Edgar Filing: SPINDLETOP OIL & GAS CO

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2018

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE

SECURITIES EXCHANGE ACT OF 1934

Commission File No. 000-18774

SPINDLETOP OIL & GAS CO.

(Exact name of registrant as specified in its charter)

Texas	75-2063001
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)

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

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

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

Title of each Class	Name of each exchange on which registered
None	N/A

Securities registered pursuant to Section 12(g) of the Act: Common Stock, $0.01 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [ ] No [ X ]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [ X ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding twelve months (or for such shorter period that the registrant was required to submit and post such files). Yes [ X ] No [ ]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Company was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [ X ] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§293.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of the Form 10-K or any amendment to this Form 10-K. [ X ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer [ ]	Accelerated filer [ ]

Non-accelerated filer [ ]	Smaller reporting company [ X ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act. Yes [ ] No [ X ]

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter.

$4,039,331 based upon a total of 1,035,726 shares held as of June 30, 2018 by persons believed to be non-affiliates of the Registrant; the basis of the calculation does not constitute a determination by the Registrant as defined in Rule 405 of the Securities Act of 1933, as amended, that such calculation, if made as of a date within 60 days of this filing, would yield a different value.

APPLICABLE ONLY TO REGISTRANTS INVOLVED IN BANKRUPTCY

PROCEEDINGS DURING THE PRECEDING FIVE YEARS:

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes [ ] No [ ]

(APPLICABLE ONLY TO CORPORATE REGISTRANTS)

Indicate the number of shares outstanding of each of the issuer's classes of common, as of the latest practicable date.

Common Stock, $0.01 par value	6,809,602
(Class)	(Outstanding at March 29, 2019)

DOCUMENTS INCORPORATED BY REFERENCE

None

PART I

Item 1. Description of Business

GENERAL

Spindletop Oil & Gas Co. is an independent oil and gas company engaged in the exploration, development, production and acquisition 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. (“Spindletop”, “SOG”) and its wholly owned subsidiaries, Spindletop Drilling Company ("SDC"), and Prairie Pipeline Co. (“PPC”).

The Company has focused its oil and gas operations principally in Texas, although we operate properties in six states including: Texas, Oklahoma, New Mexico, Louisiana, Alabama and Arkansas. We operate a majority of our projects through the drilling and production phases. Our staff has a great deal of experience in the operations arena. We have traditionally leveraged the risks associated with drilling by obtaining industry partners to share in the costs.

In addition, the Company, through PPC, owns several miles of pipelines associated with Company operated oil and natural gas properties in Texas and other states, which are used for the gathering of natural gas. These gathering lines are located primarily 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, most of it in the Fort Worth Basin.

One of our strengths has been the ability of the Company to look at cost effective ways to grow our production. We have traditionally increased our reserve base in one of two ways. Initially, in the 1970s and 1980s, the Company obtained its production through an exploration and development drilling program focused principally in the Fort Worth Basin of North Texas. Today, the Company has retained many of these wells as producing properties and holds a large amount of acreage by production in that Basin.

From the 1990s through 2003, the Company took advantage of the lower product prices by cost effectively adding to its reserve base through value-priced acquisitions. We found that through selective purchases we could make producing property acquisitions that were more cost effective than drilling.

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

From 2003 through the fourth quarter of 2008, we returned our focus to a strategy of development drilling with an emphasis on our Barnett Shale acreage. Since 2009, our focus has evolved to seek value-priced acquisitions combined with the development of economically feasible drilling prospects. Currently we are continuing our efforts to acquire producing properties and develop our leasehold acreage. We are pursuing controlled growth primarily through acquisitions of good quality producing properties. With current oil and natural gas prices and high costs to produce, we believe that it is prudent to carefully evaluate all our options and make sure that each transaction can be supported in today’s price environment.

Strategic Business Plans

One of our key strategies is to attempt to maintain shareholder value through implementation of plans for selective drilling and value priced acquisitions to the extent the economics of such projects work in this low energy price environment and development of assets. The Company's long-term focus is to grow its oil and natural gas production through a strategic combination of selected property acquisitions, divestitures, and a development program primarily based on developing its leasehold acreage. Additionally, the Company plans to continue to rework existing wells to increase production and reserves when feasible.

