SECURITIES AND EXCHANGE COMMISSION

                           WASHINGTON, DC 20549

                                 FORM 10-K

             ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                    THE SECURITIES EXCHANGE ACT OF 1934

                For the fiscal year ended December 31, 2004
                       Commission File No. 000-18774


                         SPINDLETOP OIL & GAS CO.
          (Exact name of registrant as specified in its charter)


                   Texas                                      75-2063001
        (State or other jurisdiction                   (IRS Employer or ID #)
      of incorporation or organization)

 12850 Spurling Road, Suite 200, Dallas, TX                     75230
  (Address of principal executive offices)                    (Zip Code)

                              (972) 644-2581
             (Company's telephone number, including area code)

        Securities registered pursuant to Section 12(b) of the Act:

                                   NONE

        Securities registered pursuant to Section 12(g) of the Act:

                  Common Stock par value $0.01 per share
                             (Title of Class)


Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act).

                  YES                               NO   X

Indicate by check mark whether the Company (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the Company
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.

                  YES   X                           NO

As of March 31, 2005, 7,677,471  shares of the Company's common stock were
issued and outstanding, and the aggregate market value of the voting stock
held by non-affiliates of the company as of that date is not determinable
since no significant public trading market has been established for the
Company's common stock.


                                  PART I

                      Item 1. Description of Business

GENERAL

Spindletop Oil & Gas Co. is an independent oil and gas company engaged in the
exploration, development and production of oil and natural gas; the rental of
oilfield equipment; and through one of its subsidiaries, the gathering and
marketing of natural gas. The terms the "Company", "We", "Us" or Spindletop
are used interchangeably herein to refer to Spindletop Oil & Gas Co. and its
wholly owned subsidiaries, Prairie Pipeline Co. ("PPC") and Spindletop Drilling
Company ("SDC").

The Company has focused its oil and gas operations principally in Texas,
although we operate properties in six states including:  Texas, Louisiana,
Oklahoma, Arkansas, Alabama, and New Mexico.  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.

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 25 years oil and gas experience 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.

From the 1990's through 2002, 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.

                                   - 2 -
During this time period, the Company acquired a large number of operated and
non-operated oil and gas properties in various states.

From 2002 to the present, we have returned our focus to a strategy of
development drilling.  With higher product prices, we believe that it is 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.

Strategic Business Plans

One of our key strategies is to enhance shareholder value through
implementation of plans for controlled growth and development. The Company's
long-term focus is to grow its oil and gas production through a strategic
combination of selected property acquisitions, to the extent feasible, and an
exploration and development program primarily based on developing its leasehold
acreage. Additionally, the Company will continue to rework existing wells to
increase production and reserves.

The Company's primary area of operation has been and will continue to be in
Texas with an emphasis in the geological province known as the Ft. Worth
Basin. The Company is planning to drill and develop its Fort Worth Basin
producing properties to the Barnett Shale formation.  We want to capitalize on
our strengths which include a good knowledge of the Fort Worth Basin,
experience in operations in this geographic area, development of lease
holdings, and utilization of existing infrastructure to minimize costs.

The Company will continue to generate and evaluate prospects using its own
technical staff. The Company intends to fund operations primarily from cash
flow generated by operations.

The Company will attempt to expand its pipeline system.  Expansion will be
dependent upon success in its exploration programs, since the majority of its
existing pipelines are connected to wells that the Company operates.


Significant Project Areas

The Company has operations and well interests in 16 states; however, the
majority of reserves (86%) are located in Texas.

A breakout of the Company's most significant reserves by geographic area is as
follows:

      Fort Worth Basin Texas    1,886,429 BOE             69.67 %
      East Texas                  131,617 BOE              4.86 %
      Gulf Coast Texas            189,889 BOE              7.01 %

                                   - 3 -
      Panhandle Texas              45,076 BOE              0.75 %
      West Texas                   87,914 BOE              3.25 %
      Alabama                      17,353 BOE              0.64 %
      Arkansas                     29,650 BOE              1.10 %
      Kansas                       24,149 BOE              0.89 %
      Louisiana                   111,371 BOE              4.11 %
      Michigan                      1,112 BOE              0.04 %
      New Mexico                   51,941 BOE              1.92 %
      North Dakota                  3,273 BOE              0.12 %
      Oklahoma                    122,641 BOE              4.53 %
      Wyoming                      29,944 BOE              1.11 %

      Total                     2,707,682 BOE            100.00 %

The majority of our wells are located within a two-hour drive from our
corporate headquarters, which provides for more effective oversight of
operations.

                          Fort Worth Basin Texas

The Fort Worth Basin has been the focal point of the Company since its
inception. Our technical personnel have an average of 25 years of exploration,
drilling and production experience in the Basin. We also have an extensive
collection of geologic and engineering data.

The Fort Worth Basin is a gas prone region with multiple pay zones ranging in
depth from 1000-9000 feet. The basin is currently experiencing a drilling boom
due to increased natural gas prices and advances in fracturing technology
that have unlocked natural gas reserves from the Barnett Shale Formation.

The Barnett Shale is a thick blanket type formation covering the entire basin.
The natural gas reserves in place are significant; however, due to the
extremely low permeability of the shale, it has been technically difficult to
recover these reserves. Recent advances in hydraulic fracturing and horizontal
well technology have enabled economic recovery of natural gas reserves in the
Fort Worth Basin.

According to the U.S. Geological Survey, it is estimated that there is
approximately 26.7 trillion cubic feet (TCF) of undiscovered natural
gas, 98.5 million barrels of undiscovered oil, and 1.1 billion barrels of
undiscovered natural gas liquids (condensate) in the Bend Arch-Fort Worth
Basin Province and more than 98 percent, or 26.2 TCF, of the undiscovered
natural gas is located in the Barnett Shale.

The Company has large lease-holdings in the Fort Worth Basin held by production
from shallower producing zones.  We are planning to drill into the Barnett
Shale Formation on these leases.  We are also actively seeking and acquiring
new leases in the Barnett Shale play.

During 2004, the Company drilled its fourth Barnett Shale well on its Olex
(U.S.) lease in eastern Denton County, Texas. Our leasehold is offset in all
directions by productive Barnett Shale gas wells, and with existing spacing
rules, an additional 13 wells could be drilled on this lease.  The Company
also participated in the drilling of one Barnett Shale well on a non-operated


                                   - 4 -
lease north of Fort Worth, Texas.  Up to seven more wells may be drilled on
this lease.

The Barnett Shale gas play is rapidly expanding into Parker County, Texas
where the Company has a large acreage position.  The Company intends to focus
its efforts on developing Barnett Shale natural gas reserves underlying its
leasehold. The Company plans to drill five horizontal Barnett Shale wells in
Parker County in the next two years, providing we can secure the necessary
drilling equipment on a timely basis. The Company may take on partners to
reduce risk in any one project.

In the northeast quarter of Parker County at Springtown, the Company holds
approximately 1750 acres of leasehold by production, and has 3D seismic data
across a portion of the acreage. Recently, three horizontal wells offsetting
our acreage with initial potentials ranging from 1,000-3,000 MCFG/D were
drilled and completed. The Company plans to drill at least three horizontal
Barnett Shale wells on this block in the near future.  PPC owns and operates
a natural gas gathering system at Springtown, Texas that could be used to
bring natural gas from these future wells to market.

In southeastern Parker County, near the town of Cresson, the Company holds
approximately 325 acres by production. Last year, another company completed
two successful horizontal wells offsetting this acreage. Each of these wells
has produced in excess of 300,000 MCFG in the first year of production. The
Company plans to drill at least one horizontal Barnett Shale well on this block

In the northwest portion of Parker County near the town of Peaster, the Company
holds approximately 2200 acres by production which was recently offset by
another company. The Company plans to drill at least one horizontal Barnett
Shale well on this block.

The Company also holds smaller acreage blocks throughout Parker County as well
as in Palo Pinto, Erath and Eastland Counties. The Barnett Shale is present
under these blocks, however, as of yet they have not been directly offset by
proven productive wells. The limits of economic Barnett Shale gas production
in the Fort Worth Basin are continually expanding and these blocks may be
proven productive in the future.

Other than the Barnett Shale, the Company has other opportunities to optimize
existing natural gas production. During 2004, two previously non-producing gas
wells were reworked and restored to production adding 273,000 MCFG to the
Proved Developed Reserves classification.

                                East Texas

In Titus County, during 2005, the Company intends to restore to production its
Pewitt Ranch Field properties near the town of Talco. These properties have
large oil reserves in place but the wells produce viscous low gravity, high
sulfur crude oil and have high operating costs due to corrosion and water
handling problems. However, in the current oil price environment, the Company
believes that the wells can be operated economically.

In Limestone County, the Company has agreed to participate in the work-over of
two infield wells to be completed in the Upper Cotton Valley Sands and one
infield well to be reworked in the Lower Cotton Valley Sands during 2005.

                                   - 5 -
                                Gulf Coast

In 2003, the Company farmed out some of its rights to an unrelated company
retaining an overriding royalty interest. This other company successfully
completed a 9300 ft. gas well in 2004 with an initial potential of 749 MCFG/D
and earned 160 acres. Subsequently in 2005, the Company farmed out its deeper
rights to a second company who is currently drilling a 12,000 ft. Wilcox test.
The Company retained an overriding royalty interest and a back-in after payout
working interest.

                                 Oklahoma

In Ellis County in 2004, the Company participated in the drilling and
completion of an 8,500 ft. Morrow Sand development well. The well is expected
to produce approximately 470 MCF/D and one other well may be drilled on this
lease in the future. In Caddo County, the Company participated in a 13,000 ft.
Springer Sand development well, and completed it as a marginal gas producer.

                                  Wyoming

The Company participated in the drilling of three 800 ft. coal bed methane
wells in Campbell County. The wells were completed in December of 2004 and are
expected to each produce approximately 150 MCFG/D.

                          Other Areas of Interest

The Company participated during 2004 in the drilling of three development
wells in the Arkoma Basin of Arkansas, and in one rework of a gas well in
Louisiana. During the first quarter of 2005, the Company has agreed to
participate in the drilling of four 2,000 ft. development wells in the
Bowdoin gas field located in Phillips, Montana.

Oil and Natural Gas Reserves

The net crude oil and gas reserves of the Company as of December 31, 2004,
were 418,993 barrels of oil and condensate and 13,732,132 MCF (thousand cubic
feet) of natural gas.  Based on SEC guidelines, the reserves were classified
as follows:

        Proved Developed Producing        389,851 BO and   6.9 BCFG
        Proved Undeveloped                 29,142 BO and   6.8 BCFG
        Total Proved Reserves             418,993 BO and  13.7 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.






                                   - 6 -
On a barrel of oil equivalent basis (6MCF/BOE), the reserves are

      Natural Gas Reserves                2,288,689 BOE      85%
      Oil Reserves                          418,993 BOE      15%
          Total Reserves                  2,707,682 BOE     100%

      Proved Developed Producing          1,537,847 BOE      57%
      Proved Undeveloped                  1,169,835 BOE      43%
          Total Proved Reserves           2,707,682 BOE     100%

The Company has operational control over the majority of these reserves and can
therefore to a large extent control the timing of development and production.

      The Company's Operated Wells        2,432,271 BOE      90%
      Non Operated Wells                    275,411 BOE      10%
          Total                           2,707,682 BOE     100%


Financial information relating to Industry Segments

The Company has three identifiable business segments: exploration, development
and production of oil and natural gas, gas gathering, and commercial real
estate investment.  Footnote 15 to the Consolidated Financial Statements filed
herein sets forth the relevant information regarding revenues, income from
operations and identifiable assets for these segments.

