2006 combined with an increase in production
from approximately 21,300 bbls in 2005 to approximately 25,400 bbls in 2006.
Increased production of approximately 4,000 bbls came primarily from the King-
Lowe, Peters #1, Pope 1&2 and Sharp 1-18 wells, all operated wells.
Gas revenue decreased in 2006 from 2005 by approximately $698,000, a decrease
of 15.7%. This was due primarily to a decrease in average gas prices from
$6.74 per mcf in 2005 to $5.55 per mcf in 2006. The decrease in price was
offset by an increase in production from approximately 656,000 mcf in 2005 to
approximately 672,000 mcf in 2006. Approximately 25,800 mcf of the increase
- 34 -
was due to the following non-operated wells; three new Tuit Draw wells in
Wyoming (12,200 mcf), the Giant Energy Porter #2 a new well (4,622 mcf), and
the Strauch #1, a new well (14,700 mcf). Several operated wells in Texas and
Louisiana had decreased production in 2006 of approximately 9,800 mcf as
compared with 2005. These wells were shut for a portion of 2006, due to
pipeline problems, salt water disposal well issues and other mechanical
problems that will be addressed as soon as practicable.
Interest income is up due to the Company's policy of investing excess cash
Fundsfunds in higher earning money market accounts and certificates of deposit as
opposed to checking accounts, as well as the higher level of cash balances
earning interest in 2006 as compared to 2005. Interest rates were also
slightly higher than in the previous year.
Lease operating expenses were higher in 2006 because costs to operate have
increased. As oil and gas prices have escalated, operating cost, costs of
oil field services and equipment have also increased.
Amortization of the full cost pot (depletion) decreased by approximately
$267,000 in 2006. This decrease was due to a decrease in the calculated basis
of the full-cost pot for the cost to develop undeveloped reserves from an
estimated $13 million in 2005 to an estimated $4$5 million in 2006. The decrease
in the estimated future development cost more than offset the depletion rate
increase from 4.2% in 2005 to 5.04% in 2006.
General and administrative expenses increased approximately $400,000 between
years. Almost all of the increase was due to direct and indirect personnel
costs of salary, contract labor, payroll taxes, benefits and associated
expenses associated with the increased number of technical and professional
personnel added to the Company's staff during 2006. Additionally, a portion
of the increase is attributable to the outsourcing of the Company's payroll
and benefits to Administaff.
The decrease in other revenues is due mainly to receipt of approximately
$24,000 more received in 2005 over the amounts received in 2006 for farm-outs
of leasehold interests held by the Company.
- 28 -
The increase in interest expense for 2006 was due to approximately $48,000 of
interest expense paid to interest owners on funds that had been suspended
awaiting the completion of title work to determine and verify the ownership of
the respective interests.
2005 Compared to 2004
Both oil and gas revenues increased for the year 2005. This was due primarily
to an approximate 24% increase in average gas prices from $5.44 per Mcf in 2004
to $6.74 per Mcf in 2005. Average oil prices received by the Company also
increased approximately 35% from $38.93 per bbl in 2004 to $52.50 in 2005.
Natural gas production was approximately 656,000 Mcf in 2005 compared to
approximately 577,000 in 2004, an increase of approximately 14%. The increased
gas production was due primarily to production added by the Olex wells in
Denton County, Texas which were completed early in 2005. Oil production was
approximately 21,300 bbls in 2005 compared to 23,000 bbls in 2004. an
approximate decrease 7%. This decrease in production was due primarily to the
curtailment of oil production in South Texas due to problems with some salt
water disposal facilities which the Company intends to correct during 2006.
Gas gathering and compression fee income was up slightly during 2005 as a
result of an increase in production from properties served by PPC. The
Company charges a fee for transportation of gas from the well site to the
purchaser's pipeline, and in some cases provides and charges for compression
services.
Interest income is up due to the Company's policy of investing excess cash
funds in higher earning money market accounts and certificates of deposit as
opposed to checking accounts, as well as the higher level of cash balances
earning interest in 2005 as compared to 2004. Interest rates were also
slightly higher than in the previous year.
Lease operating expenses were higher in 2005 because costs to operate have
increased. As oil and gas prices have escalated, operating cost, costs of oil
field services and equipment have also increased.
Amortization of the full cost pot (depletion) was up in 2005 due to an increase
in the cost of acquisitions and the projected cost to develop the proved
undeveloped reserves which were added to the full cost pot. In addition,
$230,000 was added to the depletable basis due to the implementation of FAS143
for the addition of the asset retirement obligation. The depletion rate also
increased from 4.2% in 2004 to 4.7% in 2005.
General and administrative expenses increased approximately $222,000 due to
direct and indirect personnel costs of salary, contract labor, payroll taxes,
benefits and associated expenses associated with the increased number of
personnel from twelve to fourteen full-time and from 44 to 48 part time and
contract employees. General liability insurance premium increases account
for the additional increases.
The increase in other revenues is due mainly to a $96,000 paid to the Company
for a farm-out of leasehold interest held by the Company, and approximately
$18,000 of plant product sales by PPC.
- 29 -
Interest expense for 2005 was due to the note payable incurred on December 27,
2004 for purchase of the Commercial office building.
Certain Factors That Could Affect Future Operations
- ---------------------------------------------------
Certain information contained in this report, as well as written and oral
statements made or incorporated by reference from time to time by the Company
and its representatives in other reports, filings with the Securities and
Exchange Commission, press releases, conferences, teleconferences or otherwise,
may be deemed to be 'forward-looking statements' within the meaning of Section
21E of the Securities Exchange Act of 1934 and are subject to the 'Safe Harbor'
provisions of that section.
-35 -
Forward-looking statements include statements concerning the Company's and
management's plans, objectives, goals, strategies and future operations and
performance and the assumptions underlying such forward-looking statements.
When used in this document, the words "anticipates", "estimates", "expects",
"believes", "intends", "plans", and similar expressions are intended to
identify such forward-looking statements. Actual results and developments
could differ materially from those expressed in or implied by such statements
due to these and other factors.
Item 8. Consolidated Financial Statements And Schedules Index At Page 4248
Item 9. Changes In And Disagreements With Accountants On Accounting And
Financial Disclosure
None
Item 9A(T). Controls And Procedures
Evaluation of Disclosure Controls and Procedures
A review and evaluation was performed by management under the supervision and
with the participation of the Acting Principal Executive Officer and Chief
Financial Officer of the effectiveness of the Company's disclosure controls and
procedures, as required by Rule 13a-15(b) of the Securities Exchange Act of
1934 as of December 31, 2006.2007. Based upon that most recent evaluation, which
was completed as of the end of the period covered by this Form 10-K, the
Acting
Principal Executive Officer and Chief Financial Officer concluded that the
Company's disclosure controls and procedures were effective at December 31,
20062007 to ensure that information required to be disclosed in reports that the
Company files submits under the Securities Exchange Act of 1934 is recorded,
processed, summarized and timely reported as provided in the Securities and
Exchange Commission ("SEC") rules and forms. As a result of this evaluation,
there were no significant changes in the Company's internal control over
financial reporting during the three months ended December 31, 20062007 that have
materially affected or are reasonably likely to materially affect the Company's
internal control over financial reporting.
- 30 -
Management Report on Internal Control Over Financial Reporting
Management of the Company is responsible for establishing and maintaining
adequate internal control over financial reporting as defined in Rules 13a-15(b)13a-
15(b) and 15d-15(f) under the Securities Exchange Act of 1934, as amended, as
a process designed by, or under the supervision of the Company's principal
executive and principal financial officers and effected by the Company's board,
management and other personnel to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with accounting principles generally
accepted in the United States ("GAAP, US") and includes those policies and
procedures that:
- 36 -
- pertain to the maintenance of records that in reasonable detail
accurately and fairly reflect the transactions and dispositions of the assets
of a company;
- provide reasonable assurance that the transactions are recorded as
necessary to permit preparation of financial statements in accordance with
GAAP, US and that receipts and expenditures of a company are being made only in
accordance with authorization of management and directors of a company; and
- provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of a company's assets that could
have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial
reporting, including the possibility of human error and the circumvention or
overriding of controls, material misstatements may not be prevented or detected
on a timely basis. Projections of any evaluation of effectiveness to future
periods are subject to the risks that controls may become inadequate because of
changes and conditions or that the degree of compliance with policies or
procedures may deteriorate. Accordingly, even internal controls determinedetermined to
be effective can provide only reasonable assurance that information required to
be disclosed in and reports filed under the Securities Exchange Act of 1934 is
recorded, processed, summarized and represented within the time periods
required.
This annual report does not include an attestation report of the Company's
registered public accounting firm regarding internal control over financial
reporting. Management's report was not subject to attestation by the Company's
registered public accounting firm pursuant to temporary rules of the SEC that
permit the Company to provide only management's report in this annual report.
Changes in Internal Control Over Financial Reporting.
There has been no change in the Registrant's internal control over financial
reporting during the fourth fiscal quarter ended December 31, 2006,2007, that has
materially affected, or is reasonably likely to materially affect, the
Registrant's internal control over financial reporting.
Item 9B. Other Information
Not Applicable
- 3137 -
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 4950 Chairman of the Board, Director and
President
Michelle H. Mazzini 4546 Director, Vice President, Secretary,
Treasurer
PaulDavid E. Cash 74Allard 49 Director
On April 2, 2008, Mr. David E. Allard, was appointed as a member of the Board
of Directors of Spindletop Oil & Gas Co.
All directors hold offices until the next annual meeting of the shareholders or
until their successors are duly elected and qualified. Officers of the Company
serve at the discretion of the board of directors.
Business Experience
- -------------------
Chris Mazzini, Chairman of the Board of Directors and President, graduated from
the University of Texas at Arlington in 1979 with a Bachelor of Science degree
in geology. He started his career in the oil and gas industry in 1978, and
began as a petroleum geologist with Spindletop in 1979, working the Fort Worth
Basin of North Texas. He became Vice President of Geology at Spindletop in
1982, and served in that capacity until he left the Company in 1985 when he
founded Giant Energy Corp. ("Giant"). Mr. Mazzini has served as President of
Giant since then. He rejoined the Company in December 1999 when he, through
Giant, purchased controlling interest from Mr. Cash.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
transactions. She also worked as Corporate Counsel for Alcatel USA, a global
telecommunications manufacturing corporation where her practice was broad-based.broad-
based. Ms. Mazzini serves as Vice President and General Counsel of the
Company.
- 3238 -
PaulDavid E. Cash,Allard, Director, has served as Chief Financial Officer (since
February 2005) 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 TCI subsidiary); Senior Vice President and Vice
President-Business Development (1992-1996) of Westcott 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 is a graduateDirector
(since February 20, 2004) and Chairman of The Universitythe Audit Committee of the Board of
Income Opportunity Realty Investors, Inc. a Dallas, Texas (B.B.A.-
Accounting)based real estate
company which has its common stock listed and istraded on the American Stock
Exchange. Mr. Allard has been a Certified Public Accountant. He has been active in the
oil and gas industry for over 40 years, during which time he has served as
financial officer of two publicly-owned companies, Texas Gas Producing Co. and
Landa Oil Co., and also served as president of publicly-owned Continental
American Royalty Co., Bloomfield Royalty Co., Southern Bankers Investment Co.,
Spindletop Oil & Gas Co. (a Utah Corporation), Double River Oil & Gas Co., and
Loch Exploration Inc. He has also been an officer and part owner of several
private oil and gas companies and partnerships. Mr. Cash also formerly served
as Mayor of the City of Sunnyvale, Texas.Accountant since 1983.