The Company's primary area of operation has been in the State of Texas with an emphasis in the geological province known as the Fort Worth Basin. We plan to continue to focus on operations in Texas, and we want to capitalize on our strengths which include an extensive knowledge of the various reservoirs in Texas, 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 its operations.

Project Significant Areas

The Company owns various interests in wells located in 14 states and the Company’s operations are currently located in 6 of those states which include Alabama, Arkansas, Louisiana, Oklahoma, New Mexico and Texas.

The Company holds approximately 86,402 gross acres under lease in 14 states. The majority of the leases are held by production. A breakout of the Company’s leasehold acreage by geographic area is as follows:

	Operated				Non-Operated								Percent
	Properties				Properties				Total				of Total
	Gross		Net		Gross		Net		Gross		Net		Gross			Net
Geographic Area	Acres		Acres		Acres		Acres		Acres		Acres		Acres			Acres
North Texas (1)		8,313		7,785		6,759		334		15,072		8,119		17.44	%		38.08	%
East Texas		3,591		3,105		9,011		1,050		12,602		4,155		14.59	%		19.49	%
Gulf Coast Texas		40		35		2,250		65		2,290		100		2.65	%		0.47	%
South Texas		—		—		540		52		540		52		0.62	%		0.24	%
West Texas		1,115		988		2,390		163		3,505		1,151		4.06	%		5.40	%
Texas Panhandle		1,760		1,195		1,520		104		3,280		1,299		3.80	%		6.09	%
Alabama		1,160		634		2,498		169		3,658		803		4.23	%		3.77	%
Arkansas		1,286		1,141		2,957		109		4,243		1,250		4.91	%		5.86	%
Louisiana		838		589		3,058		213		3,896		802		4.51	%		3.76	%
New Mexico		2,600		1,835		796		29		3,396		1,864		3.93	%		8.74	%
Oklahoma		317		185		26,711		594		27,028		779		31.28	%		3.65	%
Colorado		—		—		240		—		240		—		0.28	%		0.00	%
Kansas		—		—		640		184		640		184		0.74	%		0.86	%
Michigan		—		—		240		6		240		6		0.28	%		0.03	%
Mississippi		—		—		140		6		140		6		0.16	%		0.03	%
Montana		—		—		170		7		170		7		0.20	%		0.03	%
North Dakota		—		—		1,142		138		1,142		138		1.32	%		0.65	%
Utah		—		—		2,520		473		2,520		473		2.92	%		2.22	%
Wyoming		—		—		1,800		134		1,800		134		2.08	%		0.63	%

Total		21,020		17,492		65,382		3,830		86,402		21,322		100.00	%		100.00	%

(1) North Texas includes the Fort Worth Basin & Bend Arch

The majority of the Company’s net acres (69.77%) are located in Texas.

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

	BOE		% Total
North Texas including the Fort Worth Basin & Bend Arch		1,009,260		71.93	%
East Texas		200,767		14.31	%
Panhandle Texas		30,418		2.17	%
West Texas		18,940		1.35	%
Gulf Coast Texas		4,877		0.35	%
Total Texas		1,264,262		90.11	%

Alabama		56,013		3.99	%
Oklahoma		18,567		1.32	%
Kansas		1,543		0.11	%
New Mexico		25,802		1.84	%
Louisiana		36,630		2.61	%
Montana		241		0.02	%
Total Other States		138,796		9.89	%
Total		1,403,058		100.00	%

North Texas - Fort Worth Basin & Bend Arch

The Fort Worth Basin-Bend Arch Province has been a focal point of the Company since its inception. Our technical personnel have an average of over 25 years of exploration, drilling, completing, and production experience extracting natural gas and oil from both conventional and unconventional hydrocarbon deposits found across the basin. Furthermore, the Company maintains comprehensive and extensive dossiers of geologic and engineering data gathered from the province.

The Fort Worth Basin-Bend Arch Province is a major United States onshore natural gas-prone expanse containing multiple pay zones that range in depth from one thousand to nine thousand (1,000-9,000) feet. Improved technical advances in fracturing and stimulation technologies have helped unlock natural gas and oil reserves from the hydrocarbon bearing Barnett Shale Formation; and thus, continue to bolster vigorous exploration and development activities that target these conventional and unconventional reservoir reserves throughout the province.