Narrative Description of Business

The Company is engaged in the exploration, development and production of oil
and natural gas, and the gathering and marketing of natural gas.  The Company
is also engaged in commercial real estate leasing through the acquisition and
partial occupancy of its new 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 806 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 January, 2004 the Company acquired an approximate 56 mile inactive gas
gathering system in South Central Kansas.  In December, 2004, the Company sold
the pipline to an unrelated third party.

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.

                                   - 7 -
                     Patents, Licenses and Franchises

Oil and gas leases of the Company are obtained from the owner of the mineral
estate.  The leases are generally for a primary term of 1 to 5 years, and in

some instances as long as 10 years, with the provision that such leases shall
be extended into a secondary term and will continue during such secondary term
as long as oil and gas are produced in commercial quantities or other
operations are conducted on such leases as provided by the terms of the leases.
It is generally required that a delay rental be paid on an annual basis during
the primary term of the lease unless the lease is producing.  Delay rentals are
normally $1.00 to $5.00 per net mineral acre.

The Company currently holds interests in producing and non-producing oil and
gas leases. The existence of the oil and gas leases and the terms of the oil
and gas leases are important to the business of the Company because future
additions to reserves will come from oil and gas leases currently owned by the
Company, and others that may be acquired, when they are proven to be
productive.  The Company is continuing to purchase oil and gas leases in
areas where it currently has production, and also in other areas.


                                Seasonality

The Company's oil and gas activities generally are conducted on a year round
basis with only minor interruptions caused by weather, equipment and labor
issues.

                           Working Capital Items

The Company finances the majority of its operations, including the purchase of
oil and gas leases, the development of wells, the construction of pipelines and
acquisition of oil field rental equipment from its internal working capital as
well as some borrowings.

                          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, 2004:

	Year Ended December 31, (1)
	--------------------------------
              Purchaser                        2004        2003        2002
-----------------------------------------    --------    --------    --------
Enbridge Energy Partners                        14%         17%         22%
Panther Pipeline North Texas, Inc.              13%          -           -
Devon Gas Services, L.P                         12%         20%         38%
Dynegy Midstream Services, LIM                  11%          -           -
Crosstex Energy Services, Ltd                    8%          -           -
Plains Marketing, LP.                            6%          7%          -
Shell Trading (US) Company                       6%          9%          -
LIG Chemical Company                             2%          9%          -

(1)  Percent of Total Oil & Gas Sales


                                   - 8 -
Oil and gas is sold to approximately 105 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, LIG Chemical Company, 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, 2004.

The Company currently has no hedged contracts.

                                Competition

Numerous entities and individuals, many of which have far greater financial
and other resources than the Company, are active in the exploration for and
production of oil and gas.  Substantial competition exists for leases,
prospects and equipment, all of which are necessary for successful operations.
Competition is focused primarily on the discovery of new prospects, which can
be developed and made productive.

The market prices received for the Company's products depend on a number of
factors beyond the control of the Company, including consumer demand, worldwide
availability, transportation facilities, and United States and foreign
government regulation of exports, imports, production and prices.  Widely
fluctuating prices for oil and gas over recent years have had a direct effect
on the profitability of the Company's operations.

                          Development Activities

The Company's primary oil and gas prospect acquisition efforts have been in
 known producing areas in the United States with emphasis devoted to Texas.

The Company intends to use a portion of its available funds to participate in
drilling activities.  Any drilling activity is performed by independent
drilling contractors.  The Company does not refine or otherwise process its
oil and gas production.

Exploration for oil and gas is normally conducted with the Company acquiring
undeveloped oil and gas prospects, and carrying out exploratory drilling on
the prospect with the Company retaining a majority interest in the prospect.
Interests in the property are sometimes sold to key employees and associated
companies at cost.  Also, interests may be sold to third parties with the
Company retaining an overriding royalty interest, carried working interest,
or a reversionary interest.

A prospect is a geographical area designated by the Company for the purpose of
searching for oil and gas reserves and reasonably expected by it to contain at
least one oil or gas reservoir.  The Company utilizes its own funds along with
the issuance of common stock and options to purchase common stock in some
cases, to acquire oil and gas leases covering the lands comprising the
prospects.  These leases are selected by the Company and are obtained directly
from the landowners, as well as from land men, geologists, other oil companies,
some of whom may be affiliated with the Company, and by direct purchase, farm-

                                   - 9 -
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.

                         Environmental Regulation

The Company's oil and gas exploration and production activities are subject
to Federal, State and environmental quality and pollution control laws and
regulations.  Such regulations restrict emission and discharge of wastes from
wells, may require permits for the drilling of wells, prescribe the spacing of
wells and rate of production, and require prevention and clean-up of pollution

Although the Company has not in the past incurred substantial costs in
complying with such laws and regulations, future environmental restrictions or
requirements may materially increase the Company's capital expenditures,
reduce earnings, and delay or prohibit certain activities.  However, such
restrictions and requirements would also apply to the Company's competitors,
and it is unlikely that compliance by the Company would adversely affect the
Company's competitive position.

                     Additional Government Regulation

In addition to environmental regulations, the production and sale of oil and
gas is subject to regulation by Federal, State and local governmental
authorities and agencies.  Such regulations encompass matters such as the
location and spacing of wells, the prevention of waste, the rate of
production, the sale price of certain oil and gas, conservation, and safety.

                           Oil Price Regulation

Historically, regulatory policy affecting crude oil pricing was derived from
the Emergency Petroleum Allocation Act of 1973, as amended, which provided for
mandatory crude oil price controls until June 1, 1979, and discretionary
controls through September 30, 1981.  On April 5, 1979, President Carter
directed the Department of Energy to complete administrative procedures
designed to phase out, commencing June 1, 1979, price controls on all
domestically produced crude oil by October 1, 1981. However, on January 28,
1981, President Reagan ordered the elimination of remaining federal controls
on domestic oil production, effective immediately.  Consequently, oil may
currently be sold at unregulated prices.

                           Gas Price Regulation

The Natural Gas Act of 1938 ("NGA") regulates the interstate transportation
and certain sales for resale of natural gas.  The Natural Gas Policy Act of
1978 ("NGPA") regulates the maximum selling prices of certain categories of
gas, whether sold in so-called "first sales" in interstate or intrastate
commerce.  These statutes are administered by the Federal Energy Regulatory
Commission ("FERC").  The NGPA established various categories of natural gas
and provided for graduated deregulation of price controls for first sales of
several categories of natural gas.  With certain exceptions, all price
deregulation contemplated under the NGPA as originally enacted in 1978 has
already taken place.  Under current market conditions, deregulated gas prices
under new contracts tend to be substantially lower than most regulated price
ceilings prescribed by the NGPA.

                                   - 10 -
On July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 ("Decontrol
Act") was enacted.  The Decontrol Act amended the NGPA to remove as of July 27,
1989 both price and non-price controls from natural gas not subject to a first
sale contract in effect on July 26, 1989.  The Decontrol Act also provided for
the phasing out of all price regulation under the NGPA by January 1, 1993.

                          Special Tax Provisions

See Footnote 8 to Consolidated Financial Statements

                                 Employees

The Company, on its own account and through a management contract with its
parent corporation, employs or contracts for the services of a total of 44
people.  Twelve 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 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.





















                                   - 11 -
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,
                                          -----------------------------------
                                              2004       2003        2002
                                          ----------- ----------- -----------
Gas and Oil Properties, net (1):
   Proved developed gas reserves-Mcf (2)    6,888,000   4,978,000   4,977,000
   Proved undeveloped gas reserves-Mcf (3)  6,844,000   4,375,000  11,298,000
                                          ----------- ----------- -----------
     Total proved gas reserves-Mcf         13,732,000   9,353,000  16,275,000
                                          =========== =========== ===========
Proved Developed Crude Oil and
   Condensate reserves-Bbls (2)               390,000     365,000     153,000
Proved Undeveloped crude oil and
   Condensate reserves-Bbls (3)                29,000         -           -
                                          ----------- ----------- -----------
   Total proved crude oil and condensate
     Reserves-Bbls                            419,000     365,000     153,000
                                          =========== =========== ===========

                                                Year Ended December 31,
                                          -----------------------------------
                                             2003        2003        2002
                                          ----------- ----------- -----------
Present Value of Estimated Future
  Net Reserves from proved reserves (4)(5)
    (Before Income Tax)
       Developed                          $15,118,000 $10,726,000 $ 5,578,000
       Undeveloped                          8,279,000   1,106,000   6,237,000
                                          ----------- ----------- -----------
       Total Developed and Undeveloped    $23,397,000 $11,832,000 $11,815,000
                                          =========== =========== ===========

(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 2002 through 2004.

(4) "Estimated Future Net Revenues" are computed by applying current prices
of oil and gas, less the estimated future expenditures (based on current costs)
to be incurred in developing and producing the proved reserves.

                                   - 12 -
(5) "Present Value of Estimated Future Net Revenues" is computed by discounting
the Estimated Future Net Revenues at the rate of ten percent (10%) per year on
a pretax basis in accordance with the Securities and Exchange Commission Rules
and Regulations.

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,
                                     -----------------------------------------
                                         2004          2003          2002
                                     ------------- ------------- -------------
                                      Gross   Net   Gross   Net   Gross   Net
                                     ------ ------ ------ ------ ------ ------
Exploratory Wells (1):
  Productive                            -      -      -      -      -      -
  Non-Productive                        -      -      -      -      -      -
                                     ------ ------ ------ ------ ------ ------
    Total                               -      -      -      -      -      -
                                     ------ ------ ------ ------ ------ ------

Development Wells (2):
  Productive                         10.000  1.171  2.000   .765  1.000   .125
  Non-Productive                        -      -      -      -      -      -
                                     ------ ------ ------ ------ ------ ------
    Total                            10.000. 1.171  2.000   .765  1.000   .125
                                     ------ ------ ------ ------ ------ ------

Total Exploration & Development
Wells:
  Productive                         10.000  1.171  2.000   .765  1.000   .125
  Non-Productive                        -      -      -      -      -      -
                                     ------ ------ ------ ------ ------ ------
     Total                           10.000  1.171  2.000   .765  1.000   .125
                                     ------ ------ ------ ------ ------ ------

(1) An exploratory well is a well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir.
(2) A development well is a well drilled within the proved area of an oil or
gas reservoir to the depth of a stratigraphic horizon known to be productive.

Subsequent to year end at March 31, 2005, we had completed two gross (1.08 net)
Barnett Shale natural gas development wells in Denton County, Texas that were
not reflected in the table above as they were not completed by December 31,
2004.  Additionally, at that same date, we participated in the completion of
one gross (.10 net) horizontal Barnett Shale natural gas development well in
Tarrant County, Texas. Also, at that same date, three gross (.07 net) Bowdoin
Field natural gas development wells in Phillips County, Montana and one gross
(.10 net) horizontal Barnett Shale development well in Tarrant County, Texas
were waiting on completion.



                                   - 13 -
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
                               2004      2003      2002      2001      2000
                             --------  --------  --------  --------  --------
Oil and Gas Production, net:
 Natural Gas (Mcf)            577,099   540,799   499,081   472,728   479,769
 Crude Oil & Condensate (Bbl)  23,098    28,747     9,553     9,229    10,111

Average Sales Price per Unit
Produced:
 Natural Gas ($/Mcf)          $  5.44  $   4.33  $   3.02  $   4.07  $   3.58
 Crude Oil & Condensate($/Bbl)$ 38.90  $  25.14  $  23.27  $  25.19  $  27.37

Average Production Cost per
Equivalent Barrel (1) (2)     $ 11.69  $  10.41  $   8.51  $   9.15  $   8.09


(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, 2004.