Key Employees
In addition to the services provided through the management contract with
Giant by Mr. Mazzini, Ms. Mazzini (both of whom have biographies listed above)
and the services of another Giant employee, the Company also relies extensively
on the key employees identified below.
Robert E. Corbin, Controller, has been a full-time employee of Spindletop since
April 2002. From May 2001 until April 2002, Mr. Corbin was an independent
accounting consultant and devoted substantially all of his time to Spindletop.
He has been active in the oil and gas industry for over 3233 years, during which
time he has served as financial officer of a publicly-held company as well as
several private oil and gas companies and partnerships. Mr. Corbin graduated
from Texas Tech University in 1969 with a BBA degree in accounting and began
his accounting career as an auditor with Arthur Andersen & Co. in 1970.
Mr. Corbin is a Certified Public Accountant.
Mark Cook, Petroleum Geologist, joined the Company in November 2006. He has
over 2829 years experience in the oil and gas industry. Mr. Cook graduated from
The University of Texas at San Antonio in 1983 with a Bachelor of Science in
Geology. He has extensive experience in the Continental United States with a
focus in the Fort Worth Basin and Bend Arch region. Mr. Cook has worked as
Chief Geologist for Raw Energy Corp.Corp, in Weatherford, Texas,Texas; McClymond, LTD of
Breckenridge, Texas, and as a personal Geologist for Mr. Tex Moncrief, in Fort
Worth, Texas. Mr. Cook is a Licensed Professional Geoscientist in the state
of Texas.
Mike Keen, Operations Manager, joined the Company in March, 2006. Mr. Keen
has over 2627 years experience in the oil and gas industry. He graduated magna
cum laude from Rose-Hulman Institute of Technology in May 1975 with a Bachelor
of Science degree in Mechanical Engineering. Mr. Keen started his career with
Texaco, Inc. in Great Bend, Kansas working primarily in the mid-continent area.
Mr. Keen then moved to North Texas and went to work for Mitchell Energy
Corporation primarily focusing on the Fort Worth Basin. He also worked for
Huffco in Indonesia, Aminoil in South Texas and most recently for Envirogas,
primarily in the Appalachian and Illinois Basins, before switching to the
- 39 -
"downstream" side of the industry to work for Indiana Gas Company the largest
gas utility in Indiana at the time.
Dick A. Mastin, Petroleum Landman, has been a full-time employee of the Company
since February, 2006. Mr. Mastin graduated cum laude from Stephen F. Austin
State University in 1980 with a Bachelor of Science in Forestry and a minor in
General Business. From September of 1980 until December of 1985, Mr. Mastin
- 33 -
worked for Spindletop Oil & Gas Co. as a Petroleum Landman. He received his
Masters of Science in Management and Administrative Sciences from the
University of Texas at Dallas in 1990. In January of 1987, he took a position
with the Dallas office of the Federal Bureau of Investigation. After a year
with the Bureau, he accepted a position with the Internal Revenue Service as a
Revenue Agent. Fifteen of his eighteen years with the Service were spent in
the Large and Mid-Sized Business unit auditing tax returns of the largest
business entities.
Glenn E. Sparks is the Land Director and also acts as Associate General Counsel
to the Company. Mr. Sparks was previously employed as a Landman by the Company
from 1982 through 1986, prior to attending law school. Mr. Sparks holds a
B.B.A. with a concentration in Finance from the University of Texas at
Arlington, and a J.D. from Texas Tech University School of Law. From 1990 to
2005, Mr. Sparks practiced law in a private practice focusing primarily on oil
and gas law and real estate, as a partner in the law firm of Logan & Sparks,
PLLC, and has acted as outside legal counsel for the Company in numerous oil
and gas transactions during his years in private practice. Mr. Sparks left his
private law practice and joined the Company again as an employee in his current
position in 2005. Mr. Sparks is Board Certified in Oil & Gas Mineral Law by
the Texas Board of Legal Specialization.
Family Relationships
Michelle Mazzini, Vice President, Secretary and General Counsel is the wife of
Chris Mazzini, Chairman of the Board and President.
Involvement in Certain Legal Proceedings
None of the directors or executive officers of the Registrant, during the past
five years, has been involved in any civil or criminal legal proceedings,
bankruptcy filings or has been the subject of an order, judgment or decree of
any Federal or State authority involving Federal or State securities laws.
Item 11. Executive Compensation
Cash Compensation
- -----------------
For the years ended December 31, 2007, 2006 2005 and 2004,2005, neither Mr. Mazzini nor
Ms. Mazzini received any salary from the Company. None of the executive
officers were paid cash compensation by the Company at an annual rate in excess
of $100,000. Mr. Mazzini and Ms. Mazzini are both employed by Giant.
Management fees the Company paid to Giant are used to reimburse a portion of
- 40 -
Mr. Mazzini's, Ms. Mazzini's and other Giant employees' salaries for time spent
working on matters for the Company.
The Company has no stock option or incentive plan, does not grant any plan-basedplan-
based awards or awards of equity securities. The Company has no pension plan
for its employees.
- 34 -
Compensation Pursuant to Plan
None
Other Compensation
Key employees and officers of the Company may sometimes be assigned overriding
royalty interests and/or carried working interestinterests in prospects acquired by or
generated by the Company. These interests normally vary from less than one
percent to three percent for each employee or officer. There is no set formula
or policy for such program, and the frequency and amounts are largely
controlled by the economics of each particular prospect. We believe that these
types of compensation arrangements enable us to attract, retain and provide
additional incentives to qualified and experienced personnel
Effective March 22, 2007, the Company issued 5,000 shares of restricted common
stock to a key employee pursuant to an employment package. The shares were
valued at $2.12 per share, a 60% discount from the believed market value for
free trading shares at the time of issue of $5.30 per share. The discount was
determined based in part on the fact that the shares were restricted and could
not be sold or traded for at least one year from date of issue. The amount was
expensed as general and administrative expense. The shares of common stock
were issued out of Treasury Stock and reduced the amount of the Company's
common stock held in Treasury from 81,668 to 76,668 shares. This transaction
was recorded in accordance with FAS 123-R that became effective January 1,2006.
Effective August 15, 2007, the Company issued 10,000 shares of restricted
common stock to a key employee pursuant to an employment package. The shares
were valued at $2.10 per share, a 60% discount from the believed market value
for free trading shares at the time of issue of $5.25 per share. The discount
was determined based in part on the fact that the shares were restricted and
cannot be sold or traded for at least one year from date of issue. The amount
was expensed as general and administrative expense. The shares of common stock
were issued out of Treasury Stock and reduced the amount of the Company's
common stock held in Treasury from 76,668 to 66,668 shares. This transaction
was recorded in accordance with FAS 123-R that became effective January 1,2006.
During 2006, the Company issued 10,000 shares of restricted common stock out of
Treasury Stock to a key employee, and during 2005, the Company issued 20,000
shares of restricted stock out of Treasury Stock to the same employee pursuant
to an employment package. Subsequent to year end, in March, 2007, the Company
issued 5,000 shares of restricted common stock out of Treasury Stock to a
second key employee, pursuant to an employment package. See Footnote No. 7, to the Financial Statements for
further detail.
- 41 -
Compensation of Directors
Directors who are employees of either Giant or the Company are not currently
compensated nor are there plans to compensate them for their services on the board. In 2008, Mr. Allard was paid a
director's fee of $10,000 to compensate him for his position as the Board of
Directors' Financial Expert. Mr. Allard will also receive $2,500 for each board
of directors meeting during the year. In each of 2007 and 2006, Mr. Paul E.
Cash (a director who resigned on October 31, 2007) was paid a director's fee for the previous year
of $10,000 to compensate him for his position as the Board of Directors'
Financial Expert.
Termination of Employment and Change of Control Arrangement
There are no plans or arrangements for payment to officers or directors upon
resignation or a change in control of the Registrant.
Item 12. Security Ownership Of Certain Beneficial Owners And Management
Security Ownership of Certain Beneficial Owners and Managers
The table below sets forth the information indicated regarding ownership of the
Registrant's common stock, $.01 par value, the only outstanding voting
securities, as of December 31, 20062007 with respect to: (i) any person who is
known to the Registrant to be the owner of more than five percent (5%) of the
Registrant's common stock; (ii) the common stock of the Registrant beneficially
owned by each of the directors of the Registrant and, (iii) by all officers
and directors as a group. Each person has sole investment and voting power
with respect to the shares indicated, except as otherwise set forth in the
footnotes to the table.
-35 -
Pct Based On
Nature of Outstanding
Name and Address Number Beneficial Percent of
Of Beneficial Owner of Shares Ownership Class
- ----------------------------------- -------------- ----------- ---------------
Chris Mazzini and Michelle Mazzini 5,900,543 (1) 77%
12850 Spurling Rd., Suite 200
Dallas, Texas 75230
Paul E. Cash 291,968 Direct 4%
12850 Spurling Rd., Suite 200
Dallas, Texas 75230All officers and directors
as a group 5,900,543 77%
West Coast Asset Management, Inc. 419,652624,612 (2) 5%8%
Paul J. Orfalea
Lance W. Helfert
R. Atticus Lowe
2151 Alessandro Drive, #100
Ventura, CA 93011
All officers and directors
as a group 6,192,511 81%93001
- 42 -
(1) Chris Mazzini directly owns 39,654 shares (1%). Giant Energy Corp.,
directly owns 5,860,889 shares (76%). Chris Mazzini owns 100% of the common
stock of Giant Energy Corp.
(2) According to Amendment No. 1 to Schedule 13G filed with the Commission by
these persons for event occurring January 24,December 31, 2007, each of the individually
named persons have shared power to vote or direct a vote as well as shared
power to dispose or direct the disposition of the aggregate amount of stock
owned.
Changes in control
- ----------------------------------
The Company is not aware of any arrangements or pledges with respect to its
securities that may result in a change in control of the Company.
Item 13. Certain Relationships And Related Transactions
Transactions with management and others
- ---------------------------------------
Certain officers, directors and related parties, including entities controlled
by Mr. Mazzini, the President and Chief Executive Officer, have engaged in
business transactions with the Company which were not the result of arm's
length negotiations between independent parties. Our management believes that
- 36 -
the terms of these transactions were as favorable to us as those that could
have been obtained from unaffiliated parties under similar circumstances. All
future transactions between us and our affiliates will be on terms no less
favorable than could be obtained from unaffiliated third parties and will be
approved by a majority of the disinterested members of our Board of Directors.