The Barnett Shale is a thick natural gas and oil bearing stratigraphic zone found throughout the Fort Worth Basin-Bend Arch Province. The natural gas reserves in place are significant; however, as a consequence of the extreme low permeability character of the shales, it has been technically challenging to produce these reserves. According to the United States Geological Survey assessment, an estimated 26.7 trillion cubic feet (TCF) of undiscovered natural gas, 98.5 MMBO of undiscovered oil, as well as a mean of 1.1 BBNGL of undiscovered natural gas liquids reserves remain within the 54,000 square mile Fort Worth Basin-Bend Arch Province. More than 98 percent or approximately 26.2 TCF of the undiscovered natural gas is contained in the organic-rich Mississippian Barnett Shale. Combined, recent advances in hydraulic fracturing, completion procedures, and improvements in pump technology, as well as refined horizontal well drilling technologies, continue to enable the economic recovery of natural gas and oil reserves from tight low-permeability reservoirs found throughout the Fort Worth Basin-Bend Arch Province. Undiscovered conventional reservoir natural gas reserves are estimated to be 467 billion cubic feet of gas (BCFG), the majority of which is dissolved in conventional oil accumulations (source: United States Geological Survey Energy Resource Program).

The Company has 15,072 gross acres under lease across the prolific Fort Worth Basin-Bend Arch Province, the majority of which is held by production from the more shallow producing zones. The Company uses recent and emerging technologies, as well as proven industry practices, to develop and produce oil and natural gas from its properties. Additionally, the Company has a dedicated and well-trained team of employees and professional staff that continually seek out low-risk profitable drilling and acquisition opportunities throughout the Fort Worth Basin-Bend Arch Province.

West Texas

Effective January 1, 2018, the Company acquired an additional 50% working interest with a 39.5% net revenue interest in its Miller #1 well located in Jones County, Texas. This additional acquisition brought the Company’s interest in the well to a total 100% working interest with a 79% net revenue interest.

During 2018, the Company sold its 18.75% non-operated working interest in 51.78 net leasehold acres located in Martin County, Texas.

North Texas

During 2018, but effective December 31, 2017, the Company acquired a working interest of 2.29% with a net revenue interest of 1.71% in the Company’s Lebleu #1 well located in Comanche County, Texas. This acquisition brought the Company’s interest in the well to a total working interest of 65.35% with a net revenue interest of 52.55%.

Effective June 1, 2018, the Company acquired additional working interests totaling 3.0% with net revenue interests of 2.25% in the Company’s Olex wells located in Denton County, Texas. This acquisition brought the Company’s interests in the wells to total working interests of 56.33% to 59.50% with net revenue interests of 42.25% to 44.625%.

East Texas

Effective April 1, 2018, the Company acquired a working interest of 13.51% with a net revenue interest of 10.72% in the Company’s Watts Gas Unit #1 well located in Marion County, Texas. This acquisition brought the Company’s interest in the well to a total working interest of 65.35% with a net revenue interest of 52.55%.

Subsequent to year end, effective February 1, 2019, the Company acquired additional working interest of 11.67% with a net revenue interest of 9.51% in the Company’s Watts Gas Unit #1 well located in Marion County, Texas. This acquisition brought the Company’s interest in the well to a total working interest of 77.02% with a net revenue interest of 62.06%.

Oklahoma

Effective March 1, 2018, the Company acquired an additional 0.13% working interest with a 0.09% net revenue interest in its Sharp 18-1 well located in Oklahoma County, Oklahoma. This additional acquisition brought the Company’s interest in the well to a total 89.25% working interest with a 66.94% net revenue interest.

Effective June 1, 2018, the Company sold its 18.75% non-operated working interest in an 80 acre tract of land located in Grady County, Oklahoma.

Effective November, 2018, the Company participated for a 1.36777% non-operated working interest with a 1.094216% net revenue interest in the drilling of the Taylor Trust 14/23 #1HXL well located in Grady County, Oklahoma. The well was spud on November 6, 2018, drilled, and the wellbore was landed in the Lower Hoxbar (Marchand C) formation. Production casing was set to total depth on December 24, 2018. The well was perforated from 11,232 ft. to 18,848 ft. and the perforated interval was fractured in 19 stages. The well was placed into production on February 3, 2019 and is currently producing at an approximate rate of 90 bopd, 65 mcfgpd, and 135 bswpd.