The Company currently has leases covering in excess of 5,000 acres in  Denton,
Eastland, Erath, Hood, Palo Pinto, Parker, and Tarrant Counties, Texas
(currently held by production), that the Company believes may have drilling
locations in the Barnett Shale Formation.  The Company has included some of
these potential locations in its calculation of proven undeveloped oil and gas
reserves.  See Footnote 18 to the Financial Statement for an expanded
description of this activity.

Effective August 1, 2003, the Company sold its working interest in a non-
operated property for a sales price of $735,000.  On August 18, 2003, 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.  The Exchanger holds the
sales proceeds pending timely identification of and the closing on the
acquisition of potential qualifying like-kind replacement properties.
Subsequent to the initial sale, the Company acquired various mineral interests
from a third party for the sum of $97,270. The acquisition price was paid out
of the funds being held by the Exchanger.  After 180 days from the initial
sale, any funds not used to acquire qualifying properties are to be returned
to the Company, and the Company will recognize a taxable gain on the unused
proceeds.

On January 30, 2004, the Company purchased an inactive natural gas pipeline
for a purchase price of $200,200 including fees, which was paid by the
Exchanger out of funds held on behalf of the Company.  Both of the above

                                   - 14 -
purchases (the "Replacement Property") qualify as tax-free exchanges under IRC
Section 1031.  During February, 2004, the Exchanger remitted approximately
$437,500 to the Company representing the net proceeds from the sale and two
purchases.


Office Space

On December 27, 2004, the Company entered into an "Assignment of Contract" as
Assignee, with Giant Energy Corp as "Assignor" whereby the Company acquired
the rights of the Assignor in the Assignor's Contract dated September 30, 2004
between the Assignor as Purchaser, and Jose Montemayor, Receiver for Colonial
Casualty Insurance Company as Seller.  The Contract is a customary real estate
purchase contract.  On the same date, the Company closed such contract and
acquired a commercial office building.  The property acquired is a two story
multi-tenant, garden office building with a sub-grade parking garage. The 20
year old building contains approximately 46,286 rentable square feet and sits
on a 1.4919 acre block of land situated in north Dallas, Texas in close
proximity to hotels, restaurants and shopping areas (the Galleria/Valley View
Mall) with easy access to Interstate Highway 635 (LBJ Freeway) and Dallas
Parkway (North Dallas Toll Road).  The Company occupies approximately 8,668
square feet of the building as its primary office headquarters, and leases the
remaining space in the building to non-related third party commercial tenants
at prevailing market rates.

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.  Additionally
on January 30, 2004, the Company acquired an inactive natural gas pipeline in
South Central Kansas.  The Kansas pipeline was later sold in December, 2004.
These pipelines are steel and polyethylene and range in size from 2 inches to
8 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 806, 713,
and 807, MCF per day for 2004, 2003, and 2002 respectively.

Oil Field Production Equipment

The Company owns various natural gas compressors, pumping units, dehydrators
and various other pieces of oil field production equipment.

Substantially all of the equipment is located on oil and gas properties
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.


                                   - 15 -
Item 3.  LEGAL PROCEEDINGS

Neither the Registrant nor its subsidiaries nor any officers or directors is a
party to any material pending legal proceedings for or against the Company or
its subsidiary nor are any of their properties subject to any proceedings.

Item 4.  SUBMISSION OF MATTERS OF SECURITY HOLDERS TO A VOTE

Not applicable


                                     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 2002, 2003 and 2004.

                                          Price Per Share
                                          High        Low
                   2002
                     First Quarter       $ .60      $ .20
                     Second Quarter        .30        .20
                     Third Quarter         .50        .28
                     Fourth Quarter        .30        .22

                   2003
                     First Quarter         .40        .40
                     Second Quarter        .55        .25
                     Third Quarter         .55        .26
                     Fourth Quarter       1.01        .32

                   2004
                     First Quarter        2.00        .70
                     Second Quarter       1.50       1.00
                     Third Quarter        2.45       1.30
                     Fourth Quarter       2.55       1.60

During the First Quarter of 2005, subsequent to year end, the following high
and low prices were recorded for the Company's common stock.

                                          Price Per Share
                                          High        Low
                   2005
                     First Quarter        5.50       2.00


                                   - 16 -
There is no amount of common stock that is subject to outstanding warrants to
purchase, or securities convertible into, common stock of the Company.

The approximate number of record holders of the Company's Common Stock on
March 31, 2004, was 611.  The 611 shareholders of record do not reflect the
number of shareholders whose stock is held in street name.  It is estimated
that as of March 31, 2005 approximately 5.2% of the Company's stock was held
in street name.

The Company has not paid any dividends since its reorganization and it is not
contemplated that it will pay any dividends on its Common Stock in the
foreseeable future.  The Business Loan Agreement entered into between the
Company and JPMorgan Chase Bank for the purpose of acquiring the commercial
office building contains restrictions on the payment of dividends in the event
a default under terms of the Business Loan Agreement has occurred and is
continuing or would result from the payment of such dividends or distributions.

The Registrant currently serves as its own stock transfer agent and registrar.

During the fourth quarter of the fiscal year ended December 31, 2004, the
Company did not repurchase any of its equity securities.  The Board of
Directors has not approved nor authorized any standing repurchase program.

Item 6.  SELECTED FINANCIAL DATA

The selected financial information presented should be read in conjunction
with the consolidated financial statements and the related notes thereto.

                                 For the years ended December 31
                      2004        2003        2002        2001        2000
                  ----------- ----------- ----------- ----------- -----------
Total Revenue     $ 4,515,000 $ 3,458,000 $ 2,084,000 $ 2,610,000 $ 2,345,000
Net Income (Loss)   1,266,000     987,000     382,000     776,000     849,000
Earnings per Share     $ 0.16      $ 0.13      $ 0.05      $ 0.10      $ 0.11

                                     As of December 31, 2004
Total Assets      $ 9,715,000 $ 5,395,000 $ 3,764,000 $ 3,486,000 $ 2,909,000
Long-Term Debt      1,800,000         -           -        55,000     246,000



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.


                                   - 17 -
Results of Operations:


                          2004 Compared to 2003

Oil and gas revenues increased for the year 2004.  This was due primarily to
an approximate 26% increase in average gas prices from $4.33 per Mcf in 2003
to $5.44 per Mcf in 2004.  Average oil prices received by the Company also
increased approximately 55% from $25.14 per bbl in 2003 to $38.90 per bbl in
2004.  Natural gas production was approximately 577,099 Mcf in 2004 compared
to 540,799 Mcf in 2003, and increase of approximately 7%. The increase gas
production is due primarily to bringing on-line our second Denton County gas
well.  Oil production was approximately 23,098 Bbls in 2004 compared to 28,747
in 2003, an approximate decrease of 20%.  The oil production decrease is
attributed to an east Texas property that was shut-in early in 2004.

Gas gathering and compression fee income was up slightly during 2004 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 as opposed to checking accounts,
as well as the higher level of cash balances earning interest in 2004 as
compared to 2003.

Lease operating expenses were higher in 2004 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 2004 due to an increase
in the cost of acquisitions added to the full cost pot, the addition of
reserves and the resulting increase in production for the year.

General and administrative expenses increased approximately $257,000.
Approximately $227,000 was 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 eight to 12 full-time
and from 39 to 44 part time and contract employees.  Approximately $30,000
was a one-time expense related to legal fees, bank charges and closing costs
associated with the acquisition of the commercial office building.

The increase in other revenues is due mainly to a $57,000 lease bonus paid to
the company, and approximately $15,000 of plant product sales by PPC.

Interest expense decreased due to payoff of the note payable to a related
party in May, 2003 and related amortization of the note discount.









                                   - 18 -
                           2003 Compared to 2002

Oil and gas revenues increased for the year 2003.  This was due primarily to
an approximate 43% increase in average gas prices from $3.02 per Mcf in 2002
to $4.33 per Mcf in 2003.  Average oil prices received by the Company also
increased approximately 8% from $23.27 per bbl in 2002 to $25.14 per bbl in
2003.  Production also increased due primarily to the acquisition of operating
interests in 22 producing oil and gas wells during the first half of 2003.
Natural gas production was approximately 541,000 Mcf in 2003 compared to
499,000 Mcf in 2003.  Oil production was approximately 28,747 Bbls in 2003
compared to 9,533 in 2002.

The increase in revenue from lease operations this year was due to the
addition of operated properties mentioned above which were acquired during the
year.  The Company bills overhead in accordance with the operating agreements,
and records as income the charges made to the non-operating interests.

Gas gathering and compression fee income decreased during 2003 as a result of
a decrease in production from properties served by PPC.  The decrease was a
result of natural decline in production.  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 as opposed to checking accounts,
as well as the higher level of cash balances earning interest in 2003 as
compared to 2002.

Lease operating expenses was higher in 2003 due to the addition of 22 operated
producing wells in 2003 and the addition of 19 producing wells in August and
September of 2002.  In addition, 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 2003 due to an
increase in the cost of acquisitions added to the full cost pot, the addition
of reserves and the resulting increase in production for the year.

General and administrative expenses increased $179,000.  Due to the acquisition
of over 40 producing oil and gas wells during the year, many in states in which
the Company has not previously operated, the headquarters staff was increased
to accommodate the additional workload.  In addition, the management fee
charged by the affiliated entity that provides management services including
supervisory personnel, was increased from $10,000 to $20,000 per month
effective January 1, 2003 (See Item 11 Executive Compensation and Footnote 6
to the Financial Statements).

Interest expense decreased due to payoff of the note payable to a related
party in May, 2003 and related amortization of the note discount.







                                   - 19 -
Certain Factors That Could Affect Future Operations


Certain information contained in this report, as well as written and oral
statements made or incorporated by reference from time to time by the Company
and its representatives in other reports, filings with the Securities and
Exchange Commission, press releases, conferences, teleconferences or otherwise,
may be deemed to be 'forward-looking statements' within the meaning of Section
21E of the Securities Exchange Act of 1934 and are subject to the 'Safe Harbor'
provisions of that section.

Forward-looking statements include statements concerning the Company's and
management's plans, objectives, goals, strategies and future operations and
performance and the assumptions underlying such forward-looking statements.
When used in this document, the words "anticipates", "estimates", "expects",
"believes", "intends", "plans", and similar expressions are intended to
identify such forward-looking statements.  Actual results and developments
could differ materially from those expressed in or implied by such statements
due to these and other factors.


Item 8. CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES INDEX AT PAGE 27


Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

The accountants for the Company are Farmer, Fuqua & Huff, P.C., who have
prepared audit reports for the years ended December 31, 2004, 2003, and 2002.

There have been no disagreements between the Company and Farmer, Fuqua, & Huff,
P.C. on any matter of accounting principles or practices, financial statement
disclosure, or auditing scope or procedure.


Item 9A. CONTROLS AND PROCEDURES

Based on their most recent evaluation, which was completed within 90 days of
the filing of this Form 10-K, our Acting Principal Executive Officer and
Acting Chief Financial Officer, believe our disclosure controls and procedures
(as defined in Exchange Act Rules 13a-14 and 15d-14) are effective. There were
not any significant changes in internal controls or in other factors that
could significantly affect these controls subsequent to the date of their
evaluation, and there has not been any corrective action with regard to
significant deficiencies and material weaknesses.


Item 9B. OTHER INFORMATION

None






                                   - 20 -
                                   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 Mazzini            47    Chairman of the Board, Director and
                                     President
      Michelle Mazzini         43    Director, Vice President and Secretary
      Paul E. Cash   72   Director

All directors hold offices until the next annual meeting of the shareholders
or until their successors are duly elected and qualified.  Officers of the
Company serve at the discretion of the board of directors.