There is a management services agreement between Giant Energy Corp. ("Giant")
and the Company. Details of the agreement are shown below under Certain
Business Relationships.
During 2005 the Company participated in the drilling of the Giant Energy Corp.
Porter #2 well, a vertical Barnett Shale well in Parker County, Texas, which
was completed in June 2005 with an initial production of 128 thousand cubic
feet of gas per day ("MCFG/D") and 1 barrel of oil per day ("BO/D"). The
Company owns a 35% working interest and a 26.25% net revenue interest in the
Porter #2 well. Giant Energy Corp owns a 19% working interest (15.2% net revenue interest)
and Chris Mazzini owns a 3.9% overriding royalty interest in the well.
Chris G. Mazzini and Michelle H. Mazzini, through a limited partnership in
which they are limited partners, startedown M-R Oilfield Services, LP ("MRO"), an oil
field service company which provides roustabout, swabbing and completion
services at rates which are at or below market to the Company. The oil field service company plans to expand
equipment and services they provide. This oil field
services company does work exclusively for the Company and its parent company
Giant Energy Corp. The Company benefits by having immediate access to services
in a tight market.
- 43 -
The Company and Giant have entered into a joint Barnett Shale horizontal
drilling and development program dated August 22, 2006, and later amended on
October 20, 2006 (the "Agreement") with an unrelated third party company. (See
"Joint Drilling Development of North Texas Barnett Shale Leasehold" on page 6).
Certain Business Relationships
- ------------------------------
The long-term debt, which is secured by the commercial office building, is
also guaranteed individually by Chris G. Mazzini and Michelle H. Mazzini,
related parties.
There is a management services agreement between Giant and the Company which
has been in effect since 1999. This agreement provides monthly payments from
the Company to Giant in the amount of $20,000 in exchange for several of
Giant's personnel providing management, administrative and other services to
the Company and for the use of certain Giant assets. We believe the management
services agreement described above was made on terms no less favorable than if
we had entered into the transaction with an unrelated party.
The Company has entered into a management services agreement with M-R Oilfield
Services, LP ("MRO")MRO whereby
MRO makes monthly payments in the amount of $1,000 per month to the Company in
exchange for the Company providing administrative services to MRO. The Company
has entered into a similar arrangement with Peveler Pipeline, LP ("Peveler"),
whereby Peveler pays the Company a monthly charge of $200 in exchange for the
Company providing administrative services to Peveler. Chris and Michelle
Mazzini are the owners of Peveler Pipeline, LP, a limited partnership which
owns a pipeline gathering system servicing wells owned by Giant, another
related entity, described elsewhere in this report.
Key employees and officers of the Company may sometimes be assigned overriding
royalty interests and/or carried working interests in prospects acquired by or
generated by the Company. These interests normally vary from less than one
- 37 -
percent to three percent for each employee or officer. There is no set
formula or policy for such program, and the frequency and amounts are largely
controlled by the economics of each particular prospect. We believe that
these types of compensation arrangements enable us to attract, retain and
provide additional incentives to qualified and experienced personnel.
Item 14. Principal Accounting Fees And Services
The following table sets forth the aggregate fees for professional services
rendered to Spindletop Oil & Gas Co. and Subsidiaries for the years 2007, 2006
2005
and 20042005 by accounting firm, Farmer, Fuqua, & Huff, P.C.
Type of Fees 2007 2006 2005
2004
Audit Fees $14,000$33,000 $14,000 $14,000
Audit related fees - - -
Tax fees - - -
All other fees - - -
Members of the Board of Directors (the "Board") fulfill the responsibilities
Ofof an audit committee and have established policies and Procedures for the
approval and pre-approval of audit services and permitted non-audit services.
The Board has the responsibility to engage and terminate Farmer, Fuqua, & Huff,
P.C. independent auditors, to pre-approve their performance of audit services
and permitted non-audit services, to approve all audit and non-audit fees, and
to set guidelines for permitted non-audit services and fees. All the fees for
2007, 2006 2005 and 20042005 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.
- 3844 -
PART IV
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as a part of this report:
(1) FINANCIAL STATEMENTS: The following financial statements of the
Registrant and Report of Independent Registered Public Accounting Firm
therein are filed as part of this Report on Form 10-K:
Page
Report of Farmer, Fuqua & Huff, P.C
Independent Registered Public Accounting Firm 4349
Consolidated Balance Sheets 4450
Consolidated Statement of Income 4652
Consolidated Statement of Changes in
Stockholders' Equity 4753
Consolidated Statements of Cash Flows 4854
Notes to Consolidated Financial Statements 4955
(2) FINANCIAL STATEMENT SCHEDULES: Other financial statement schedules
have been omitted because the information required to be set forth
therein is not applicable, is immaterial or is shown in the consolidated
financial statements or notes thereto.
(3) EXHIBITS
The following documents are filed as exhibits (or are incorporated by reference
as indicated) into this Report:
Exhibit
Designation Description
3.1 Articles of Incorporation of Spindletop Oil & Gas Co. (previously
filed with our General Form for Registration of Securities on
Form 10, filed with the Commission on August 14, 1990)
3.2 Bylaws of Spindletop Oil & Gas Co. (previously filed with our
General Form for Registration of Securities on Form 10, filed
with the Commission on August 14, 1990)
14*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).
- 45 -
21* Subsidiaries of the Registrant
- 39 -
31.1* Rule 13a-14(a) Certification of Chief Executive Officer
31.2* Rule 13a-14(a) Certification of Chief Financial Officer
32* Officers' Section 1350 Certifications
- -----------------------------
* Filed herewith
(b) The Index of Exhibits is included following the Financial Statement
Schedules beginning at page 5277 of this Report.
(c) The Index to Consolidated Financial Statements and Supplemental Schedules
is included following the signatures, beginning at page 2848 of this Report.
- 4046 -
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the CompanyRegistrant has duly caused this Report to be signed on its
behalf by the undersigned, thereunto duly authorized.
SPINDLETOP OIL & GAS CO.
Dated: April 16, 200714, 2008
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 CompanyRegistrant
and in the capacities and on the dates indicated.
Signatures Capacity Date
Principal Executive Officers:
/s/ Chris Mazzini
_____________________________________________________________________ President, Director April 16, 200714, 2008
Chris Mazzini (Principal(Chief Executive
Officer)
/s/ Michelle Mazzini
_____________________________________________________________________ Vice President, Secretary, April 16, 200714, 2008
Michelle Mazzini Secretary, Treasurer, Director
/s/ David E. Allard
__________________________________ Director April 14, 2008
David E. Allard
/s/ Robert E. Corbin
_____________________________________________________________________ Controller (Principal April 16, 200714, 2008
Robert E. Corbin Financial and Accounting
Officer)
/s/ Paul E. Cash
___________________________________ Director April 16, 2007
Paul E. Cash
- 4147 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
Index to Consolidated Financial Statements and Schedules
Page
Report of Independent Registered Public Accounting Firm 4349
Consolidated Balance Sheets - December 31, 2007 and 2006 and 2005 4450
Consolidated Statements of Income for the years
Ended December 31, 2007, 2006 and 2005 and 2004 4652
Consolidated Statements of Changes in Shareholders'
Equity for the years ended December 31, 2007, 2006, 2005, and 2004. 472005. 53
Consolidated Statements of Cash Flows for the years ended
December 31, 2007, 2006 and 2005 and 2004 4854
Notes to Consolidated Financial Statements 4955
Schedules for the years ended December 31, 2007, 2006 2005 and 20042005
II - Valuation and Qualifying Accounts 6975
III - Real Estate and Accumulated Depreciation 7076
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.
- 4248 -
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, 20062007 and
2005,2006, and the related consolidated statements of income, shareholders' equity
and cash flows for each of the years in the three-year period ended December
31, 2006. These2007. Spindletop Oil & Gas Co.'s management is responsible for these
consolidated financial statements are the
responsibility of the company's management.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. The
company is not required to have, nor were we engaged to perform, an audit of
its internal control over financial reporting. Our audit included
consideration of internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of the company's
internal control over financial reporting. Accordingly, we express no such
opinion. An audit also includes examining, on a test basis, evidence
supporting the amounts and disclosures in the consolidated financial
statements, assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Spindletop Oil &
Gas Co. and subsidiaries as of December 31, 20062007 and 2005,2006, and the consolidated
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 20062007 in conformity with accounting
principles generally accepted in the United States of America.
Our audits were made for the purpose of forming an opinion on the basic
consolidated financial statements taken as a whole. The schedules listed in the
index of 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.
FARMER, FUQUA & HUFF,/s/ Farmer, Fuqua and Huff, P.C.
Plano, Texas
April 13, 200714, 2008
- 4349 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31
--------------------------
2007 2006 2005
----------- -----------
ASSETS
Current Assets
Cash and cash equivalents $ 5,759,0006,325,000 $ 5,508,0005,759,000
Accounts receivable, trade 1,413,000 1,173,000 1,228,000
Prepaid expenses, related party - 60,000 -
Prepaid income tax - 426,000 -
----------- -----------
Total current assets 7,738,000 7,418,000 6,736,000
----------- -----------
Property and Equipment, at cost
Oil and gas properties (full cost method) 11,041,000 8,102,000 6,819,000
Rental equipment 399,000 399,000
Gas gathering systems 145,000 145,000
Other property and equipment 183,000 141,000 157,000
----------- -----------
11,768,000 8,787,000 7,520,000
Accumulated depreciation and amortization (5,902,000) (5,257,000) (4,807,000)
----------- -----------
Total property and equipment, net 5,866,000 3,530,000 2,713,000
----------- -----------
Real Estate Property, at cost
Land 688,000 688,000
Commercial office building 1,542,000 1,508,000 1,298,000
Accumulated depreciation (204,000) (120,000) (49,000)
----------- -----------
Total real estate property, net 2,026,000 2,076,000 1,937,000
----------- -----------
Other Assets 1,000 - 1,000
----------- -----------
Total Assets $15,631,000 $13,024,000 $11,387,000
=========== ===========
The accompanying notes are an integral part of these statements.
- 4450 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - (Continued)
As of December 31
--------------------------
2007 2006 2005
----------- -----------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable, current portion $ 120,000 $ 120,000
Accounts payable and accrued liabilities 2,272,000 2,237,000 1,943,000
Income tax payable 8,000 - 20,000
Tax savings benefit payable 97,000 97,000
----------- -----------
Total current liabilities 2,497,000 2,454,000 2,180,000
----------- -----------
NoncurrentNon-current Liabilities
Notes payable, long-term portion 1,200,000 1,320,000 1,440,000
Asset Retirement Obligation 564,000 251,000 239,000
----------- -----------
Total noncurrentnon-current liabilities 1,764,000 1,571,000 1,679,000
----------- -----------
Deferred income tax payable 1,855,000 1,324,000 794,000
----------- -----------
Shareholders' Equity
Common stock, $.01 par value; 100,000,000
Shares authorized; 7,677,471 shares
issued and 7,610,803 shares outstanding
at December 31, 2007; 7,677,471 shares
issued and 7,595,803 shares outstanding at
December 31, 2006. 7,667,471 shares
issued and 7,585,803 shares outstanding at
December 31, 2005. 77,000 77,000
Additional paid-in capital 874,000 850,000 831,000
Treasury Stock at cost (32,000) (40,000) (42,000)
Retained earnings 8,596,000 6,788,000 5,868,000
----------- -----------
Total shareholders' equity 9,515,000 7,675,000 6,734,000
----------- -----------
Total Liabilities and Shareholders' Equity $15,631,000 $13,024,000 $11,387,000
=========== ===========
The accompanying notes are an integral part of these statements.