Alabama

During 2018, but effective July 1, 2017, the Company acquired an additional 0.08% working interest with a 0.07% net revenue interest in its Fairview Carter North Oil Unit located in Lamar County, Alabama. This additional acquisition brought the Company’s interest in the Unit to a total 52.81% working interest with a 39.62% net revenue interest.

Oil and Natural Gas Reserves

The Company’s net proved oil and natural gas reserves have been estimated by Company personnel. (See footnote 17 to the financial statements). No separate independent reserve report analysis has been prepared by an independent third party.

The net proved crude oil and natural gas reserves of the Company as of December 31, 2018 were 261,500 barrels of oil and condensate and 6.849 BCF of natural gas. Based on SEC guidelines, the reserves were classified as follows:

	Barrels of Oil		BCF Gas
Proved Developed Producing		261,500		6.849
Proved Developed Non-Producing		—		—
Proved Undeveloped		—		—
Total Proved Reserves		261,500		6.849

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 underlying the Company's properties. Shut-in uneconomic wells and insignificant non-operated interests were excluded.

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

	Barrels of Oil Equivalent (BOE)

Natural Gas Reserves		1,141,558	81	%
Oil Reserves		261,500	19	%
Total Reserves		1,403,058	100	%

Proved Developed Producing		1,403,058	100	%
Proved Developed Non-Producing		—	0	%
Proved Undeveloped		—	0	%
Total Proved Reserves		1,403,058	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.

	Barrels of Oil Equivalent (BOE)

Operated Wells		1,118,742	80	%
Non-Operated Wells		284,316	20	%
Total		1,403,058	100	%

Financial Information Relating to Industry Segments

The Company has three identifiable business segments: (1) exploration, acquisition, development and production of oil and natural gas, (2) natural gas gathering, and (3) commercial real estate investment. Footnote 14 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, acquisition 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 leasing office space to non-related third party tenants in the Company’s 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 natural gas properties which are acquired and sold to oil and natural gas development entities. Reserves of oil and natural 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 several miles of pipelines in various states. Natural gas is gathered for a fee. Substantially all of the natural gas gathered by the Company is produced from wells that the Company operates and in which it owns a working interest.

The Company owns land and a two story commercial office building in Dallas, Texas, which it uses as its principal headquarters office. The Company leases the remainder of the building to non-related third party commercial tenants at prevailing market rates.

Patents, Licenses and Franchises

Oil and natural gas leases of the Company are obtained from the owner of the mineral estate. The leases are generally for a primary term of one or more years, and often have extension options for an equivalent period as the original primary term for payment of additional bonus consideration. The leases customarily provide for extension beyond their primary term for as long as oil and natural gas are produced in commercial quantities or other operations are conducted on such leases as provided by the terms of the leases.

The Company currently holds interests in producing and non-producing oil and natural gas leases. The existence of the oil and natural gas leases and the terms of the oil and natural gas leases are important to the business of the Company because future additions to reserves will come from oil and natural 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 natural gas leases in areas where it currently has production, and also in other areas.

Dependence on Customers

The following is a summary of a partial list of purchasers / operators (listed by percent of total oil and natural gas sales) from oil and natural gas produced by the Company for the three-year period ended December 31, 2018.