Business experience

Chris Mazzini, Chairman of the Board of Directors and President, graduated
from the University of Texas at Arlington in 1979 with a Bachelor of Science
degree in geology.  He started his career in the oil and gas industry in 1978,
and began as a petroleum geologist with Spindletop in 1979, working the Fort
Worth Basin of North Texas.  He became Vice President of Geology at Spindletop
in 1982, and served in that capacity until he left the Company in 1985 when he
founded Giant Energy Corp. ("Giant").   Mr. Mazzini has served as President of
Giant since then. He rejoined the Company in December 1999 when he, through
Giant, purchased controlling interest from Mr. Cash.  Mr. Mazzini has been
Chairman of the Board of Directors and President of the Company since 1999 and
is a Certified and Licensed Petroleum Geologist.  Mr. Mazzini has worked
numerous geological basins throughout the United States with an emphasis on
the Fort Worth Basin.  He is responsible for several new field discoveries in
the Fort Worth Basin.

Michelle Mazzini, Vice President and General Counsel, received her Bachelor
of Science Degree in Business Administration (Major:  Accounting) from the
University of Southwestern Louisiana (now named University of Louisiana at
Lafayette) where she graduated magna cum laude in 1985.  She earned her law
degree from Louisiana State University where she graduated Order of the Coif
in 1988. Ms. Mazzini began her career with Thompson & Knight, a large law firm
in Dallas, where she focused her practice on general corporate and finance
transactions.  She also worked as Corporate Counsel for Alcatel USA, a global
telecommunications manufacturing corporation where her practice was broad-
based.  Ms. Mazzini serves as Vice President and General Counsel of the
Company.

Paul E. Cash, Director, is a graduate of The University of Texas (B.B.A.-
Accounting) and is a Certified Public Accountant.  He has been active in the
oil and gas industry for over 40 years, during which time he has served as
financial officer of two publicly-owned companies, Texas Gas Producing Co. and
Landa Oil Co., and also served as president of publicly-owned Continental
American Royalty Co., Bloomfield Royalty Co., Southern Bankers Investment Co.,
Spindletop Oil & Gas Co. (a Utah Corporation), Double River Oil & Gas Co., and
Loch Exploration Inc.  He has also been an officer and part owner of several

                                   - 21 -
private oil and gas companies and partnerships.  Mr. Cash also formerly
served as Mayor of the City of Sunnyvale, Texas.


                               Key Employees

In addition to the services provided through the management contract with
Giant by Mr. Mazzini, Ms. Mazzini (both of whom have biographies listed above)
and the services of another Giant employee, the Company also relies
extensively on the key employees identified below.

Robert E. Corbin, Controller, has been a full-time employee of Spindletop
since April 2002.  From May 2001 until April 2002, Mr. Corbin was an
independent accounting consultant and devoted substantially all of his time to
Spindletop.  He has been active in the oil and gas industry for over 30 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.

Kent Fouret, Petroleum Geologist, has been a full-time employee of Spindletop
since September 2004.  He has over 25 years experience in the oil and gas
industry as a petroleum geologist.  Mr. Fouret graduated cum laude from
Texas A & M University in 1978 with a Bachelor of Science in Geology, and in
1980, received a Master of Science in Geology from Texas A & M University.
He has a large amount of experience in the Fort Worth Basin and is a Certified
Petroleum Geologist.

Jack Koestline, Petroleum Engineer and Geologist, has been full-time employee
for Spindletop since January 2004.  Prior to that, he worked as a Petroleum
Engineer for BP Amoco in Alaska.  From 1981 to 1993, Mr. Koestline worked as
a Petroleum Geologist for Spindletop, with an emphasis on the Fort Worth Basin.
He has almost 24 years experience in the oil and gas industry.  Mr. Koestline
graduated in 1980 from the University of Texas at Arlington with a Bachelor of
Science Degree in Geology, and in 1998, received his Master of Science Degree
in Petroleum Engineering from the Colorado School of Mines.

                           Family Relationships

Michelle Mazzini, Vice President 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.






                                   - 22 -
Item 11.  EXECUTIVE COMPENSATION

Cash Compensation

For the year ended December 31, 2004, neither Mr. Mazzini nor Ms. Mazzini took
any salary from the Company.  None of the executive officers were paid cash
compensation by the Company at an annual rate in excess of $100,000.  Mr.
Mazzini and Ms. Mazzini are both employed by Giant.  Management fees the
Company paid to Giant are used to reimburse a portion of Mr. Mazzini's, Ms.
Mazzini's and other Giant employees' salaries for time spent working on
matters for the Company.

                       Compensation Pursuant to Plan

None

                            Other Compensation

Key employees and officers of the Company, may sometimes be assigned
overriding royalty interests and/or carried working interest in prospects
acquired by or generated by the Company.  These interests normally vary from
less than one percent to three percent for each employee or officer.  There is
no set formula or policy for such program, and the frequency and amounts are
largely controlled by the economics of each particular prospect.

                         Compensation of Directors

Directors are not currently compensated nor are there plans to compensate them
for their services on the board.

        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, 2004 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.







                                   - 23 -

                                                                Pct Based On
                                                    Nature of    Outstanding
    Name and Address                     Number    Beneficial     Percent of
  Of Beneficial Owner                  of Shares    Ownership       Class
----------------------------------- -------------- ----------- ---------------
Chris Mazzini                          5,900,543      Direct         77%
12850 Spurling Rd., Suite 200
Dallas, Texas 75230

Paul E. Cash                             308,468      Direct          4%
12850 Spurling Rd., Suite 200
Dallas, Texas 75230

All officers and directors
as a group                             6,209,011                     81%


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

None

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.

Key employees and officers of the Company may sometimes be assigned overriding
royalty interests and/or carried working interests in prospects acquired by or
generated by the Company.  These interests normally vary from less than one
percent to three percent for each employee or officer.  There is no set
formula or policy for such program, and the frequency and amounts are largely
controlled by the economics of each particular prospect.  We believe that these
types of compensation arrangements enable us to attract, retain and provide
additional incentives to qualified and experienced personnel.




                                   - 24 -
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 2004 and
2003 by accounting firm, Farmer, Fuqua, & Huff, P.C.

             Type of Fees              2004               2003

             Audit Fees              14,000             11,200
             Audit related fees         -                  -
             Tax fees                   -                  -
             All other fees             -                  -

Members of the Board of Directors (the "Board") fulfill the responsibilities
of an audit committee and have established policies and Procedures for the
approval and pre-approval of audit services and permitted non-audit services.
The Board has the responsibility to engage and terminate Farmer, Fuqua, & Huff,
P.C. independent auditors, to pre-approve their performance of audit services
and permitted non-audit services, to approve all audit and non-audit fees, and
to set guidelines for permitted non-audit services and fees.  All the fees for
2004 and 2003 were pre-approved by the Board or were within the pre-approved
guidelines for permitted non-audit services and fees established by the
Board,and there were no instances of waiver of approved requirements or
guidelines during the same periods.


PART IV

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 . . . 29
             Consolidated Balance Sheets . . . . . . . . . . . . . 30
             Consolidated Statement of Income. . . . . . . . . . . 32
             Consolidated Statement of Changes in
               Stockholders' Equity  . . . . . . . . . . . . . . . 33
             Consolidated Statements of Cash Flows . . . . . . . . 34
             Notes to Consolidated Financial Statements  . . . . . 35

         (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.






                                   - 25 -
         (3) EXHIBITS
     The following documents are filed as exhibits (or are incorporated by
     reference as indicated) into this Report:


                                   - 25 -
     Exhibit
   Designation                        Description

       3.1        Articles of Incorporation of Spindletop Oil & Gas Co.
                  (previously filed with our General Form for Registration of
                  Securities on Form 10, filed with the Commission on August
                  14, 1990)

       3.2        Bylaws of Spindletop Oil & Gas Co. (previously filed with
                  our General Form for Registration of Securities on Form 10,
                  filed with the Commission on August 14, 1990)

       14         Code of Ethics for Senior Financial Officers

       21         Subsidiaries of the Registrant

      31.1        Rule 13a-14(a) Certification of Chief Executive Officer

      31.2        Rule 13a-14(a) Certification of Chief Executive Officer

       32         Officers' Section 1350 Certifications


(b) The Index of Exhibits is included following the Financial Statement
            Schedules beginning at page 52 of this Report.

(c) The Index to Consolidated Financial Statements and Supplemental Schedules
is included following the signatures, beginning at page 28 of this Report.






















                                   - 26

                                   SIGNATURES


Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Company has duly caused this Report to be signed on its behalf
by the undersigned, thereunto duly authorized.


                            SPINDLETOP OIL & GAS CO.



Dated: April 15, 2005


                                              By /s/ Chris Mazzini
                                              ________________________
                                                 Chris Mazzini
                                                 President, Director


Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below by the following on behalf of the Company and in
the capacities and on the dates indicated.




       Signatures   Capacity   Date
   Principal Executive Officers:

/s/ Chris Mazzini
__________________________________     President, Director     April 15, 2004
Chris Mazzini



/s/  Michelle Mazzini
__________________________________     Secretary, Director     April 15, 2004
Michelle Mazzini



/s/  Robert E. Corbin
__________________________________     Controller              April 15, 2004
Robert E. Corbin



/s/ Paul E. Cash
__________________________________     Director                 April 15, 2004
Paul E. Cash



                                   - 27 -
                 SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
         Index to Consolidated Financial Statements and Schedules


                                                                       Page


Report of Independent Registered Public Accounting Firm . . . . . . . . 29

Consolidated Balance Sheets - December 31, 2004 and 2003  . . . . . . . 30

Consolidated Statements of Income for the years
  Ended December 31, 2004, 2003 and 2002  . . . . . . . . . . . . . . . 32

Consolidated Statements of Changes in Shareholders'
  Equity for the years ended December 31, 2004, 2003, and 2002. . . . . 33

Consolidated Statements of Cash Flows for the years ended
  December 31, 2004, 2003 and 2002  . . . . . . . . . . . . . . . . . . 34

Notes to Consolidated Financial Statements  . . . . . . . . . . . . . . 35

Schedules for the years ended December 31, 2004, 2003 and 2002
  II - Valuation and Qualifying Accounts  . . . . . . . . . . . . . . . 53
 III - Real Estate and Accumulated Depreciation . . . . . . . . . . . . 54

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.



























                                   - 28 -


          REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



To the Board of Directors and
Shareholders of Spindletop Oil & Gas Company

We have audited the accompanying consolidated balance sheets of Spindletop Oil
& Gas Company (A Texas Corporation) and subsidiaries as of December 31, 2004
and 2003, 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, 2004. These consolidated financial statements are the
responsibility of the company's management. Our responsibility is to express
an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company
 Accounting Oversight Board (United States). Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the
consolidated financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the consolidated financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Spindletop Oil &
Gas Company and subsidiaries as of December 31, 2004 and 2003, and the
consolidated results of their operations and their cash flows for each of the
years in the three-year period ended December 31, 2004 in conformity with
accounting principles generally accepted in the United States of America.

Our audits were made for the purpose of forming an opinion on the basic
consolidated financial statements taken as a whole. The schedules listed in
the index of consolidated financial statements are presented for purposes of
complying with the Securities and Exchange Commission's rules and are not part
of the basic consolidated financial statements.  These schedules have been
subjected to the auditing procedures applied in the audits of the basic
consolidated financial statements and, in our opinion, fairly state, in all
material respects, the financial data required to be set forth therein in
relation to the basic consolidated financial statements taken as a whole.

FARMER FUQUA & HUFF, P.C.