- 4551 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Years Ended December 31,
-----------------------------------
2007 2006 2005 2004
----------- ----------- -----------
Revenues
Oil and gas revenue $ 7,437,000 $ 5,076,000 $ 5,541,000 $ 4,039,000
Revenue from lease operations 212,000 154,000 120,000 127,000
Gas gathering, compression and
Equipment rental 179,000 140,000 167,000 158,000
Real estate rental income 512,000 430,000 302,000
3,000
Interest income 299,000 275,000 132,000
100,000
Other 68,000 99,000 133,000 88,000
----------- ----------- -----------
Total revenue 8,707,000 6,174,000 6,395,000 4,515,000
----------- ----------- -----------
Expenses
Lease operations 2,459,000 2,106,000 1,747,000 1,235,000
Pipeline and rental operations 49,000 50,000 29,000 24,000
Real estate operations 365,000 330,000 484,000 2,000
Depreciation and amortization 728,000 528,000 795,000 498,000
Accretion of asset retirement obligation 24,000 34,000 - -
General and administrative 2,221,000 1,534,000 1,125,000
903,000
Interest expense 86,000 142,000 105,000 -
----------- ----------- -----------
Total expenses 5,932,000 4,724,000 4,285,000 2,662,000
----------- ----------- -----------
Income before income tax 2,775,000 1,450,000 2,110,000 1,853,000
----------- ----------- -----------
Current tax provision 436,000 - 360,000 144,000
Deferred tax provision 531,000 530,000 333,000 443,000
----------- ----------- -----------
967,000 530,000 693,000 587,000
----------- ----------- -----------
Net income $ 1,808,000 $ 920,000 $ 1,417,000 $ 1,266,000
=========== =========== ===========
Earnings per Share of Common Stock
Basic $ 0.24 $ 0.12 $ 0.19 $ 0.16
=========== =========== ===========
Diluted $ 0.24 $ 0.12 $ 0.19 $ 0.16
=========== =========== ===========
Weighted Average Shares Outstanding 7,604,269 7,589,995 7,573,365 7,567,875
=========== =========== ===========
Diluted Shares Outstanding 7,604,269 7,589,995 7,573,365 7,592,670
=========== =========== ===========
The accompanying notes are an integral part of these statements.
- 4652 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2007, 2006 2005 and 20042005
Additional Treasury
Common Stock Paid-In Stock Retained
Shares Amount Capital Shares Amount Earnings
--------- -------- ---------- -------- -------- -----------
Balance at
December 31, 2003 7,677,471 77,000 796,000 103,334 (18,000) 3,185,000
Purchase of
Treasury Stock - - - 83,334 (40,000) -
Issuance of 75,000
shares of Common Stock
upon exercise of option
out of Treasury Stock - - 10,000 (75,000) 13,000 -
Net Income - - - - - 1,266,000
--------- -------- ---------- -------- -------- -----------
Balance at
December 31, 2004 7,677,471 77,000 806,000 111,668 (45,000) 4,451,000
Issuance of 20,000
shares of Common Stock
out of Treasury Stock
as part of an employee
compensation package - - 25,000 (20,000) 3,000 -
Net Income - - - - - 1,417,000
--------- -------- ---------- -------- -------- -----------
Balance at
December 31, 2005 7,677,471 $ 77,000 $ 831,000 91,668 $(42,000)$ 5,868,000
Issuance of 10,000
shares of Common Stock
out of Treasury Stock
as part of an employee
compensation package - - 19,000 (10,000) 2,000 -
Net Income - - - - - 920,000
--------- -------- ---------- -------- -------- -----------
Balance at
December 31, 2006 7,677,471 $ 77,000 $ 850,000 81,668 $ (40,000)$(40,000)$ 6,788,000
Issuance of 5,000
shares of Common Stock
out of Treasury Stock
as part of an employee
compensation package - - 9,000 (5,000) 2,000 -
Issuance of 10,000
shares of Common Stock
out of Treasury Stock
as part of an employee
compensation package - - 15,000 (10,000) 6,000 -
Net Income - - - - - 1,808,000
--------- -------- ---------- -------- -------- -----------
Balance at
December 31, 2007 7,677,471 $ 77,000 $ 874,000 66,668 $(32,000)$ 8,596,000
========= ======== ========== ======== ======== ===========
The accompanying notes are an integral part of these statements.
- 4753 -
SPINDLETOP OIL & GAS CO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31,
-----------------------------------
2007 2006 2005 2004
----------- ----------- -----------
Cash Flows from Operating Activities
Net Income $ 1,808,000 $ 920,000 $ 1,417,000 $ 1,266,000
Reconciliation of net income
to net cash provided by
Operating Activities
Depreciation and amortization 728,000 528,000 795,000 498,000
Non-cash employee compensation 32,000 21,000 - -
Changes in prepaid expenses
to related party 60,000 (60,000) - -
Changes in accounts receivable (240,000) 55,000 (611,000) (52,000)
Changes in prepaid income tax 427,000 (426,000) 190,000 (190,000)
Changes in accounts payable 35,000 293,000 (125,000) 1,106,000
Changes in current taxes payable 8,000 (20,000) 20,000 (278,000)
Changes in deferred taxes payable 531,000 530,000 333,000
443,000Changes in asset retirement obligation 313,000 - -
Changes in other assets (1,000) 1,000 - 1,000
----------- ----------- -----------
Net cash provided by operating
activities 3,701,000 1,842,000 2,019,000 2,794,000
----------- ----------- -----------
Cash flows from Investing Activities
Capitalized acquisition, exploration
and development costs (2,940,000) (1,271,000) (619,000) (884,000)
Purchase of property and equipment (42,000) 10,000 (55,000) (18,000)
Capitalized tenant improvements (33,000) (210,000) - (185,000)
Proceeds from sale of properties - - 23,000 -
----------- ----------- -----------
Net cash used for investing activities
activities (3,015,000) (1,471,000) (651,000) (1,087,000)
----------- ----------- -----------
Cash Flows from Financing Activities
Repayment of note payable to a bank (120,000) (120,000) (240,000) -
Purchase of treasury stock - - (40,000)
Sale of common stock - - 28,000 23,000
----------- ----------- -----------
Net cash used for financing
activities (121,000)(120,000) (120,000) (212,000) (17,000)
----------- ----------- -----------
Increase in cash 566,000 251,000 1,156,000 1,690,000
Cash at beginning of period 5,759,000 5,508,000 4,352,000 2,662,000
----------- ----------- -----------
Cash at end of period $ 6,325,000 $ 5,759,000 $ 5,508,000 $ 4,352,000
=========== =========== ===========
The accompanying notes are an integral part of these statements.
- 4854 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION AND ORGANIZATION
Merger and Basis of Presentation
- --------------------------------
On July 13, 1990, Prairie States Energy Co., a Texas corporation, (the Company)
merged with Spindletop Oil & Gas Co., a Utah corporation (the Acquired
Company). The name of Prairie States Energy Co. was changed to Spindletop Oil
& Gas Co., a Texas corporation at the time of the merger.
Organization and Nature of Operations
- -------------------------------------
The Company was organized as a Texas corporation in September 1985, in
connection with the Plan of Reorganization ("the Plan"), effective
September 9, 1985, of Prairie States Exploration, Inc., ("Exploration"), a
Colorado corporation, which had previously filed for Chapter 11 bankruptcy.
In connection with the Plan, Exploration was merged into the Company, with the
Company being the surviving corporation. After giving effect to a stock split,
up to a total of 166,667 of the Company's common shares may be issued to
Exploration's former shareholders. As of December 31, 2007, 2006, 2005, and 2004,2005,
122,436 shares have been issued to former shareholders in connection with the
Plan.
Spindletop Oil & Gas Co. is engaged in the exploration, development and
production of oil and natural gas; and through one of its subsidiaries, the
gathering and marketing of natural gas.
On December 27, 2004, the Company purchased a commercial office building and
related land. The building contains approximately 46,286 of rentable square
feet, of which the Company occupies approximately 8,66810,317 rentable square feet
as its corporate office headquarters. The Company leases the remaining space
in the building to non-related third party commercial tenants at prevailing
market rates.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A summary of the significant accounting policies consistently applied in the
preparation of the accompanying financial statements follows:
Consolidation
- -------------
The consolidated financial statements include the accounts of Spindletop Oil &
Gas Co. and its wholly owned subsidiaries, Prairie Pipeline Co. and Spindletop
Drilling Company. All significant inter-company transactions and accounts have
been eliminated.
- 4955 -
Cash and Cash Equivalents
- -------------------------
The Company considers all highly liquid instruments with a maturity of three
months or less to be cash equivalents.
Allowance for Doubtful Accounts
- -------------------------------
The Company provides an allowance for doubtful accounts equal to the estimated
uncollectible portion of accounts receivable. This estimate is based on
historical collection experience and a review of the current status of accounts
receivable.
Oil and Gas Properties
- ----------------------
The Company follows the full cost method of accounting for its oil and gas
properties. Accordingly, all costs associated with acquisition, exploration
and development of oil and gas reserves are capitalized and accounted for in
cost centers, on a country-by-country basis. If unamortized costs within a
cost center exceed the cost center ceiling (as defined), the excess is charged
to expense during the year in which the excess occurs.
Depreciation and amortization for each cost center are computed on a composite
unit-of-production method, based on estimated proven reserves attributable to
the respective cost center. All costs associated with oil and gas properties
are currently included in the base for computation and amortization. Such
costs include all acquisition, exploration and development costs. All of the
Company's oil and gas properties are located within the continental United
States.
Gains and losses on sales of oil and gas properties are treated as adjustments
of capitalized costs. Gains or losses on sales of property and equipment,
other than oil and gas properties, are recognized as part of operations.
Expenditures for renewals and improvements are capitalized, while expenditures
for maintenance and repairs are charged to operations as incurred.
Property and Equipment
- ----------------------
The Company, as operator, leases equipment to owners of oil and gas wells,
on a month-to-month basis.
The Company, as operator, transports gas through its gas gathering systems,
in exchange for a fee.
Depreciation is provided in amounts sufficient to relate the cost of
depreciable assets to operations over their estimated service lives (5 to 10
years for rental equipment and gas gathering systems, 4 to 5 years for other
property and equipment). The straight-line method of depreciation is used for
financial reporting purposes, while accelerated methods are used for tax
purposes.