Purchaser / Operator	2018			2017			2016
Sunoco Partners Marketing		18	%		18	%		12	%
Enlink Gas Marketing, LTD.		10	%		13	%		9	%
Enervest Operating, LLC		10	%		3	%		2	%
Targa Midstream Services, LLC		9	%		13	%		14	%
ETX Energy, LLC formerly New Gulf Resources		5	%		7	%		13	%
DCP Midstream, LP		4	%		3	%		3	%
Barnett Gathering, LP		4	%		1	%		0	%
ACE Gathering, Inc.		4	%		2	%		0	%
Shell Trading (US) Company		4	%		4	%		4	%
ETC Texas Pipeline, Ltd		4	%		2	%		1	%
Eastex Crude Company		3	%		7	%		10	%
Midcoast Energy Partners LP		3	%		4	%		4	%
Pruet Production Co.		3	%		3	%		3	%
Land and Natural Resources Development		2	%		0	%		0	%
Devon OEI Operating, Inc.		2	%		0	%		0	%
LPC Crude Oil Marketing LLC		2	%		3	%		3	%
Phillips 66		1	%		1	%		1	%
OXY USA, Inc.		1	%		2	%		4	%
Valero Energy Corporation		1	%		3	%		2	%
FDL Operating LLC		1	%		0	%		0	%
Enterprise Crude Oil, LLC		1	%		0	%		1	%
XTO Energy, Inc.		1	%		1	%		1	%
Empire Pipeline Corp.		1	%		1	%		1	%
Sandridge Energy, Inc.		1	%		1	%		1	%
Lucid Energy Group II (Formerly Agave Energy Co.)		1	%		2	%		0	%
Webb Energy Resources, Inc.		1	%		1	%		1	%
Range Resources Corporation		1	%		1	%		1	%
Courson Oil & Gas, Inc.		0	%		1	%		1	%
Corum Production Company		0	%		0	%		1	%
Ward Petroleum Corporation		0	%		1	%		1	%
Agave Energy Company		0	%		0	%		2	%
Linear Energy Management LLC		0	%		0	%		1	%

Oil and natural gas is sold to approximately 109 different purchasers under market sensitive, short-term contracts computed on a month to month basis.

Except as set forth above, there are no other customers of the Company that individually accounted for more than one percent (1%) of the Company's oil and natural gas revenues during the three years ended

December 31, 2018.

The Company currently has no hedged contracts.

Prospective Drilling Activities

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

The Company intends to use a portion of its available funds to participate in drilling activities. The Company does not own any drilling rigs. Independent drilling contractors perform all drilling activity. The Company does not refine or otherwise process its oil and natural gas production.

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

A prospect is a geographical area designated by the Company for the purpose of searching for oil and natural gas reserves and reasonably expected by it to contain at least one oil, or natural gas reservoir. The Company utilizes its own funds along with the issuance of common stock and options to purchase common stock in some limited cases, to acquire oil and gas leases covering the lands comprising the prospects. These leases are selected by the Company and are obtained directly from the landowners, as well as from land men, geologists, other oil companies, some of whom may be affiliated with the Company, and by direct purchase, farm-in, or option agreements. After an initial test well is drilled on a property, any subsequent development drilling of such prospect will normally require the Company to fund the development activities.

Employees

As of December 31, 2018, the Company employed or contracted for the services of a total of approximately 56 people. Of this total, 20 are full-time employees, and the remainder are part-time employees or independent contractors. We believe that our relationships with our employees are good.

In order to effectively utilize our resources, we employ the services of independent consultants and contractors to perform a variety of professional, technical, and field services, including in the areas of lease acquisition, land related documentation and contracts, drilling and completion work, pumping, inspection, testing, maintenance and specialized services. We believe that it can be more cost effective to utilize the services of consultants and independent contractors for some of these services.

We depend to a large extent on the services of certain key management personnel and officers, and the loss of any these individuals could have a material adverse effect on our operations. The Company does not maintain key-man life insurance policies on its employees.

Financial information about foreign and domestic operations and export sales

All of the Company's business is conducted domestically, with no export sales.

Compliance with Environmental Regulations

Our oil and natural gas operations are subject to numerous United States federal, state, and local laws and regulations relating to the protection of the environment, including those governing the discharge of materials into the water and air, the generation, management and disposal of hazardous substances and wastes, and clean-up of contaminated sites. We could incur material costs, including clean-up costs, fines, civil and criminal sanctions, and third party claims for property damage and personal injury as a result of violations of, or liabilities under, environmental laws and regulations. Such laws and regulations not only expose us to liability for our own activities, but may also expose us to liability for the conduct of others or for actions by us that were in compliance with all applicable laws at the time those actions were taken. In addition, we could incur substantial expenditures complying with environmental laws and regulations, including future environmental laws and regulations which may be more stringent.

Glossary of Oil and Gas Terms

The following are abbreviations and definitions of terms commonly used in the oil and gas industry that are used in this Report. The terms defined herein may be found in this report in both upper and lower case or a combination of both.

"BBL" means a barrel of 42 U.S. gallons.

“BBNGL” means billion barrels of natural gas liquids.

“BCF” or “BCFG” means billion cubic feet.