Plano, Texas
April 13, 2005





                                   - 29 -

                SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS


                                                        As of December 31
                                                   --------------------------
                                                       2004          2003
                                                   -----------    -----------
                ASSETS

Current Assets
  Cash                                             $ 4,352,000    $ 2,662,000
  Accounts receivable, trade                           617,000        565,000
  Accounts receivable, other                               -          638,000
  Prepaid income tax                                   190,000            -
                                                   -----------    -----------
    Total current assets                             5,159,000      3,865,000
                                                   -----------    -----------

Property and Equipment, at cost
  Oil and gas properties (full cost method)          5,983,000      4,460,000
  Rental equipment                                     399,000        399,000
  Gas gathering systems                                145,000        145,000
  Other property and equipment                         102,000         85,000
                                                   -----------    -----------
                                                     6,629,000      5,089,000
  Accumulated depreciation and amortization         (4,059,000)    (3,561,000)
                                                   -----------    -----------
    Total property and equipment, net                2,570,000      1,528,000
                                                   -----------    -----------

Real Estate Property, at cost
  Land                                                 688,000            -
  Commercial office building                         1,298,000            -
  Accumulated depreciation                              (1,000)           -
                                                   -----------    -----------
    Total real estate property, net                  1,985,000            -
                                                   -----------    -----------

Other Assets                                             1,000          2,000
                                                   -----------    -----------
Total Assets                                       $ 9,715,000    $ 5,395,000
                                                   ===========    ===========










The accompanying notes are an integral part of these statements.

                                   - 30 -

                 SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
                 CONSOLIDATED BALANCE SHEETS - (Continued)


                                                        As of December 31
                                                   --------------------------
                                                       2004           2003
                                                   -----------    -----------
   LIABILITIES AND SHAREHOLDERS' EQUITY

Current Liabilities
  Notes payable, current portion                   $   120,000    $       -
  Accounts payable and accrued liabilities           2,068,000        962,000
  Income tax payable                                       -          278,000
  Tax savings benefit payable                           97,000         97,000
                                                   -----------    -----------
    Total current liabilities                        2,285,000      1,337,000
                                                   -----------    -----------

Notes payable, long-term portion                     1,680,000            -
                                                   -----------    -----------

Deferred income tax payable                            461,000         18,000
                                                   -----------    -----------

Shareholders' Equity
  Common stock, $.01 par value; 100,000,000
   Shares authorized; 7,677,471 shares
   Issued and outstanding at
   December 31, 2004 and 2003. 111,668
   shares of Treasury Stock at December 31,
   2004 and 103,334 shares of Treasury Stock
   at December 31, 2003                                 77,000         77,000
Additional paid-in capital                             806,000        796,000
Treasury Stock at cost of $0.175 per share             (45,000)       (18,000)
Retained earnings                                    4,451,000      3,185,000
                                                   -----------    -----------
  Total shareholders' equity                         5,289,000      4,040,000
                                                   -----------    -----------

Total Liabilities and Shareholders' Equity         $ 9,715,000    $ 5,395,000
                                                   ===========    ===========











The accompanying notes are an integral part of these statements.

                                   - 31 -

                 SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF INCOME


                                                Years Ended December 31,
                                          -----------------------------------
                                              2004        2003        2002
                                          ----------- ----------- -----------
Revenues
  Oil and gas revenue                     $ 4,039,000 $ 3,100,000 $ 1,733,000
  Revenue from lease operations               127,000      92,000      46,000
  Gas gathering, compression and
  Equipment rental                            158,000     152,000     176,000
  Real estate rental income                     3,000         -           -
  Interest income                             100,000     107,000      90,000
  Other                                        88,000       7,000      39,000
                                          ----------- ----------- -----------
    Total revenue                           4,515,000   3,458,000   2,084,000
                                          ----------- ----------- -----------

Expenses
  Lease operations                          1,235,000   1,237,000     790,000
  Pipeline and rental operations               24,000      30,000      25,000
  Real estate operations                        2,000         -           -
  Depreciation and amortization               498,000     331,000     278,000
  General and administrative                  903,000     646,000     467,000
  Interest expense                                -         3,000       9,000
                                          ----------- ----------- -----------
    Total expenses                          2,662,000   2,247,000   1,569,000
                                          ----------- ----------- -----------
Income before income tax                    1,853,000   1,211,000     515,000
                                          ----------- ----------- -----------

Current tax provision                         144,000     385,000      75,000
Deferred tax provision                        443,000    (161,000)     58,000
                                          ----------- ----------- -----------
                                              587,000     224,000     133,000
                                          ----------- ----------- -----------

Net income                                $ 1,266,000 $   987,000 $   382,000
                                          =========== =========== ===========

Earnings per Share of Common Stock
  Basic                                       $  0.16     $  0.13     $  0.05
                                          =========== =========== ===========
  Diluted                                     $  0.16     $  0.13     $  0.05
                                          =========== =========== ===========

Weighted Average Shares Outstanding         7,677,471   7,640,074   7,582,471
                                          =========== =========== ===========
Diluted Shares Outstanding                  7,689,766   7,751,444   7,525,804
                                          =========== =========== ===========

The accompanying notes are an integral part of these statements.

                                   - 32 -
                 SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
         CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
               YEARS ENDED DECEMBER 31, 2004, 2003, and 2002

                                     Additional     Treasury
                      Common Stock     Paid-In        Stock         Retained
                    Shares   Amount    Capital   Shares   Amount    Earnings
                  --------- -------- ---------- -------- -------- -----------
Bal Dec 31, 2001  7,525,804 $ 75,000 $  733,000      -   $    -   $ 1,816,000

Issuance of 56,667
shares of Common
Stock for the
purchase of a
drilling prospect    56,667    1,000     16,000      -        -           -

Issuance of options
to purchase Common
Stock                   -        -       27,000      -        -           -

Purchase of
Treasury Stock          -        -          -    103,334   18,000         -

Net Income              -        -          -        -        -       382,000
                  --------- -------- ---------- -------- -------- -----------
Bal Dec 31, 2002  7,582,471   76,000    776,000  103,334   18,000   2,198,000

Issuance of 25,000
Shares of Common
Stock for the
Purchase of a
Drilling prospect    25,000      -          -        -        -           -

Issuance of 70,000
Shares of Common
Stock upon exercise
of stock option      70,000    1,000     20,000      -        -           -

Net Income              -        -          -        -        -       987,000
                  --------- -------- ---------- -------- -------- -----------
Bal Dec 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
                  --------- -------- ---------- -------- -------- -----------
                  7,677,471 $ 77,000 $  806,000  111,668 $ 45,000 $ 4,451,000
                  ========= ======== ========== ======== ======== ===========

      The accompanying notes are an integral part of these statements.
                                   - 33 -

                 SPINDLETOP OIL & GAS CO AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF CASH FLOWS

                                                Years Ended December 31,
                                          -----------------------------------
                                              2004        2003        2002
                                          ----------- ----------- -----------
Cash Flows from Operating Activities
  Net Income                              $ 1,266,000 $   987,000 $   382,000
  Reconciliation of net income
    to net cash provided by
    Operating Activities
     Depreciation and amortization            498,000     331,000     278,000
     Amortization of note discount                -        (3,000)     (9,000)
     Changes in accounts receivable           (52,000)   (291,000)    (99,000)
     Changes in prepaid income tax           (190,000)    109,000     (20,000)
     Changes in accounts payable            1,106,000     548,000      56,000
     Changes in current taxes payable        (278,000)    278,000         -
     Changes in deferred taxes payable        443,000    (161,000)     58,000
     Changes in other assets                    1,000      (2,000)         -
                                          ----------- ----------- -----------
Net cash provided by operating
  activities                                2,794,000   1,796,000     646,000
                                          ----------- ----------- -----------
Cash flows from Investing Activities
  Capitalized acquisition, exploration
    and development costs                    (884,000)  (1,162,000)  (670,000)
  Purchase of property and equipment          (18,000)       -            -
  Purchase of commercial office building     (185,000)       -            -
                                          ----------- ----------- -----------
Net cash provided by (used for) investing
  activities                               (1,087,000)  (1,162,000)  (670,000)
                                          ----------- ----------- -----------
Cash Flows from Financing Activities
  Repayment note payable related party            -        (39,000)  (235,000)
  Purchase 103,334 sh of treasury stock           -            -      (18,000)
  Purchase 83,334 sh of treasury stock        (40,000)         -          -
  Issue 70,000 sh of common stock                 -          1,000        -
  Issue 75,000 shares of common stock          23,000          -          -
                                          ----------- ----------- -----------
Net cash used for financing
  activities                                  (17,000)     (18,000)   (253,000)
                                          ----------- ----------- -----------

Increase (decrease) in cash                 1,690,000     616,000    (277,000)

Cash at beginning of period                 2,662,000   2,046,000   2,323,000
                                          ----------- ----------- -----------
Cash at end of period                     $ 4,352,000 $ 2,662,000 $ 2,046,000
                                          =========== =========== ===========



The accompanying notes are an integral part of these statements.

                                   - 34 -
                 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 h had previously filed for Chapter 11
bankruptcy. In connection with the Plan, Exploration was merged into the
Company, with the Company being the surviving corporation.  After giving
effect to the stock split discussed in Note 2, up to a total of 166,667 of
the Company's common shares may be issued to Exploration's former
shareholders.  As of December 31, 2004, 2003, and 2002, 122,436 shares
have been issued to former shareholders in connection with the Plan.

Spindletop Oil & Gas Co. is engaged in the exploration, development and
production of oil and natural gas; and through one of its subsidiaries, the
gathering and marketing of natural gas.

On December 27, 2004, the Company purchased a commercial office building and
related land. The building contains approximately 46,286 of rentable square
feet, of which the Company occupies approximately 8,668 square feet as its
corporate office headquarters.  The Company leases the remaining space in the
building to non-related third party commercial tenants at prevailing market
rates.


2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A summary of the significant accounting policies consistently applied in the
preparation of the accompanying financial statements follows:

Consolidation
-------------
The consolidated financial statements include the accounts of Spindletop
Oil & Gas Co. and its wholly owned subsidiaries, Prairie Pipeline Co. and
Spindletop Drilling Company.  All significant inter-company transactions and
accounts have been eliminated.

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

                                   - 35 -
cost centers, on a country-by-country basis.  If unamortized costs within a
cost center exceed the cost center ceiling (as defined), the excess is charged
to expense during the year in which the excess occurs.

Depreciation and amortization for each cost center are computed on a composite
unit-of-production method, based on estimated proven reserves attributable to
the respective cost center. All costs associated with oil and gas properties
are currently included in the base for computation and amortization.  Such
costs include all acquisition, exploration and development costs. All of the
Company's oil and gas properties are located within the continental United
States.

Gains and losses on sales of oil and gas properties are treated as adjustments
of capitalized costs. Gains or losses on sales of property and equipment, other
than oil and gas properties, are recognized as part of operations.
Expenditures for renewals and improvements are capitalized, while expenditures
for maintenance and repairs are charged to operations as incurred.

Property and Equipment
----------------------
The Company, as operator, leases equipment to owners of oil and gas wells, on
a month-to-month basis.

The Company, as operator, transports gas through its gas gathering systems, in
exchange for a fee.

Depreciation is provided in amounts sufficient to relate the cost of
depreciable assets to operations over their estimated service lives (5 to 10
years for rental equipment and gas gathering systems, 4 to 5 years for other
property and equipment).  The straight-line method of depreciation is used for
financial reporting purposes, while accelerated methods are used for tax
purposes.

Real Estate Property
--------------------
The Company owns land along with a two-story commercial office building which
is situated thereon. The Company occupies a portion of the building as its
primary corporate headquarters, and leases the remaining space in the building
to non-related third party commercial tenants at prevailing market rates.  The
Company depreciates the commercial office using the straight-line method of
depreciation for financial statement and income tax purposes.

Inventory
---------
Inventory consists of oil field materials and supplies, stated at the lower
of average cost or market.