- 56 -
Real Estate Property
- --------------------
The Company owns land along with a two-story commercial office building which
is situated thereon. The Company occupies a portion of the building as its
primary corporate headquarters, and leases the remaining space in the building
to non-related third party commercial tenants at prevailing market rates. The
Company depreciates the commercial office using the straight-line method of
depreciation for financial statement and income tax purposes.
Investments in Real Estate and Oil and Gas Properties
- -----------------------------------------------------
All investments in oil and gas properties and in real estate holdings are
stated at cost or adjusted carrying value. Statement of Financial Accounting
- 50 -
Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets" ("SFAS No. 144"), requires that a property be considered impaired if
the sum of the expected future cash flows (undiscounted and without interest
charges) is less than the carrying amount of the property. If impairment
exists, an impairment loss is recognized by a charge against earning equal to
the amount by which the carrying amount of the property exceeds fair market
value less cost to sell the property. If impairment of a property is
recognized, the carrying amount of the property is reduced by the amount of
the impairment, and a new cost for the property is established. Depreciation
is provided over the properties estimated remaining useful life. There was no
charge to earnings during 20062007 due to impairment of oil and gas properties or
real estate holdings.
Accounting for Asset Retirement Obligations
- -------------------------------------------
The Company adopted Statement of Financial Accounting Standards No. 143 ("SFAS
143") "Accounting for Asset Retirement Obligations" on December 31, 2005. The
adoption of SFAS 143 on December 31, 2005 resulted in a cumulative effect
adjustment to record a $239,000 increase in the carrying value of oil and gas
properties, and an asset retirement obligation liability of the same amount.
This statement requires the recording of a liability in the period in which
an asset retirement obligation ("ARO") is incurred, in an amount equal to the
discounted estimated fair value of the obligation that is capitalized.
Thereafter, each quarter, this liability is accreted up to the final retirement
cost. The determination of the ARO is based on an estimate of the future cost
to plug and abandon our oil and gas wells. The actual costs could be higher or
lower than current estimates.
The following table reflects the changes of the asset retirement obligations
during the current period.period ending December 31;
2007 2006
------------ ------------
Carrying amount of asset retirement obligation at December 31, 2006$ 251,000 $ 239,000
Liabilities added 374,000 27,000
Liabilities divested or settled (85,000) (49,000)
Current period accretion expenses 24,000 34,000
---------------------- ------------
Carrying amount as of December 31, 2006$ 564,000 $ 251,000
====================== ============
- 57 -
Income Taxes
- ------------
In June, 2006, the Financial Accounting Standards Board ("FASB") issued
Interpretation No..48, "Accounting for Uncertainty in Income Taxes , an
Interpretation of SFAS No.109" ("FIN 48"). The interpretation creates a single
model to address accounting for uncertainty in tax positions. Specifically,
the pronouncement prescribes a recognition threshold and a measurement
attribute for the financial statement recognition and measurement of a tax
position taken or expected to be taken in a tax return. The interpretation
also provides guidance on de-recognition, classification, interest and
penalties, accounting in interim periods, disclosure and transition of certain
tax positions.
The Company adopted the provisions of FIN 48 effective January 1, 2007. The
adoption of this accounting principle did not have an effect on the Company's
consolidated financial statements at, and for the three years ended December
31, 2007.
The Company accounts for income taxes pursuant to Statement of Financial
Accounting Standards No. 109 "Accounting for Income Taxes" (SFAS 109), which
requires the recognition of deferred tax liabilities and assets for the
expected future tax consequences of events that have been recognized in the
Company's financial statements or tax returns. Under this method, deferred tax
liabilities and assets are determined based on the difference between the
financial statement carrying amounts and tax bases of assets and liabilities,
using enacted tax rates in effect in the years in which the differences are
expected to reverse. The temporary differences primarily relate to
depreciation, depletion and intangible drilling costs.
- 51 -
Use of Estimates
- ----------------
The preparation of financial statements in conformity with U. S. generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Share-Based Payments
- --------------------
Effective January 1, 2006, the Company adopted the Financial Accounting
Standards Board's revised Statement of Financial Accounting Standards No. 123
(FAS 123R), "Share-Based Payment". FAS 123R requires compensation costs
related to share-based payments to be recognized in the income statement over
the requisite service period. The amount of the compensation cost is to be
measured based on the grant-date fair value of the instrument issued.
FAS 123R is effective for awards granted or modified after the date of adoption
and for awards granted prior to that date that have not vested. FAS 123R does
not materially change the Company's existing accounting practices or the amount
of share-based compensation recognized in earnings.
- 58 -
3. ACCOUNTS RECEIVABLE
December 31,
----------------------------
2007 2006 2005
------------ ------------
Trade $ 530,000370,000 $ 160,000530,000
Accrued receivable 1,057,000 657,000 1,082,000
------------ ------------
1,427,000 1,187,000 1,242,000
Less: Allowance for losses (14,000) (14,000)
------------ ------------
$ 1,173,0001,413,000 $ 1,228,0001,173,000
============ ============
4. ACCOUNTS PAYABLE
December 31,
----------------------------
2007 2006 2005
------------ ------------
Trade payables $ 213,000699,000 $ 138,000213,000
Production proceeds payable 1,070,000 1,385,000 1,153,000
Prepaid drilling costs 414,000 561,000
604,000
Other 89,000 78,000 48,000
----------- ------------
$ 2,237,0002,272,000 $ 1,943,0002,237,000
=========== ============
- 52 -
5. NOTES PAYABLE
December 31,
----------------------------
2007 2006 2005
------------ ------------
Note payable to a bank with monthly
principal payments of $10,000 plus
Accrued interest; interest at a
variable annual interest rate based
upon an index which is the Treasury
Securities Rate for a term of seven
years, plus 2.20%. The interest rate
is subject to change on the first day
of each seven year anniversary after
the date of the note based on the Index
then in effect. As of the date of the
Loan, the annual interest rate was
6.11%. The note is collateralized by
land and commercial office building,
plus a guarantee by certain related
parties. $ 1,440,0001,320,000 $ 1,560,0001,440,000
Less current maturities 120,000 120,000
------------ ------------
Total notes payable, long-term portion $ 1,320,0001,200,000 $ 1,440,0001,320,000
============ ============
- 59 -
Estimated annual maturities for long-term debt are as follows:
20072008 $ 120,000
2008 120,000
2009 120,000
2010 120,000
2011 120,000
2012 120,000
thereafter 840,000720,000
-----------
$ 1,440,0001,320,000
===========
6. RELATED PARTY TRANSACTIONS
Since 1999 Giant Energy Corp. ("Giant") has charged the Company a fee pursuant
to a management services agreement. Effective January 1, 2003, this agreement
was amended to increase the monthly payments from the Company to Giant to
$20,000 in exchange for several of Giant's personnel providing management,
administrative and other services to the Company and for the use of certain
Giant assets. Giant is wholly owned by Chris Mazzini, President of the
Company. General and administrative expense for the years endedending December 31,
2007, 2006 2005 and 20042005 includes $240,000, $240,000 and $240,000, respectively,
related to this agreement. In addition, prepaid expenses, related party at
December 31, 2006 includes $60,000 related to this agreement.
The Company has entered into a management services agreement with M-R Oilfield
Services, LP ("MRO") whereby MRO makes monthly payments in the amount of $1,000
- 53 -
per month to the Company in exchange for the Company providing administrative
services to MRO. The Company has entered into a similar arrangement with
Peveler Pipeline, LP ("Peveler"), whereby Peveler pays the Company a monthly
charge of $200 in exchange for the Company providing administrative services
to Peveler. Chris Mazzini and Michelle Mazzini, President and Vice President
respectively of the Company are the owners of both MRO and Peveler.
The Company has guaranteed a $50,000 letter of credit and a $25,000 letter of
credit issued by a credit union for the benefit of two affiliated companies in
favor of the Railroad Commission of Texas. These letters of credit were issued
in accordance with the filing of a P-5 Organization Report as required by the
Texas Natural Resources Code in order to perform operations within the
jurisdiction of the Railroad Commission of Texas. These letters of credit are
secured by a restriction of certain funds of the Company on deposit at the
credit union issuing the letters of credit.
The long-term debt, which is secured by the commercial office building, is
also guaranteed individually by Chris G. Mazzini and Michelle H. Mazzini,
related parties.
The Company and Giant have entered into a joint Barnett Shale horizontal
drilling and development program dated August 22, 2006, and later amended on
October 20, 2006 (the "Agreement") with an unrelated third party company. (See
"Joint Drilling Development of North Texas Barnett Shale Leasehold" on page 6).
- 60 -
7. COMMON STOCK
Effective January 1, 2006, the Company adopted the Financial Accounting
Standards Board's revised Statement of Financial Accounting Standards No. 123
(FAS 123R), "Share-Based Payment". FAS 123R requires compensation costs
related to share-based payments to be recognized in the income statement over
the requisite service period. The amount of the compensation cost is to be
measured based on the grant-date fair value of the instrument issued.
FAS 123R is effective for awards granted or modified after the date of adoption
and for awards granted prior to that date that have not vested. FAS 123R does
not materially change the Company's existing accounting practices or the amount
of share-based compensation recognized in earnings.
Effective August 15, 2005, the Company issued 20,000 shares of restricted
common stock to a key employee pursuant to an employment package. The shares
were valued at $1.44 per share, a 60% discount from the believed market value
for free trading shares at the time of issue of $3.60 per share. The discount
was determined based in part on the fact that the shares were restricted and
could not be sold or traded for at least one year from date of issue. The
amount was expensed as general and administrative expense. The shares of
common stock were issued out of Treasury Stock and reduced the amount of the
Company's common stock held in Treasury from 111,668 to 91,668 shares.
Effective August 15, 2006, the Company issued 10,000 shares of restricted
common stock to a key employee pursuant to an employment package. The shares
were valued at $2.10 per share, a 60% discount from the believed market value
for free trading shares at the time of issue of $5.25 per share. The discount
was determined based in part on the fact that the shares were restricted and
could not be sold or traded for at least one year from date of issue. The
amount was expensed as general and administrative expense. The shares of
common stock were issued out of Treasury Stock and reduced the amount of the
Company's common stock held in Treasury from 91,668 to 81,668 shares.
- 54 -
Subsequent to year end, and effectiveEffective March 22, 2007, the Company issued 5,000 shares of restricted common
stock to a key employee pursuant to an employment package. The shares were
valued at $2.12 per share, a 60% discount from the believed market value for
free trading shares at the time of issue of $5.30 per share. The discount was
determined based in part on the fact that the shares were restricted and could
not be sold or traded for at least one year from date of issue. The amount was
expensed as general and administrative expense. The shares of common stock
were issued out of Treasury Stock and reduced the amount of the Company's
common stock held in Treasury from 81,668 to 76,668 shares. This transaction
was recorded in accordance with FAS 123-R that became effective January 1,
2006.