"BOE" means barrels of oil equivalent; converting volumes of natural gas to oil equivalent volumes using a ratio of six Mcf of natural gas to one Bbl of oil.

“BOPD” means barrels of oil per day.

"BTU" means British Thermal Units. British Thermal Unit means the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

“BSWPD” means barrels of salt water per day.

"Completion" means the installation of permanent equipment for the production of oil or natural gas.

"Development Well" means a well drilled within the proved area of an oil or natural gas reservoir to the depth of a strata graphic horizon known to be productive.

"Dry Hole" or "Dry Well" means a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

"Exploratory Well" means a well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new production reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

"Farm-Out" means an agreement pursuant to which the owner of a working interest in an oil and natural gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farm-in" and the assignor issues a "farm-out."

"Farm-In" see "Farm-Out" above.

"Gas" means natural gas.

"Gross" when used with respect to acres or wells, refers to the total acres or wells in which we have a working interest.

"Infill Drilling" means drilling of an additional well or wells provided for by an existing spacing order to more adequately drain a reservoir.

"MCF" or “MCFG” means thousand cubic feet.

“MCFGPD” means thousand cubic feet of natural gas per day.

"MCFE" means MCF of natural gas equivalent; converting volumes of oil to natural gas equivalent volumes using a ratio of one BBL of oil to six MCF of natural gas.

“MD” means measured depth.

“MMBO” means million barrels of oil.

"MMBTU" means one million BTUs.

"Net" when used with respect to acres or wells, refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by the Company.

"Net Production" means production that is owned by the Company less royalties and production due others.

"Non-Operated" or "Outside Operated" means wells that are operated by a third party.

“Oil and Gas” means oil and natural gas.

"Operator" means the individual or company responsible for the exploration, development, production and management of an oil or gas well or lease.

“Overriding Royalty” means a royalty interest which is usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

"Present Value" ("PV") when used with respect to oil and natural gas reserves, means the estimated future gross revenues to be generated from the production of proved reserves calculated in accordance with the guidelines of the SEC, net of estimated production and future development costs as of the date of estimation without future escalation, and discounted using an annual discount rate of 10%. Prices are not escalated and are computed using a 12-month average price, calculated as the un-weighted arithmetic average of the first-day-of-the month price for each month of the year (except to the extent a contract specifically provides otherwise). No effect is given to non-property related expenses such as general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization.

"Productive Wells" or "Producing Wells" consist of producing wells and wells capable of production, including wells waiting on pipeline connections.

"Proved Developed Reserves" means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery will be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

"Proved Reserves" means the estimated quantities of crude oil and natural gas which upon analysis of geological and engineering data appear with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if either actual production or conclusive formation

tests support economic producability. The area of a reservoir considered proved

includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water

contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which

can be reasonably judged as economically productive on the basis of available geological

and engineering data. In the absence of information on fluid contacts, the lowest known

structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved recovery

techniques (such as fluid injection) are included in the "proved" classification when successful

testing by a pilot project, or the operation of an installed program in the reservoir, provides

support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following: (A) oil that may become

available from known reservoirs but is classified separately as "indicated additional reserves";

(B) crude oil and natural gas, the recovery of which is subject to reasonable doubt because of

uncertainty as to geology, reservoir characteristics or economic factors; (C) crude oil and

natural gas that may occur in undrilled prospects; and (D) crude oil and natural gas that may

be recovered from oil shales, coal, gilsonite and other such resources.

"Proved Undeveloped Reserves" means reserves that are recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

"Recompletion" means the completion for production of an existing well bore in another formation from that in which the well has been previously completed.

"Reserves" means proved reserves.

"Reservoir" means a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

"Royalty" means an interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

“TCF” means trillion cubic feet.

“TD” means total depth.

“TVD” means true vertical depth,

"2-D Seismic" means an advanced technology method by which a cross-section of the earth's subsurface is created through the interpretation of reflecting seismic data collected along a single source profile.

"3-D Seismic" means an advanced technology method by which a three dimensional image of the earth's subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, development and production.

"Working Interest" means an interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties.

"Workover" means operations on a producing well to restore or increase production.