Income Taxes
------------
The Company accounts for income taxes pursuant to Statement of Financial
Accounting Standards No. 109  "Accounting for Income Taxes" (SFAS 109), which
requires the recognition of deferred tax liabilities and assets for the
expected future tax consequences of events that have been recognized in the
Company's financial statements or tax returns. Under this method, deferred tax


                                   - 36 -
liabilities and assets are determined based on the difference between the
financial statement carrying amounts and tax bases of assets and liabilities,
using enacted tax rates in effect in the years in which the differences are
expected to reverse.  The temporary differences primarily relate to
depreciation, depletion and intangible drilling costs.

Use of Estimates
----------------
The preparation of financial statements in conformity with 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.


3.  ACCOUNTS RECEIVABLE
                                                         December 31,
                                                 ----------------------------
                                                     2004            2003
                                                 ------------    ------------
      Trade                                      $    268,000    $     85,000
      Accrued receivable                              379,000         510,000
                                                 ------------    ------------
                                                      647,000         595,000
      Less: Allowance for losses                      (30,000)        (30,000)
                                                 ------------    ------------
                                                 $    617,000    $    565,000
                                                 ============    ============

4.  ACCOUNTS PAYABLE
                                                         December 31,
                                                 ----------------------------
                                                     2004            2003
                                                 ------------    ------------
      Trade payables                             $  1,053,000    $    360,000
      Production proceeds payable                     929,000         433,000
      Other                                            86,000         169,000
                                                  -----------    ------------
                                                  $ 2,068,000    $    962,000
                                                  ===========    ============


5.  NOTES PAYABLE
                                                         December 31,
                                                 ----------------------------
                                                     2004            2003
                                                 ------------    ------------
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

                                   - 37 -
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.                                         $  1,800,000    $        -

Less current maturities                               120,000             -
                                                 ------------    ------------
  Total notes payable, long-term portion         $  1,680,000    $        -
                                                 ============    ============

Estimated annual maturities for long-term debt are as follows:

                          2005            $   120,000
                          2006                120,000
                          2007                120,000
                          2008                120,000
                          2009                120,000
                        hereafter           1,200,000


6. RELATED PARTY TRANSACTIONS

Since 1999 Giant has charged the Company a fee pursuant to a management
services agreement.  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.  Effective January 1, 2003,
the monthly fee was increased from $10,000 to $20,000 per month.

The Company has guaranteed a $50,000 letter of credit and a $25,000 letter of
credit issued by a credit union for the benefit of two affiliated companies in
favor of the Railroad Commission of Texas.  These letters of credit were issued
in accordance with the filing of a P-5 Organization Report as required by the
Texas Natural Resources Code in order to perform operations within the
jurisdiction of the Railroad Commission of Texas.  These letters of credit are
secured by a restriction of certain funds of the Company on deposit at the
credit union issuing the letters of credit.

The Long-term Debt, which is secured by the commercial office building, is
also guaranteed individually by Chris G. Mazzini and Michelle H. Mazzini,
related parties.


7. STOCK OPTIONS

During 2002, the Company entered into two stock option agreements with third-
parties and issued stock options to purchase up to 145,000 shares of restricted
common stock at a value of $0.30 per share and other consideration to obtain
interests in oil and gas properties.  On July 9, 2003, options to purchase
70,000 shares of stock were exercised and 70,000 shares of common stock were

                                   - 38 -
issued.  On April 30, 2004 options to purchase 75,000 shares of common stock
were exercised and 75,000 shares were issued using treasury stock of the
company.

The Company has elected to account for the options using FASB Statement 123,
"Accounting for Stock-Based Compensation," (FAS No. 123) which requires the
use of option valuation models.  The fair value of these options was estimated
at the date of grant using the Black-Scholes option pricing model with the
following assumption ranges:  risk free interest rates of 1-2%, volatility
factor of 170, and an expected life of 1 year - 1.5 years.  Using the Black-
Scholes option evaluation model, the weighted average value of the option
granted during 2002 was $0.19, per option respectively.  The effect of applying
the fair value method of FAS No. 123 to the stock options granted during 2002
had a $26,850 effect which was applied to the oil and gas properties and will
be amortized using the full cost method. These options had no dilutive effect
on earnings per share.

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 2004, 2003 and 2002, respectively.  As of
December 31, 2003 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, 2004 and 2003,
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 the U.S. federal
income tax rate of 35% to pretax income in 2004, 2003 and 2002 as a result of
the following:

                                             2004         2003        2002
                                          -----------  ----------  ----------
    Computed expected tax expense         $   649,000  $  424,000  $  180,000
    Miscellaneous timing differences
      related to book and tax depletion
      differences and the expensing of
      intangible drilling costs              (505,000)    (39,000)   (105,000)
                                          -----------  ----------  ----------
                                          $   144,000  $  385,000  $   75,000
                                          ===========  ==========  ==========

                                   - 39 -
Deferred income taxes reflect the effects of temporary differences between
the tax bases of assets and liabilities and the reported amounts of those
assets and liabilities for financial reporting purposes. Deferred income
taxes also reflect the value of net operating losses, investment tax credits
and an offsetting valuation allowance.  The Company's total deferred tax
assets and corresponding valuation allowance at December 31, 2004 and 2003
consisted of the following:

                                                         December 31,
                                                 ----------------------------
                                                     2004            2003
                                                 ------------    ------------
  Deferred tax assets
    Investment tax credit carry-forwards         $      1,000    $      1,000
    Depreciation, depletion and amortization          497,000         393,000
    Other, net                                          8,000           8,000
                                                 ------------    ------------
      Total                                           506,000         402,000

  Deferred tax liabilities
    Expired leasehold                                 (50,000)        (50,000)
    Intangible drilling costs                        (917,000)       (370,000)
                                                  ------------    ------------
  Net deferred tax liability                         (461,000)        (18,000)
                                                  ============    ============


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 $ -0-, $ -0- and $ -0- in 2004, 2003 and 2002, respectively.  Also
included are cash payments for taxes of $ 260,000 , $122,000 , and $ -0- in
2004, 2003 and 2002, respectively.

Excluded from the Consolidated Statements of Cash Flows were the effects of
certain non-cash investing and financing activities, as follows:

                                               2004        2003        2002
                                           ----------- ----------- -----------
  Purchase of oil and gas properties
    for common stock                       $       -   $       -   $    17,000
  Purchase of commercial office building
    in exchange for note payable             1,800,000         -           -
  Accounts Receivable, Other in
  Exchange for the sale of interest
    in non-operated oil & gas lease                -       735,000         -
  Acquisition of various mineral
    interests                                      -       (97,000)        -
                                           ----------- ----------- -----------
                                           $ 1,800,000 $   638,000 $    17,000
                                           =========== =========== ===========

                                   - 40 -
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. All calculations have
been adjusted for the effects of the stock split discussed in Note 2. The
adoption of SFAS 128 had no effect on previously reported EPS.  Diluted EPS
is computed based on the weighted number of shares outstanding, plus the
additional common shares that would have been issued had the options
outstanding been exercised.

11.  CONCENTRATIONS OF CREDIT RISK

As of December 31, 2004, the Company had approximately $2,505,000 in accounts
 at one bank, and $1,847,000 in one Credit Union.

Most of the Company's business activity is located in Texas.  Accounts
receivable as of December 31, 2004 and 2003 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, 2004 and 2003 follow:
                                -------- 2004 ------    -------- 2003 -------
 Carrying  Fair  Carrying  Fair
                                 mount       Value      Amount       Value
                              ----------- ----------- ----------- -----------
     Cash                     $ 4,352,000 $ 4,352,000 $ 2,662,000 $ 2,662,000
     Accounts receivable          617,000     617,000     565,000     565,000
     Accounts receivable, other       -           -       638,000     638,000



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


                                   -41 -
of wells and rate of production, and require prevention and clean-up pollution.

Although the Company has not in the past incurred substantial costs in
complying with such laws and regulations, future environmental restrictions
or requirements may materially increase the Company's capital expenditures,
reduce earnings, and delay or prohibit certain activities.

At December 31, 2004, the Company has acquired bonds and letters of credit
issued in favor of various state regulatory agencies as mandated by state law
in order to comply with financial assurance regulations required to perform
oil and gas operations within the various state jurisdictions.

The Company has eleven, $5,000 single-well bonds totaling $50,000 with an
insurance company, for wells the Company operates in Alabama.  The bonds are
written for a three year period.  The Company also has a single-well bond in
the amount of $10,000 with a different insurance company for a well operated
in New Mexico.  This bond renews annually.

The Company has nine letters of credit from a credit union issued for the
benefit of various state regulatory agencies in Arkansas, Louisiana, Oklahoma,
and Texas, ranging in amounts from $25,000 to $50,000 and totaling  $300,000.
These letters of credit have expiration dates that range from August 4, 2005
through December 29, 2006, and are secured by funds on deposit with the
credit union in business money market accounts.


14.  OPERATING LEASE OBLIGATIONS

None


15.    ADDITIONAL OPERATIONS AND BALANCE SHEET INFORMATION

Certain information about the Company's operations for the years ended
December 31, 2004, 2003, and 2002 follows.

Sale of Oil & Gas Properties
----------------------------

Effective August 1, 2003, the Company sold its working interest in a non-
operated property (the "Relinquished Property") for a sales price of $735,000.
On August 18, 2003, 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.  The
Exchanger holds the sales proceeds pending timely identification of and the
closing on the acquisition of potential qualifying like-kind replacement
properties.  Subsequent to the initial transaction, the Company acquired
various mineral interests from a third party for the sum of $97,000, and the
acquisition price was paid out of the funds being held by the Exchanger.
After 180 days, any funds not used to acquire qualifying properties are to be
returned to the Company, and the Company will recognize a taxable gain on the
unused proceeds.

As of December 31, 2003, the Exchanger held approximately $638,000 for the
account of the Company.  The transaction has been reported in the

                                   - 42 -
accompanying financial statements as an Other Account Receivable, with the
net proceeds from the sale being credited to Oil & Gas Properties under the
full cost method of accounting.

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.

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, 2004.

                                             Year Ended December 31, (1)
                                          --------------------------------
            Purchaser                         2004       2003       2002
-----------------------------------------   --------   --------   --------
Enbridge Energy Partners                       14%        17%        22%
Panther Pipeline North Texas, Inc.             13%         -          -
Devon Gas Services, L.P                        12%        20%        38%
Dynegy Midstream Services, LIM                 11%         -          -

                                   - 43 -
Crosstex Energy Services, Ltd                   8%         -          -
Plains Marketing, LP.                           6%         7%         -
Shell Trading (US) Company                      6%         9%         -
LIG Chemical Company                            2%         9%         -

(1)  Percent of Total Oil & Gas Sales

Oil and Gas is sold to approximately 105 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, LIG Chemical Company, 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, 2004.

The Company currently has no hedged contracts.