Effective August 15, 2007, the Company issued 10,000 shares of restricted
common stock to a key employee pursuant to an employment package. The shares
were valued at $2.10 per share, a 60% discount from the believed market value
for free trading shares at the time of issue of $5.25 per share. The discount
was determined based in part on the fact that the shares were restricted and
could not be sold or traded for at least one year from date of issue. The
amount was expensed as general and administrative expense. The shares of
common stock were issued out of Treasury Stock and reduced the amount of the
- 61 -
Company's common stock held in Treasury from 76,668 to 66,668 shares. This
transaction was recorded in accordance with FAS 123-R that became effective
January 1, 2006
8. INCOME TAXES
The Company accounts for income taxes pursuant to Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS 109).
SFAS 109 utilizes the liability method of computing deferred income taxes.
In connection with the Plan discussed in Note 1, the Company agreed to pay, in
cash, to Exploration's unsecured creditors, as defined, one-half of the future
reductions of Federal income taxes which were directly related to any allowed
carryovers of Exploration's net operating losses and investment tax credits.
Such payments are to be made on a pro-rata basis. Amounts incurred under this
agreement, which are considered contingent consideration under APB No. 16,
totaled $ -0-, $ -0-, and $ -0- in 2007, 2006 2005 and 2004,2005, respectively. As of
December 31, 20062007 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, 20062007 and 2005,2006,
the Company owes $97,000 respectively to Exploration's unsecured creditors.
In calculating tax savings benefits described above, consideration was given
to the alternative minimum tax, where applicable, and the tax effects of
temporary differences, as shown below:
Income tax differed from the amounts computed by applying an effective
U.S. federal income tax rate of 34% to pretax income in 2007, 2006 2005 and 20042005
as a result of the following:
2007 2006 2005 2004
----------- ---------- ----------
Computed expected tax expense $ 944,000 $ 493,000 $ 718,000 $ 649,000
Miscellaneous timing differences
related to book and tax depletion
differences and the expensing of
intangible drilling costs 493,000(508,000) (493,000) (358,000) (505,000)
----------- ---------- ----------
$ 436,000 $ - $ 360,000 $ 144,000
=========== ========== ==========
Deferred income taxes reflect the effects of temporary differences between the
tax bases of assets and liabilities and the reported amounts of those assets
and liabilities for financial reporting purposes. Deferred income taxes also
reflect the value of net operating losses, investment tax credits and an
- 55 -
offsetting valuation allowance. The Company's total deferred tax assets and
corresponding valuation allowance at December 31, 20062007 and 20052006 consisted of
the following:
- 62 -
December 31,
----------------------------
2007 2006 2005
------------ ------------
Deferred tax assets
Depreciation, depletion and amortization 22,000 247,000 441,000
Other, net 9,000 9,000
------------ ------------
Total 31,000 256,000 450,000
Deferred tax liabilities
Expired leasehold (58,000) (58,000)
Intangible drilling costs (1,828,000) (1,522,000) (1,186,000)
------------ ------------
Net deferred tax liability (1,855,000) (1,324,000) (794,000)
============ ============
9. CASH FLOW INFORMATION
The Company does not consider any of its assets, other than cash and
certificates of deposit shown as cash on the balance sheet, to meet the
definition of a cash equivalent.
Net cash provided by operating activities includes cash payments for interest
of $86,000, $94,000 $105,000 and $ -0-105,000 for the years 2007, 2006 2005 and 2004,2005,
respectively. Also included are cash payments for taxes of $-0-, $445,000,
and $373,000 in 2007, 2006 and $260,000
in 2006, 2005, and 2004, respectively.
Excluded from the Consolidated Statements of Cash Flows were the effects of
certain non-cash investing and financing activities, as follows:
2007 2006 2005 2004
----------- ----------- -----------
Addition (reduction) of Oil & Gas
Properties by recognition of
Asset Retirement Obligation $ 289,000 (22,000)$ 239,000 -
Purchase of land and commercial office
building in exchange for note payable - - 1,800,000
----------- ----------- -----------
$ 289,000 $ (22,000)$ 239,000 $ 1,800,000
=========== =========== ===========
10. EARNINGS PER SHARE
Earnings per share ("EPS") are calculated in accordance with Statement of
Financial Accounting Standards No. 128, Earnings per Share (SFAS 128), which
was adopted in 1997 for all years presented. Basic EPS is computed by dividing
income available to common shareholders by the weighted average number of
common shares outstanding during the period. The adoption of SFAS 128 had no
effect on previously reported EPS. Diluted EPS is computed based on the
- 56 -
weighted number of shares outstanding, plus the additional common shares that
would have been issued had the options outstanding been exercised.
- 63 -
11. CONCENTRATIONS OF CREDIT RISK
As of December 31, 2006,2007, the Company had approximately $2,418,000$5,179,000 in accounts
at one bank, including $375,000$200,000 of short term certificates of deposit and
$3,421,000approximately $2,221,000 in a second bank, including $975,000$200,000 of short-term
certificates of deposit. The Company also had $1,273,000,approximately $1,032,000,
including $960,000$1,000,000 of short-term certificates of deposit invested at twofour
other banking institutions.
Most of the Company's business activity is located in Texas. Accounts
receivable as of December 31, 20062007 and 20052006 are due from both individual and
institutional owners of joint interests in oil and gas wells as well as
purchasers of oil and gas. A portion of the Company's ability to collect these
receivables is dependent upon revenues generated from sales of oil and gas
produced by the related wells.
12. FINANCIAL INSTRUMENTS
The estimated fair value of the Company's financial instruments at December 31,
20062007 and 20052006 follow:
-------- 20062007 ------ -------- 20052006 -------
Carrying Fair Carrying Fair
Amount Value Amount Value
----------- ----------- ----------- -----------
Cash $ 6,325,000 $ 6,325,000 $ 5,759,000 $ 5,759,000
$ 5,508,000 $ 5,508,000
Accounts receivable 1,413,000 1,413,000 1,173,000 1,173,000 1,228,000 1,228,000
The fair value amounts for each of the financial instruments listed above
approximate carrying amounts due to the short maturities of these instruments.
13. COMMITMENTS AND CONTINGENCIES
In connection with the Plan of Reorganization discussed in Note 1, the Company
agreed to pay, in cash, to Exploration's unsecured creditors, as defined, one-
half of the future reduction of Federal income taxes which were directly
related to any allowed carryovers of Exploration's net operating losses and
investment tax credits existing at the time of the reorganization.
The Company's oil and gas exploration and production activities are subject to
Federal, State and environmental quality and pollution control laws and
regulations. Such regulations restrict emission and discharge of wastes from
wells, may require permits for the drilling of wells, prescribe the spacing of
wells and rate of production, and require prevention and clean-up pollution.
Although the Company has not in the past incurred substantial costs in
complying with such laws and regulations, future environmental restrictions or
requirements may materially increase the Company's capital expenditures, reduce
earnings, and delay or prohibit certain activities.
- 64 -
At December 31, 20062007 the Company has acquired bonds and letters of credit
issued in favor of various state regulatory agencies as mandated by state law
- 57 -
in order to comply with financial assurance regulations required to perform oil
and gas operations within the various state jurisdictions.
The Company has eleven, $5,000 single-well bonds totaling $55,000 with an
insurance company, for wells the Company operates in Alabama. The bonds are
written for a three year period. The Company also has a single-well bond in
the amount of $10,000 with a different insurance company for a well operated
in New Mexico. This bond renews annually.
The Company has nineseven letters of credit from a credit union issued for the
benefit of various state regulatory agencies in Texas, Oklahoma, and Louisiana,
ranging in amounts from $25,000 to $50,000 and totaling $275,000.$250,000. These
letters of credit have expiration dates that range from April 30, 2007February 26, 2008
through March 31, 20082009 and are fully secured by funds on deposit with the
credit union in business money market accounts.
14. ADDITIONAL OPERATIONS AND BALANCE SHEET INFORMATION
Certain information about the Company's operations for the years ended December
31, 2007, 2006, 2005, and 20042005 follows.
Sale of Oil & Gas Properties
- ----------------------------
On January 30, 2004, the Company purchased a gas pipeline for a purchase price
of $200,000 plus fees, which was paid by the Exchanger out of funds held
on behalf of the Company. Both of the above purchases (the "Replacement
Property") qualify as tax-free exchanges under IRC Section 1031. On February
12, 2004, the Exchanger transferred approximately $437,500 into the Company's
bank account, representing the net proceeds after purchase of the Replacement
Properties. This amount less the basis of the Relinquished Property, of
approximately $56,000, was taxable to the Company in 2003, and accordingly a
provision for current income taxes of approximately $130,000 has been recorded
in the books of the Company. Under the full cost method of accounting, the
gain on the sale of the Relinquished Property of approximately $679,000, is not
recognized as income from current operations in the Company's income statement,
but the full amount of the sales price of $735,000 is treated as an adjustment
to capital costs. The purchase price of the $97,270 property is recorded as an
addition to Oil and Gas Properties at year-end. The acquisition cost of
$200,200 of the second Replacement Property acquired in 2004 was recorded as an
Oil and Gas Property addition in 2004.
Effective December 15, 2004, the Company sold the aforementioned gas pipeline
for a sales price of $225,000. The sale qualified as a tax-free exchange under
IRC Section 1031. The proceeds of the sale were deposited directly from the
purchaser into the account of a third party intermediary (the "Exchanger") that
specializes in deferred like-kind exchanges under IRC Section 1031. On
December 27, 2004, subsequent to the initial transaction, the Company acquired
real estate in the form of land and a commercial office building from a third
party for the sum of $2,038,000, and a portion of the purchase price was paid
out of the funds being held by the Exchanger.
- 58 -
Effective November 1, 2005, the Company sold its working interest and
operations in the Beth #1 and #2 wells located in Gray County, Texas to an
unrelated party for $22,500 in cash.
Effective June 1, 2007, the Company sold its working interest and operations
in the Federal 2-33 well located in Lea County, New Mexico to an unrelated
party for $20,000 in cash.
Significant Oil and Gas Purchasers
- ----------------------------------
Dependence on Purchasers
The Company's oil sales are made on a day to day basis at approximately the
current area posted price. The loss of any oil purchaser would not have an
adverse effect upon operations. The Company generally contracts to sell its
natural gas to purchasers pursuant to short-term contracts. Additionally, some
of the Company's natural gas not under contract is sold at the then current
prevailing "spot" price on a month to month basis. Following is a summary of
significant oil and gas purchasers during the three-year period ended December
31, 2006.2007.