Item 1A. Risk Factors

Risks related directly to our Company

One should carefully consider the following risk factors, in addition to the other information set forth in this Report, before investing in shares of our common stock. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock. Some information in this Report may contain "forward-looking" statements that discuss future expectations of our financial condition and results of operation. The risk factors noted in this section and other factors could cause our actual results to differ materially from those contained in any forward-looking statements.

We are exposed to global economic and market risks that are beyond our control, which could adversely affect our financial results and capital requirements.

Uncertainties regarding the global economic and financial environment could lead to an extended national or global economic recession. A slowdown in economic activity caused by a recession would likely reduce national and worldwide demand for oil and natural gas and result in lower commodity prices for long periods of time. Costs of exploration, development and production have not yet adjusted to current economic conditions, or in proportion to the significant reduction in product prices.

In the past several years, capital and credit markets have experienced volatility and disruption. Given the levels of market volatility and disruption, the availability of funds from those markets may diminish substantially. Further, arising from concerns about the stability of financial markets generally and the solvency of borrowers specifically, the cost of accessing the credit markets has increased as many lenders have raised interest rates, enacted tighter lending standards, or altogether ceased to provide funding to borrowers.

Due to these potential capital and credit market conditions, the Company cannot be certain that funding will be available in amounts or on terms acceptable to the Company. The Company is evaluating whether current cash balances and cash flow from operations alone would be sufficient to provide working capital to fully fund the Company's operations. Accordingly, the Company is evaluating alternatives, such as joint ventures with third parties, or sales of interests in one or more of its properties. Such transactions, if undertaken, could result in a reduction in the Company's operating interests or require the Company to relinquish the right to operate the property. There can be no assurance that any such transactions can be completed or that such transactions will satisfy the Company's operating capital requirements. If the Company is not successful in obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable to the Company, the Company would be required to curtail its expenditures or restructure its operations, and the Company would be unable to continue its exploration, drilling, and recompletion program, any of which would have a material adverse effect on its business, financial condition, and results of operations.

We face significant competition, and many of our competitors have resources in excess of our available resources.

The oil and natural gas industry is highly competitive. We encounter competition from other oil and gas companies in all areas of our operations, including the acquisition of producing properties and sale of crude oil and natural gas. Our competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than us. Such companies may be able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

Exploratory drilling is a speculative activity that may not result in commercially productive reserves and may require expenditures in excess of budgeted amounts.

Drilling activities are subject to many risks, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. There can be no assurance that new wells drilled by us will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, many of which are beyond our control, including economic conditions, mechanical problems, pressure or irregularities in formations, title problems, weather conditions, compliance with governmental requirements, and shortages in or delays in the delivery of equipment and services. In today's environment, shortages make drilling rigs, labor and services difficult to obtain and could cause delays or inability to proceed with our drilling and development plans. Such equipment shortages and delays sometimes involve drilling rigs where inclement weather prohibits the movement of land rigs causing a high demand for rigs by a large number of companies during a relatively short period of time. Our future drilling activities may not be successful. Lack of drilling success could have a material adverse effect on our financial condition and results of operations.

Our operations are also subject to all the hazards and risks normally incident to the development, exploitation, production and transportation of, and the exploration for, oil and natural gas, including unusual or unexpected geologic formations, pressures, down hole fires, mechanical failures, blowouts, explosions, uncontrollable flows of oil, natural gas or well fluids and pollution and other environmental risks. These hazards could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. We participate in insurance coverage maintained by the operator of its wells, although there can be no assurances that such coverage will be sufficient to prevent a material adverse effect to us in such events.

The vast majority of our oil and natural gas reserves are classified as proved reserves. Recovery of the Company's future proved undeveloped reserves will require significant capital expenditures. Our management estimates that additional capital expenditures will be required to fully develop some of these reserves in the next twelve month period. No assurance can be given that our estimates of capital expenditures will prove accurate, that our financing sources will be sufficient to fully fund our planned development activities or that development activities will be either successful or in accordance with our schedule. Additionally, any significant decrease in oil and natural gas prices or any significant increase in the cost of development could result in a significant reduction in the number of wells drilled and/or reworked. No assurance can be given that any wells will produce oil or natural gas in commercially profitable quantities.

We are subject to uncertainties in reserve estimates and future net cash flows.