Certain revenues, costs and expenses related to the Company's oil and gas
operations are as follows:

                                                Year Ended December 31,
                                          -----------------------------------
                                              2004        2003        2002
                                          ----------- ----------- -----------
  Capitalized costs relating to oil
    and gas producing activities:

      Unproved properties                 $   696,000 $       -   $       -
      Proved properties                     5,287,000   4,306,000   3,910,000
                                          ----------- ----------- -----------
        Total capitalized costs             5,983,000   4,460,000   3,910,000

      Accumulated amortization             (3,467,000) (2,990,000) (2,683,000)
                                          ----------- ----------- -----------
        Total capitalized costs, net      $ 2,516,000 $ 1,470,000 $ 1,227,000
                                          =========== =========== ===========



                                                  Year Ended December 31,
                                          -----------------------------------
                                              2004        2003       2002
                                          ----------- ----------- -----------
  Costs incurred in oil and gas property
    acquisition, exploration and
    development:
      Acquisition of properties           $       -   $   538,000 $  373,000
      Development costs                     1,526,000     720,000    295,000
                                          ----------- ----------- -----------
        Total costs incurred              $ 1,526,000 $ 1,258,000 $  668,000
                                          =========== =========== ===========


                                   - 44 -
                                                 Year Ended December 31,
                                          -----------------------------------
                                              2004        2003        2002
                                          ----------- ----------- -----------
Results of Operations from producing
  activities:
    Sales of oil and gas                  $ 4,039,000 $ 3,100,000 $ 1,733,000
                                          ----------- ----------- -----------

    Production costs                        1,235,000   1,237,000     790,000
    Amortization of oil and gas
      Properties                              477,000     307,000     248,000
                                          ----------- ----------- -----------
    Total production costs                  1,712,000   1,544,000   1,038,000
                                          ----------- ----------- -----------
      Total net revenue                   $ 2,327,000 $ 1,556,000 $   695,000
                                          =========== =========== ===========



                                                  Year Ended December 31,
                                          -----------------------------------
                                              2004        2003        2002
                                          ----------- ----------- -----------
 Sales price per equivalent Mcf             $  5.64     $  4.35     $  3.11
                                          =========== =========== ===========

Production costs per equivalent Mcf         $  1.73     $  1.73     $  1.42
                                          =========== =========== ===========

Amortization per equivalent Mcf             $   .67     $   .44     $   .45
                                          =========== =========== ===========



                                                  Year Ended December 31,
                                          -----------------------------------
                                              2004        2003        2002
                                          ----------- ----------- -----------
Results of Operations from gas
gathering and equipment rental
activities:

  Revenue                                 $   158,000 $   152,000 $   176,000
                                          ----------- ----------- -----------

  Operating expenses                           24,000      30,000      25,000
  Depreciation                                 10,000      14,000      18,000
                                          ----------- ----------- -----------
    Total costs                                34,000      44,000      43,000
                                          ----------- ----------- -----------
      Total net revenue                   $   124,000 $   108,000 $   133,000
                                          =========== =========== ===========



                                   - 45 -
16.  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, 2004:


                                                 Year Ended December 31,
                                          -----------------------------------
                                              2004        2003        2002
                                          ----------- ----------- -----------
Revenues: (3)
  Oil and gas exploration, production
    and operations                       $ 4,166,000  $ 3,192,000 $ 1,779,000
  Gas gathering, compression and
    equipment rental                         158,000      152,000     176,000
  Real estate rental                           3,000          -           -
                                          ----------- ----------- -----------
                                          $ 4,327,000 $ 3,344,000 $ 1,955,000
                                          =========== =========== ===========



Depreciation, depletion and
Amortization expense:
  Oil and gas exploration, production
    and operations                        $   487,000 $   317,000 $   260,000
  Gas gathering, compression and
    equipment rental                           10,000      14,000      18,000
  Real estate rental                            1,000         -           -
                                          ----------- ----------- -----------
                                          $   498,000 $   331,000 $   278,000
                                          =========== =========== ===========



Income from operations:
  Oil and gas exploration, production
    and operations                        $ 2,445,000 $ 1,638,000 $  729,000
  Gas gathering, compression and
    equipment rental                          123,000     108,000    133,000
  Real estate rental                            -           -          -
                                          ----------- ----------- -----------
                                            2,568,000   1,746,000    865,000
Corporate and other (1)                    (1,302,000)   (759,000)  (480,000)
                                          ----------- ----------- -----------
Consolidated net income (loss)            $ 1,266,000 $   987,000 $   382,000
                                          =========== =========== ===========





                                   - 46 -
Identifiable Assets:
  Oil and gas exploration, production
    and operations                        $ 2,531,000 $ 1,630,000 $ 1,271,000
  Gas gathering, compression and
    equipment rental                           39,000      49,000      64,000
  Real estate rental                        1,985,000         -           -
                                          ----------- ----------- -----------
                                          $ 4,555,000 $ 1,679,000 $ 1,335,000
Corporate and other (2)                     5,160,000   3,716,000  2,429,000
                                          ----------- ----------- -----------
Consolidated total assets                 $ 9,715,000 $ 5,395,000 $ 3,764,000
                                          =========== =========== ===========


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.




17.   SUPPLEMENTARY INCOME STATEMENT INFORMATION

The following items were charged directly to expense:

                                                  Year Ended December 31,
                                          -----------------------------------
                                              2004        2003        2002
                                          ----------- ----------- -----------
  Maintenance and repairs                 $    13,000 $    7,000  $     4,000
  Production taxes                            236,000    169,000      101,000
  Taxes, other than payroll and
    income taxes                               42,000     54,000       24,000



















                                   - 47 -
18.   SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)

The Company's net proved oil and natural gas reserves as of December 31, 2004,
2003 and 2002 have been estimated by Company personnel in accordance with
guidelines established by the Securities and Exchange Commission.  Accordingly,
the following reserve estimates were based on existing economic and operating
conditions.  Oil and gas prices in effect at December 31 of each year were
used.  Operating costs, production and ad valorem taxes and future development
costs were based on current costs with no escalation.

There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting the future rates of production and timing of
development expenditures.  The following reserve data represents estimates
only and should not be construed as being exact.  Moreover, the present values
should not be construed as the current market value of the Company's oil and
gas reserves or the costs that would be incurred to obtain equivalent reserves.

Changes in Estimated Quantities of Proved Oil and Gas Reserves (Unaudited):

                                                    Crude Oil     Natural Gas
                                                       Bbls          Mcf
                                                  ------------   ------------
Quantities of Proved Reserves:
------------------------------
  Balance December 31, 2001                             42,970      6,409,520
    Sales of reserves in place                             -              -
    Acquired properties                                116,662     10,439,648
    Extensions and discoveries                             -           51,615
    Revisions of previous estimates                      2,915       (127,122)
    Production                                          (9,553)      (499,081)
                                                  ------------   ------------
  Balance December 31, 2002                            152,994     16,274,580
    Sales of reserves in place                              (2)    (2,815,000)
    Acquired properties                                101,308        482,926
    Revisions of previous estimates                    139,677     (4,048,147)
    Production                                         (28,747)      (540,799)
                                                  ------------   ------------
  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
                                                  ============   ============

Proved Developed Reserves:
--------------------------
  Balance December 31, 2002                            152,994      4,976,890
  Balance December 31, 2003                            365,230      4,978,309
  Balance December 31, 2004                            389,851      6,887,978




                                   - 48 -
18.  SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) - Continued

Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil and Gas Reserves
(Unaudited)

The Standardized Measure of Discounted Future Net Cash Flows and Changes
Therein Relating to Proved Oil and Gas Reserves ("Standardized Measures") does
not purport to present the fair market value of a company's oil and gas
properties.  An estimate of such value should consider, among other factors,
anticipated future prices of oil and gas, the probability of recoveries in
excess of existing proved reserves, the value of probable reserves and
acreage prospects, and perhaps different discount rates.  It should be noted
that estimates of reserve quantities, especially from new discoveries, are
inherently imprecise and subject to substantial revision.

Reserve estimates were prepared in accordance with standard Security and
Exchange Commission guidelines.  The future net cash flow was computed using
year-end 2004 oil and gas prices.  Lease operating costs, compression,
dehydration, transportation, ad valorem taxes, severance taxes, and federal
income taxes were deducted.  Costs and prices were held constant and were not
escalated over the life of the properties.  No deduction has been made for
interest, or general corporate overhead.  The annual discount of estimated
future cash flows is defined, for use herein, as future cash flows discounted
at 10% per year, over the expected period of realization.

Proved Developed Reserves were calculated based on Decline Curve Analysis on
79 operated wells and 68 non-operated wells.  Shut-in operated wells and
insignificant non-operated wells were excluded from the reserve estimate.

During 2004, the Company completed its second Barnett Shale gas well in
Denton Co. adding net Proved Developed Producing reserves of 3,590 BO and
301,000 MCFG.  In addition two previously non-producing gas wells were
restored to production adding PDP reserves of 273,000 MCFG.  The Company also
participated in the various non-operated wells.  These non-operated wells
added 303,146 MCFG to the net Proved Developed Producing Reserves.

Proved Undeveloped Reserves were attributed to 11 well locations in the
Barnett Shale gas play (6 in Denton County and 5 in Parker County).  Two of
these 11 well locations were drilled in 2004 but were not completed until the
first quarter of 2005.  The Olex U.S. #4 well was completed on January 20, 2005
with an initial potential of 1,184 MCFG/D and 46 BO/D and placed on production
on January 23, 2005.  The Olex U.S. #3 well went into production on March 28,
2005 with an initial rate of 800 MCFG/D.  The Company's Olex U.S. lease is
offset in all directions by productive Barnett Shale gas wells and with
existing spacing rules an additional 13 wells could be drilled on this lease.
However, for this report, reserves were only attributed to 4 additional well
locations on this lease which are scheduled to be drilled in the next twenty-
four months, providing that the Company can secure the necessary drilling
equipment on a timely basis. The Company may take on partners to reduce risk
in any one project in which case it would also reduce reported reserves.





                                   - 49 -
The Barnett Shale gas play is expanding rapidly into Parker County, Texas
where Spindletop has a large acreage position.  The company plans to drill 5
horizontal Barnett Shale wells in Parker County in the next twenty-four months
providing that the Company can secure the necessary drilling equipment on a
timely basis. The Company may take on partners to reduce risk in any one
project in which case it would also reduce reported reserves.

In the northeast quarter of Parker County at Springtown, the Company holds
approximately 1750 acres of leasehold by production, and has 3D seismic data
across a portion of the acreage. Recently, three horizontal wells offsetting
our acreage with initial potentials ranging from 1,000-3,000 MCFG/D were
drilled and completed. The Company plans to drill at least three horizontal
Barnett Shale wells on this block. The Company plans to utilize PPC's
Springtown gathering system to bring natural gas from these future wells to
market.

In southeastern Parker County, near the town of Cresson, the Company holds
approximately 325 acres by production. Last year, another company completed
two successful horizontal wells offsetting this acreage. Each of these wells
has produced in excess of 300,000 MCFG in the first year of production. The
Company plans to drill at least one horizontal Barnett Shale well on this
block.

In the northwest portion of Parker County southwest of the town of Peaster,
the Company holds approximately 2200 acres by production which was recently
offset by another company. The Company plans to drill at least one horizontal
Barnett Shale well on this block.

The Company also holds smaller acreage blocks throughout Parker County as well
as in Palo Pinto, Erath and Eastland Counties. The Barnett Shale is present
under these blocks, however, as of yet they have not been directly offset by
proven productive wells. The limits of economic Barnett Shale gas production
in the Fort Worth Basin are continually expanding and these blocks may be
proven productive in the future.

The Company intends to sell portions of the individual wells discussed above
to outside investors to help offset the cost and the risk of drilling and
completing the wells. The sale of these partial interests will reduce the
Company's ultimate portion of the recoverable reserves from these wells.

Proved Undeveloped Reserves were also attributed to 4 non-operated wells
drilled during the first quarter of 2005.  These coal bed methane wells in
the Powder River Basin of Wyoming were attributed with 179,664 MCFG net to
the Company's interest.

In the table shown below for Standardized measure of discounted future net
cash flows related to proved reserves, the Company has included $33,638,000
as future production revenue and $2,716,000 as estimated future development
and production costs related to the Newark Barnett Shale prospect.







                                   - 50 -
During 2003, the Company reduced its working interest in its Denton County
lease by acquiring investors to participate in the drilling of the additional
wells.  The Sales of Reserves in Place shown in the table below for 2003 is
due to the reduction of proved undeveloped reserves from the reduction of the
Company's interest in its lease in Denton County, Texas.