- 65 -
Year Ended December 31, (1)
--------------------------------
Purchaser 2007 2006 2005 2004
- ----------------------------------------- -------- -------- --------
Enbridge Energy PartnersNorth Texas 36% 38% 39%
14%Crosstex Energy Services, LP 26% 3% 5%
Shell Trading (US) Company 6% 8% 7%
Teppco Crude Oil, LP 5% 3% -%
Targa Midstream Service, LIM
(formerly Dynegy Midstream Services, LIM 3% -% -%
Navajo Refining Co. 2% -% -%
Devon Gas Services, L.P 2% 4% 6%
ETC Texas Pipeline 2% 5% -%
Eastex Crude Company 2% -% -%
Empire Pipeline Corp 1% 3% -%
Duke Energy Field Services 1% -% -%
Plains Marketing, LP. 1% 6% 6% 6%
Devon Gas Services, L.P 4% 6% 12%
Crosstex Energy Services, Ltd 3% 5% 8%
Empire Pipeline Corp 3% -% -%
Teppco Refining 3% -% -%
Dynegy Midstream Services, LIM -% 5% 11%
Panther Pipeline North Texas, Inc. -% -% 13%
LIG Chemical Company -% -% 2%5%
(1) Percent of Total Oil & Gas Sales
Oil and Gasgas is sold to approximately 110108 different purchasers (such as Devon
Gas Services, L.P., Enbridge Energy Partners (formerly Cantera Resources,
Inc.), Plains Marketing, L.P., Shell Trading (US) Company, Dynegy Midstream
Services, Empire Pipeline Corporation, and Duke Energy Field Services under market
sensitive, short-term contracts computed on a month to month basis.
Except as set forth above, there are no other customers of the Company that
individually accounted for more than 5% of the Company's oil and gas revenues
during the three years ended December 31, 2006.2007.
The Company currently has no hedged contracts.
- 59 -
Certain revenues, costs and expenses related to the Company's oil and gas
operations are as follows:
Year Ended December 31,
-----------------------------------
2007 2006 2005 2004
----------- ----------- -----------
Capitalized costs relating to oil
and gas producing activities:
Unproved properties $ 1,100,000 $ 428,000 $ 349,000
$ 696,000
Proved properties 9,941,000 7,674,000 6,470,000 5,287,000
----------- ----------- -----------
Total capitalized costs 11,041,000 8,102,000 6,819,000
5,983,000
Accumulated amortization (5,249,000) (4,631,000) (4,196,000) (3,467,000)
----------- ----------- -----------
Total capitalized costs, net $ 5,792,000 $ 3,471,000 $ 2,623,000
$ 2,516,000
=========== =========== ===========
- 66 -
Year Ended December 31,
-----------------------------------
2007 2006 2005 2004
----------- ----------- -----------
Costs incurred in oil and gas property
acquisition, exploration and
development:
Acquisition of properties $ -1,516,000 $ - $ -
Development costs 1,423,000 1,283,000 621,000 1,526,000
----------- ----------- -----------
Total costs incurred $ 2,939,000 $ 1,283,000 $ 621,000 $ 1,526,000
=========== =========== ===========
Year Ended December 31,
-----------------------------------
2007 2006 2005 2004
----------- ----------- -----------
Results of Operations from producing
activities:
Sales of oil and gas $ 7,437,000 $ 5,076,000 $ 5,541,000 $ 4,039,000
----------- ----------- -----------
Production costs 2,459,000 2,106,000 1,747,000 1,235,000
Amortization of oil and gas
Properties 619,000 435,000 738,000 477,000
----------- ----------- -----------
Total production costs 3,078,000 2,541,000 2,485,000 1,712,000
----------- ----------- -----------
Total net revenue $ 4,359,000 $ 2,535,000 $ 3,056,000
$ 2,327,000
=========== =========== ===========
- 60 -
Year Ended December 31,
-----------------------------------
2007 2006 2005 2004
----------- ----------- -----------
Sales price per equivalent Mcf $ 7.24 $ 6.16 $ 7.07 $ 5.64
=========== =========== ===========
Production costs per equivalent Mcf $ 2.39 $ 2.55 $ 2.23 $ 1.73
=========== =========== ===========
Amortization per equivalent Mcf $ 0.60 $ 0.53 $ 1.03
$ .67
=========== =========== ===========
- 67 -
Year Ended December 31,
-----------------------------------
2007 2006 2005 2004
----------- ----------- -----------
Results of Operations from gas
gathering and equipment rental
activities:
Revenue $ 179,000 $ 140,000 $ 167,000 $ 158,000
----------- ----------- -----------
Operating expenses 50,000 50,000 29,000
24,000
Depreciation 10,0007,000 10,000 10,000
----------- ----------- -----------
Total costs 57,000 60,000 39,000 34,000
----------- ----------- -----------
Total net revenue $ 122,000 $ 80,000 $ 128,000
$ 124,000
=========== =========== ===========
- 61 -
15. BUSINESS SEGMENTS
The Company's three business segments are (1) oil and gas exploration,
production and operations, (2) transportation and compression of natural gas,
and (3) commercial real estate investment. Management has chosen to organize
the Company into the three segments based on the products or services
provided. The following is a summary of selected information for these
segments for the three-year period ended December 31, 2006:2007:
Year Ended December 31,
-----------------------------------
2007 2006 2005 2004
----------- ----------- -----------
Revenues: (3)
Oil and gas exploration, production
and operations $ 7,649,000 $ 5,230,000 $ 5,661,000 $ 4,166,000
Gas gathering, compression and
equipment rental 179,000 140,000 167,000 158,000
Real estate rental 512,000 430,000 302,000 3,000
----------- ----------- -----------
$ 8,340,000 $ 5,800,000 $ 6,130,000 $ 4,327,000
=========== =========== ===========
Depreciation, depletion and
Amortization expense:
Oil and gas exploration, production
and operations $ 673,000 $ 471,000 $ 738,000 $ 487,000
Gas gathering, compression and
equipment rental 10,0008,000 10,000 10,000
Real estate rental 47,000 47,000 1,00047,000
----------- ----------- -----------
$ 728,000 $ 528,000 $ 795,000
$ 498,000
=========== =========== ===========
- 68 -
Income from operations:
Oil and gas exploration, production
and operations $ 4,493,000 $ 2,653,000 $ 3,176,000 $ 2,445,000
Gas gathering, compression and
equipment rental 122,000 80,000 128,000 123,000
Real estate rental 100,000 53,000 (229,000) -
----------- ----------- -----------
4,715,000 2,786,000 3,075,000 2,568,000
Corporate and other (1) (1,302,000)(2,907,000) (1,866,000) (1,658,000) (1,302,000)
----------- ----------- -----------
Consolidated net income (loss) $ 1,484,0001,808,000 $ 920,000 $ 1,417,000
$ 1,266,000
=========== =========== ===========
- 62 -
Identifiable Assets net of DDA:
Oil and gas exploration, production
and operations $ 5,851,000 $ 3,507,000 $ 2,682,000 $ 2,531,000
Gas gathering, compression and
equipment rental 15,000 23,000 31,000 39,000
Real estate rental 2,026,000 2,076,000 1,937,000 1,985,000
----------- ----------- -----------
$ 7,892,000 $ 5,606,000 $ 4,650,000 $ 4,555,000
Corporate and other (2) 7,739,000 7,418,000 6,737,000 5,160,000
----------- ----------- -----------
Consolidated total assets $15,631,000 $13,024,000 $11,387,000 $ 9,715,000
=========== =========== ===========
Note (1): Corporate and other includes general and administrative expenses,
other non-operating income and expense and income taxes.
Note (2): Corporate and other includes cash, accounts and notes receivable,
inventory, other property and equipment and intangible assets.
Note (3): All reported revenues are from external customers.
16. SUPPLEMENTARY INCOME STATEMENT INFORMATION
The following items were charged directly to expense:
Year Ended December 31,
-----------------------------------
2007 2006 2005 2004
----------- ----------- -----------
Maintenance and repairs $ 8,000 $ 31,000 $ 10,000
$ 13,000
Production taxes 455,000 290,000 303,000 236,000
Taxes, other than payroll and
income taxes 49,000 37,000 70,000
42,000
- 6369 -
17. QUARTERLY DATA (UNAUDITED)
The table below reflects selected quarterly information for the years ended
December 31, 2007, 2006 2005 and 2004.2005.
Year Ended December 31, 2007
----------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
---------- ---------- ---------- ----------
Revenue $1,417,000 $2,160,000 $1,988,000 $3,142,000
Expense (999,000) (1,296,000) (1,440,000) (2,197,000)
---------- ---------- ---------- ----------
Operating income 418,000 864,000 548,000 945,000
Current tax provision (111,000) (177,000) (10,000) (138,000)
Deferred tax provision (91,000) (173,000) (147,000) (120,000)
---------- ---------- ---------- ----------
Net income 216,000 514,000 391,000 687,000
========== ========== ========== ==========
Earnings per share
of common stock
Basic $0.03 $0.07 $0.05 $0.09
Diluted $0.03 $0.07 $0.05 $0.09
Year Ended December 31, 2006
----------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
---------- ---------- ---------- ----------
Revenue $1,561,000 $1,520,000 $1,696,000 $1,397,000
Expense (927,000) (1,176,000) (1,233,000) (1,388,000)
---------- ---------- ---------- ----------
Operating income 634,000 344,000 463,000 9,000
Current tax provision (2,000) (133,000) (115,000) 250,000
Deferred tax provision (161,000) (91,000) (20,000) (258,000)
---------- ---------- ---------- ----------
Net income 471,000 120,000 328,000 1,000
========== ========== ========== ==========
Earnings per share
of common stock
Basic $0.06 $0.02 $0.04 $0.00
Diluted $0.06 $0.02 $0.04 $0.00
- 70 -
Year Ended December 31, 2005
----------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
---------- ---------- ---------- ----------
Revenue $1,306,000 $1,503,000 $1,465,000 $2,121,000
Expense (698,000) (898,000) (1,037,000) (1,652,000)
---------- ---------- ---------- ----------
Operating income 608,000 605,000 428,000 469,000
Current tax provision (109,000) (140,000) (76,000) (35,000)
Deferred tax provision (55,000) (40,000) (39,000) (199,000)
---------- ---------- ---------- ----------
Net income 444,000 425,000 313,000 235,000
========== ========== ========== ==========
Earnings per share
of common stock
Basic $0.06 $0.06 $0.04 $0.03
Diluted $0.06 $0.06 $0.04 $0.03
- 64 -
Year Ended December 31, 2004
----------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
---------- ---------- ---------- ----------
Revenue $1,004,000 $1,028,000 $1,169,000 $1,314,000
Expense (564,000) (544,000) (644,000) (910,000)
---------- ---------- ---------- ----------
Operating income 440,000 484,000 525,000 404,000
Current tax provision (13,000) (156,000) (115,000) 140,000
Deferred tax provision - - - (443,000)
---------- ---------- ---------- ----------
Net income 427,000 328,000 410,000 101,000
========== ========== ========== ==========
Earnings per share
of common stock
Basic $0.06 $0.04 $0.05 $0.01
Diluted $0.06 $0.04 $0.05 $0.01
18. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
The Company's net proved oil and natural gas reserves as of December 31, 2007
and December 31, 2006 have been estimated by Netherland, Sewell & Associates,
Inc. The Company's net proved oil and natural gas reserves as of December 31,
2005 and 2004 were estimated by Company personnel. All estimates are in accordance with
guidelines established by the Securities and Exchange Commission. Accordingly,
the following reserve estimates were based on existing economic and operating
conditions. Oil and gas prices in effect at December 31, of each year were
used. Operating costs, production and ad valorem taxes and future development
costs were based on current costs with no escalation.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting the future rates of production and timing of
development expenditures. The following reserve data represents estimates only
and should not be construed as being exact. Moreover, the present values
should not be construed as the current market value of the Company's oil and
gas reserves or the costs that would be incurred to obtain equivalent reserves.
- 6571 -
Changes in Estimated Quantities of Proved Oil and Gas Reserves (Unaudited):
Crude Oil Natural Gas
Bbls Mcf
------------ ------------
Quantities of Proved Reserves:
- ------------------------------
Balance December 31, 2003 365,230 9,353,560
Sales of reserves in place - -
Acquired properties - -
Extensions and discoveries 3,590 418,592
Revisions of previous estimates 73,271 4,537,079
Production (23,098) (577,099)
------------ ------------
Balance December 31, 2004 418,993 13,732,132
Sales of reserves in place (770) (6,113)
Acquired properties - -
Extensions and discoveries 6,407 188,973
Revisions of previous estimates 80,316 1,522,389
Production (21,323) (655,568)
------------ ------------
Balance December 31, 2005 483,623 14,781,813
Sales of reserves in place - -
Acquired properties - -
Extensions and discoveries 35,856 6,098,653
Revisions of previous estimates (137,414) (6,822,992)
Production (25,443) (671,512)
------------ ------------
Balance December 31, 2006 356,622 13,385,962
Sales of reserves in place - -
Acquired properties - -
Extensions and discoveries 12,239 1,485,603
Revisions of previous estimates 765 375,862
Production (24,472) (880,662)
------------ ------------
Balance December 31, 2007 345,154 14,366,765
============ ============
Proved Developed Reserves:
- --------------------------
Balance December 31, 2004 389,851 6,887,978
Balance December 31, 2005 433,455 7,109,815
Balance December 31, 2006 340,870 7,352,511
Balance December 31, 2007 334,213 10,947,481
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.
-72 -
Reserve estimates were prepared in accordance with standard Security and
Exchange Commission guidelines. The future net cash flow was computed using
year-end 20062007 oil and gas prices. Lease operating costs, compression,
-66 -
dehydration, transportation, ad valorem taxes, severance taxes, and federal
income taxes were deducted. Costs and prices were held constant and were not
escalated over the life of the properties. No deduction has been made for
interest, or general corporate overhead. The annual discount of estimated
future cash flows is defined, for use herein, as future cash flows discounted
at 10% per year, over the expected period of realization.
Proved Developed Reserves were calculated based on Decline Curve Analysis on
91116 operated wells and 275121 non-operated wells. Materially insignificant non-
operated wells were excluded from the reserve estimate.
The Company emphasizes that reserve estimates are inherently imprecise.
Accordingly, the estimates are expected to change as more current information
becomes available. It is reasonably possible that, because of changes in
market conditions or the inherent imprecision of these reserve estimates, that
the estimates of future cash inflows, future gross revenues, the amount of oil
and gas reserves, the remaining estimated lives of the oil and gas properties,
or any combination of the above may be increased or reduced in the near term.
If reduced, the carrying amount of capitalized oil and gas properties may be
reduced materially in the near term.
Standardized measure of discounted future net cash flows related to proved
reserves:
Year Ended December 31,
--------------------------------------
2007 2006 2005 2004
------------ ------------ ------------
Future production revenue $115,233,000 $ 81,294,000 $130,178,000
$ 87,568,000
Future development costs (4,601,000) (4,778,000) (13,831,000) (8,300,000)
Future production costs (26,806,000) (21,323,000) (25,144,000) (22,668,000)
------------ ------------ ------------
Future net cash flow before
Federal income tax 83,826,000 55,193,000 91,203,000 56,600,000
Future income taxes (23,471,000) (15,454,000) (22,941,000) (15,175,000)
------------ ------------ ------------
Future net cash flows 60,355,000 39,739,000 68,262,000 41,425,000
Effect of 10% annual discounting (18,141,000) (14,074,000) (40,401,000) (24,534,000)
------------ ------------ ------------
Standardized measure of
Discounted net cash flows $ 42,214,000 $ 25,655,000 $ 27,861,000 $ 16,891,000
============ ============ ============
- 6773 -
Changes in the standardized measure of discounted future net cash flows:
Year Ended December 31,
--------------------------------------
2007 2006 2005 2004
------------ ------------ ------------
Beginning of the year $ 25,655,000 $ 27,861,000 $ 16,891,000 $ 11,862,000
Oil and gas sales, net of
production costs (4,978,000) (2,970,000) (5,541,000)
(2,644,000)
PurchasesSales of reserves in place - - -
Sales of reserves in place - (31,000) -
Net change in prices, net of
production costs 20,449,000 (8,513,000) 13,063,000 7,809,000
Extensions, discoveries and additions 9,251,000) -7,243,000 9,251,000 -
Changes in production rates,
timing and other - - (7,571,000) (3,101,000)
Revisions of quantity estimate (1,592,000(4,083,000) (1,592,000) 11,722,000 7,662,000
Effect of income tax (4,638,000) (1,158,000) (2,361,000) (5,883,000)
Accretion of discount 2,566,000 2,786,000 1,689,000 1,186,000
------------ ------------ ------------
End of year $ 42,214,000 $ 25,655,000 $ 27,861,000 $ 16,891,000
============ ============ ============
- 6874 -
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2007, 2006, 2005, AND 20042005
SCHEDULE II
Beginning Costs & Ending
Description Balance Expenses Deductions Balance
- ----------------------------- ----------- ----------- ----------- -----------
Allowance for
doubtful Accounts
December 31, 2004 $ 30,000 $ - $ - $ 30,000
========== ========== ========== ==========
December 31, 2005 $ 30,000 $ - $ 16,000 $ 14,000
========== ========== ========== ==========
December 31, 2006 $ 14,000 $ - $ - $ 14,000
========== ========== ========== ==========
December 31, 2007 $ 14,000 $ - 69$ - $ 14,000
========== ========== ========== ==========
- 75 -
SCHEDULE III
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
REAL ESTATE AND ACCUMULATED DEPRECIATION
Initial Cost to Corporation Total Cost
- ----------------------------------------------------------------- Subsequent
Description Encumbrances Land Buildings ToAcquist'n
- ------------------------- ------------- ----------- ----------- -----------
Two story multi-tenant
garden office building with
sub-grade parking garage
located in Dallas, Texas (b) $ 688,000 $1,298,000 $210,000$244,000
Gross Amounts at Which Carried at Close of Year
Life on which
Accumulated Depreciation Date
Land Buildings Total Depreciation Calculated Acquired
- ---------- ------------ ----------- ------------- ------------ -----------
$ 688,000 $ 1,508,0001,542,000 $ 2,196,0002,230,000 $ 120,000204,000 (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, 20062007 is as follows:
Investments in Accumulated
Real Estate Depreciation
------------ ------------
Balance, December 31, 2003
Acquisitions 1,986,000
Depreciation expense - 1,000
------------ ------------
Balance, December 31, 2004 $ 1,986,000 $ 1,000
Acquisitions - -
Depreciation expense - 48,000
------------ ------------
Balance, December 31, 2005 $ 1,986,000 $ 49,000
Acquisitions 210,000
-
Depreciation expense - 71,000
------------ ------------
Balance, December 31, 2006 $ 2,196,000 $ 120,000
Acquisitions 34,000
Depreciation expense 84,000
------------ ------------
Balance, December 31, 2007 $ 2,230,000 $ 204,000
============ ============
- 7076 -
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(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 ExecutiveFinancial Officer
32 Officers' Section 1350 Certifications
- 7177 -
EXHIBIT 21
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
Subsidiaries of the Registrant
Prairie Pipeline Co. incorporated June 22, 1983, under the laws of the State of
Texas, is a wholly owned subsidiary of Registrant.
Spindletop Drilling Company, incorporated September 5, 1975, under the laws of
the State of Texas, is a wholly owned subsidiary of the Registrant.
Prairie Pipeline Co. incorporated June 22, 1983, under the laws of the State
of Texas, is a wholly owned subsidiary of Registrant.
- 7278 -
Exhibit 31.1
CERTIFICATIONS
I, Chris G. Mazzini, certify that:
1. I have reviewed this report on Form 10-K of Spindletop Oil & Gas Co.;
2. Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material respects
the financial condition, results of operations and cash flows of the registrant
as of, and for, the periods presented in this report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13-15(e) and 15d-15e) and have internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)
for the registrant and have:
(a) designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known
to us by others within those entities, particularly during the period
in which this report is being prepared;
(b) designed such internal control over financial reporting, or caused
such internal control over financial reporting to be designed under
our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally
accepted accounting principles;
and
(c) evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this report our conclusions about
the effectiveness of the controls and procedures as of the end of
the period covered by this report based on such evaluation; and
(d) disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the
registrant's most recent fiscal quarter that has materially affected,
or is reasonably likely to materially affect, the registrant's
internal control over financial reporting; and
- 7379 -
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of registrant's board of
directors (or persons performing the equivalent functions):
(a) all significant deficiencies and material weaknesses in the design
or operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls.
Dated April 16, 200714, 2008
/s/ Chris G. Mazzini
CHRIS G. MAZZINI
Chief Executive Officer
- 7480 -
Exhibit 31.2
CERTIFICATIONS
I, Robert E. Corbin, certify that:
1. I have reviewed this report on Form 10-K of Spindletop Oil & Gas Co.;
2. Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material respects
the financial condition, results of operations and cash flows of the registrant
as of, and for, the periods presented in this report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13-15(e) and 15d-15e) and have internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)
for the registrant and have:
(a) designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known
to us by others within those entities, particularly during the period
in which this report is being prepared;
(b) designed such internal control over financial reporting, or caused
such internal control over financial reporting to be designed under
our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally
accepted accounting principles;
and
(c) evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this report our conclusions about
the effectiveness of the controls and procedures as of the end of
the period covered by this report based on such evaluation; and
(d) disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the
registrant's most recent fiscal quarter that has materially affected,
or is reasonably likely to materially affect, the registrant's
internal control over financial reporting; and
- 7581 -
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:Dated April 16, 200714, 2008
/s/ Robert E. Corbin
ROBERT E. CORBIN
Principal Financial and
Accounting Officer
- 7682 -
Exhibit 32
Officers' Section 1350 Certifications
The undersigned officerofficers of Spindletop Oil & Gas Co., a Texas corporation (the
"Company"), hereby certifiescertify that (i) the Company's Annual Report on Form 10-K
for the year ended December 31, 20052007 fully complies with the requirements of
Section 13(a) of the Securities Exchange Act of 1934, and (ii) the information
contained in the Company's Annual Report on Form 10-K for the year ended
December 31, 20052007 fairly presents, in all material respects, the financial
condition and results of operations of the Company, at and for the periods
indicated.
Dated: April 16, 200714, 2008
/s/ Chris G. Mazzini
CHRIS G. MAZZINI
Chief Executive Officer
/s/ Robert E. Corbin
ROBERT E. CORBIN
Principal Financial and
Accounting Officer
- 7783 -