Revisions of Previous Estimates from 2002 of 4,048,147 Mcf as shown above is
due in part to only recognizing the drilling of its second well on the Denton
County lease, 2 additional wells in 2004 and 4 additional  wells in 2005, as
opposed to the recognition of 17 wells as shown in the 2002 reserve report.

As additional wells are proposed to be drilled within the near-term future,
the amount of proved undeveloped reserves will be added to the amount of
reserves reported in the table above.

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,
                                       --------------------------------------
                                           2004         2003         2002
                                       ------------ ------------ ------------

  Future production revenue            $ 87,568,000 $ 46,994,000 $ 56,535,000
  Future development costs               (8,300,000)  (2,470,000) (14,621,000)
  Future production costs               (22,668,000) (11,342,000) (13,688,000)
                                       ------------ ------------ ------------
  Future net cash flow before
    Federal income tax                   56,600,000   33,132,000   28,226,000
  Future income taxes                   (15,175,000)  (4,970,000)  (4,234,000)
                                       ------------ ------------ ------------
  Future net cash flows                  41,425,000   28,162,000   23,992,000
  Effect of 10% annual discounting      (24,534,000) (16,300,000)	(12,177,000)
                                       ------------ ------------ ------------
  Standardized measure of
    Discounted net cash flows          $ 16,891,000 $ 11,862,000 $  1,815,000
                                       ============ ============ ============









                                   - 51 -
Changes in the standardized measure of discounted future net cash flows:

                                               Year Ended December 31,
                                       --------------------------------------
                                           2004         2003         2002
                                       ------------ ------------ ------------

Beginning of the year                  $ 11,862,000 $ 11,815,000 $  3,729,000
  Oil and gas sales, net of
    production costs                     (2,644,000)  (1,970,000)    (943,000)
  Purchases of reserves in place                -      1,813,000    6,129,000
  Sales of reserves in place                    -     (2,532,000)         -
  Net change in prices, net of
    production costs                      7,809,000    5,384,000    2,665,000
  Changes in production rates,
    timing and other                     (3,101,000)    (360,000)  (2,083,000)
  Revisions of quantity estimate          7,662,000   (2,438,000)    (419,000)
  Effect of income tax                   (5,883,000)  (1,031,000)    (802,000)
  Accretion of discount                   1,186,000    1,181,000    3,539,000
                                       ------------ ------------ ------------
End of year                            $ 16,891,000 $ 11,862,000 $ 11,815,000
                                       ============ ============ ============


































                                   - 52

                 SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
                     VALUATION AND QUALIFYING ACCOUNTS
               YEARS ENDED DECEMBER 31, 2004, 2003, AND 2002

                                                                  SCHEDULE II

           Beginning                        Costs &                  Ending
          Description           Balance     Expenses   Deductions    Balance
----------------------------- ----------- ----------- ----------- -----------
Allowance for
  doubtful Accounts

    December 31, 2002             $   30,000 $      -   $      -   $   30,000
                                  ========== ========== ========== ==========

    December 31, 2003             $   30,000 $      -   $      -   $   30,000
                                  ========== ========== ========== ==========

    December 31, 2004             $   30,000 $      -   $      -   $   30,000
                                  ========== ========== ========== ==========



































                                   - 53 -

                                                                  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         -



 Gross Amounts at Which Carried at Close of Year
                                                   Life on which
                                      Accumulated   Depreciation      Date
    Land     Buildings      Total    Depreciation    Calculated     Acquired
---------- ------------ ----------- -------------   ------------   -----------
$  688,000 $ 1,298,000  $ 1,986,000  $      1,000        (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 fo investments in real estate and accumulated
depreciation for the years ended December 31, 2004 is as follows:
                                               Investments in    Accumulated
                                                 Real Estate    Depreciation
                                                ------------    ------------
Balance, January 1, 2002                        $        -      $        -
   Acquisitions                                          -               -
   Depreciation expense                                  -               -
                                                ------------    ------------
Balance, December 31, 2002                               -               -
   Acquisitions                                          -               -
   Depreciation expense                                  -               -
                                                ------------    ------------
Balance, December 31, 2003                               -               -
   Acquisitions                                    1,986,000
   Depreciation expense                                  -             1,000
                                                ------------    ------------
Balance, December 31, 2004                      $  1,986,000    $      1,000
                                                =============   ============



                                   - 54 -

                    SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES


Index to Exhibits



     Exhibit
   Designation                        Description

       3.1        Articles of Incorporation of Spindletop Oil & Gas Co.
                  (previously filed with our General Form for Registration of
                  Securities on Form 10, filed with the Commission on August
                  14, 1990)

       3.2        Bylaws of Spindletop Oil & Gas Co. (previously filed with
                  our General Form for Registration of Securities on Form 10,
                  filed with the Commission on August 14, 1990)

       14         Code of Ethics for Senior Financial Officers

       21         Subsidiaries of the Registrant

      31.1        Rule 13a-14(a) Certification of Chief Executive Officer

      31.2        Rule 13a-14(a) Certification of Chief Executive Officer

       32         Officers' Section 1350 Certifications



























                                   -55 -

                                                                     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.







































                                   - 56 -
                                                                     Exhibit 14

              Code of Ethics for Senior Financial Officers

The principal executive officer, president, principal financial officer,
chief financial officer, principal accounting officer and controller (all,
the company's "Senior Financial Officers") hold an important and elevated role
in corporate governance, vested with both the responsibility and authority to
protect, balance, and preserve the interests of all of the enterprise
stakeholders, including shareholders, customers, employees, suppliers, and
citizens of the communities in which business is conducted.  Senior Financial
Officers fulfill this responsibility by prescribing and enforcing the policies
and procedures employed in the operation of the enterprise's financial
organization and by acting in good faith and in the company's best interests
in accordance with the company's Code of Business Conduct and Ethics.

1.  Honest and Ethical Conduct

    Senior Financial Officers will exhibit and promote honest and
    ethical conduct through the establishment and operation of policies
    and procedures that:

      Encourage and reward professional integrity in all aspects of the
      financial organization, by eliminating inhibitions and barriers to
      responsible behavior, such as coercion, fear of reprisal, or
      alienation from the financial organization or the enterprise itself.

      Promote the ethical handling of actual or apparent conflicts of
      interest between personal and professional relationships.

      Provide a mechanism for members of the finance organization to
      inform senior Management of deviations in the practice from policies
      and procedures governing honest and ethical behavior.

      Respect the confidentiality of information acquired in the course of
      work, except when authorized or otherwise legally obligated to
      disclose such information, and restrict the use of confidential
      information acquired in the course of work for personal advantage.

      Demonstrate their personal support for such policies and procedures
      through periodic communication reinforcing these ethical standards
      throughout the finance organization.

2.  Financial Records and Periodic Reports

    Senior Financial Officers will establish and manage the enterprise
    transaction and reporting systems and procedures to provide that:

      Business transactions are properly authorized and accurately and timely
      recorded on the company's books and records in accordance with
      Generally Accepted Accounting Principles ("GAAP") and established
      company financial policy.




                                   - 57 -
      No false or artificial statements or entries for any purpose are made
      in the company's books and records, financial statements and related
      communications.

      The retention or proper disposal of company records shall be in
      accordance with established records retention policies and applicable
      legal and regulatory requirements.

      Periodic financial communications and reports will include full, fair,
      accurate, timely and understandable disclosure.


3.  Compliance with Applicable Laws, Rules and Regulations.

    Senior Financial Officers will establish and maintain mechanisms to:

      Educate members of the finance organization about any federal, state or
      local statute, regulation or administrative procedure that affects the
      operation of the finance organization and the enterprise generally.

      Monitor the compliance of the finance organization with any applicable
      federal, state or local statute, regulation or administrative rule.

      Identify, report and correct in a swift and certain manner, any detedted
      deviations from applicable federal, state or local statute or regulation

4.  Reporting of Non-Compliance

    Senior Financial Officers will promptly bring to the attention of the
    Board of Directors:

      Material information that affects the disclosures made by the company
      in its public filings.

      Information concerning significant deficiencies in the design or
      operation of internal controls that could adversely affect the company's
      ability to record, process, summarize and report financial data.

    Senior Financial Officers will promptly bring to the attention of the
    General Counsel and to the Board of Directors:

      Fraud, whether or not material, that involves management or other
      employees who have a significant role in the company's financial
      reporting, disclosures or internal controls.

      Information concerning a violation of this Code or the company's Code
      of Business and Ethics Conduct, including any actual or apparent
      conflicts of interest between personal and professional relationships,
      involving management or other employees who have a significant role in
      the company's financial reporting, disclosures or internal controls.

      Evidence of a material violation by the company or its employees or
      agents of applicable laws, rules or regulations.



                                   - 58 -
5.  Disciplinary Action

      In the event of violation by Senior Financial Officers of this Code or
      the company's Code of Business Conduct and Ethics, the Board of Directors
      shall recommend appropriate disciplinary and remedial actions.



















































                                   - 59 -
                                                                   Exhibit 31.1

                              CERTIFICATIONS


I, Chris G. Mazzini, certify that:

        1 .  I have reviewed this annual report on Form 10-K of Spindletop Oil
 & Gas Co.;

        2 .  Based on my knowledge, this annual 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
annual report;

        3 .  Based on my knowledge, the financial statements, and other
financial information included in this annual 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 annual 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 annual 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 principals; 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




                                   - 60 -
        5.  The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation of internal control over financial
reporting, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent
functions):

        (a)  all significant deficiencies and material weaknesses in the
             design or operation of internal control over financial reporting
             which are reasonably likely to adversely affect the registrant's
             ability to record, process, summarize and report financial
             information; and

        (b)  any fraud, whether or not material, that involves management or
             other employees who have a significant role in the registrant's
             internal controls.



Dated: April 15, 2005.



                                             /s/ Chris G. Mazzini
                                             --------------------
                                                 CHRIS G. MAZZINI
                                                 Chief Executive Officer






























                                   - 61 -

                                                                   Exhibit 31.2

                              CERTIFICATIONS


I, Robert E. Corbin certify that:

        1 .  I have reviewed this annual report on Form 10-K of Spindletop Oil
 & Gas Co.;

        2 .  Based on my knowledge, this annual 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
annual report;

        3 .  Based on my knowledge, the financial statements, and other
financial information included in this annual 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 annual 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 annual 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 principals; 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



                                   - 62 -
        5.  The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation of internal control over financial
reporting, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent
functions):

        (a)  all significant deficiencies and material weaknesses in the
             design or operation of internal control over financial reporting
             which are reasonably likely to adversely affect the registrant's
             ability to record, process, summarize and report financial
             information; and

        (b)  any fraud, whether or not material, that involves management or
             other employees who have a significant role in the registrant's
             internal controls.



Dated: April 15, 2005.



                                             /s/ Robert E. Corbin
                                             --------------------
                                                 ROBERT E. CORBIN
                                                 Principal Financial Officer






























                                   - 63 -

                                                                    Exhibit 32

                   Officers' Section 1350 Certifications

     The undersigned officer of Spindletop Oil & Gas Co., a Texas corporation
(the "Company"), hereby certifies that (i) the Company's Annual Report on Form
10-K for the year ended December 31, 2004 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, 2004 fairly presents, in all material respects, the
financial condition and results of operations of the Company, at and for the
periods indicated.




Dated: April 15, 2005.



                                       /s/ Chris G. Mazzini
                                       ---------------------------
                                           CHRIS G. MAZZINI
                                           Chief Executive Officer




                                       /s/ Robert E. Corbin
                                       ---------------------------
                                           ROBERT E. CORBIN
                                           Principal Financial and
                                           Accounting Officer





















                                   -64 -