This annual report contains estimates of our oil and natural gas reserves and the future net cash flows from those reserves. These estimates have been prepared by Company personnel for 2018, 2017 and 2016. There are numerous uncertainties inherent in estimating quantities of reserves of oil and natural gas and in projecting future rates of production and the timing of development expenditures, including many factors beyond our control. The reserve estimates in this annual report are based on various assumptions, including decline curve analysis, constant oil and natural gas prices, operating expenses, capital expenditures and the availability of funds, and therefore, are inherently imprecise indications of future net cash flows. Actual future production, cash flows, taxes, operating expenses, development expenditures and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves set forth in this annual report. Additionally, our reserves may be subject to downward or upward revision based upon actual production performance, results of future development and exploration, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

The present value of future net reserves discounted at 10% (the "PV-10") of proved reserves referred to in this annual report should not be construed as the current market value of the estimated proved reserves of oil and gas attributable to our properties. In accordance with applicable requirements of the SEC, the estimated discounted future net cash flows from proved reserves are generally based on prices using a 12-month average price, calculated as the un-weighted arithmetic average of the first-day-of-the month price for each month of each year, and costs as of the date of the estimate, whereas actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by: (i) the timing of both production and related expenses; (ii) changes in consumption levels; and (iii) governmental regulations or taxation. In addition, the calculation of the present value of the future net cash flows using a 10% discount as required by the SEC is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the oil and gas industry in general. Furthermore, our reserves may be subject to downward or upward revision based upon actual production, results of future development, supply and demand for oil and natural gas, prevailing oil and natural gas prices and other factors. See "Properties - Oil and Gas Reserves."

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flows and income.

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and, therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may be unable to make such acquisitions because we are:

unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

unable to obtain financing for these acquisitions on economically acceptable terms; or

outbid by competitors.

If we are unable to develop, exploit, find or acquire additional reserves to replace our current and future production, our cash flow and income will decline as production declines, until our existing properties would be incapable of sustaining commercial production.

There are risks in acquiring producing oil and natural gas properties, including difficulties in integrating acquired properties into our business, additional liabilities and expenses associated with acquired properties, diversion of management attention, increasing the scope, geographic diversity and complexity of our operations.

One of our business strategies includes growing our reserve base through acquisitions of oil and natural gas properties. Our failure to integrate acquired properties successfully into our existing business, or the expense incurred in consummating future acquisitions, could result in unanticipated expenses and losses. In addition, we may assume environmental cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.

We are continually investigating opportunities for acquisitions. In connection with future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations. Our ability to make future acquisitions may be constrained by our ability to obtain additional financing.

Possible future acquisitions could result in our incurring debt, contingent liabilities and expense, all of which could have a material effect on our financial condition and operating results.

Acquisitions may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.

Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, recovery applicability from water flood and Enhanced Oil Recovery techniques (“EOR”), future oil and natural gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well or property. Even when we inspect a well or property, we do not always discover structural, subsurface and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties. It is our current intention to continue focusing on acquiring properties with development and exploration potential located in onshore United States. To the extent that we acquire properties substantially different from the properties in our primary operating regions or acquire properties that require different technical expertise, we may not be able to realize the economic benefits of these acquisitions as efficiently as in our prior acquisitions.

We cannot control activities on properties we do not operate. Failure to fund capital expenditure requirements may result in reduction or forfeiture of our interests in some of our non-operated projects.

We do not operate some of the properties in which we have an interest and we have limited ability to exercise influence over operations for these properties or their associated costs. As of December 31, 2018, approximately 20% of our crude oil and natural gas proved reserves were operated by other companies. Our dependence on other operators and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of our targeted return on capital in drilling or acquisition activities and our targeted production growth rate. The success and timing of drilling, development and exploitation activities on properties operated by others depend on a number of factors that are beyond our control, including the operator’s expertise and financial resources, approval of other participants for drilling wells and utilization of technology.

When we are not the majority owner or operator of a particular crude oil or natural gas project, we may have no control over the timing or amount of capital expenditures associated with such project. If we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.

We are subject to risks associated with the current United States Government Administration’s possible budget features.

Future legislation may set forth budget proposals which if passed, would significantly curtail our ability to attract investors and raise capital. Future possible changes in the Federal income tax laws which would eliminate or reduce the percentage depletion deduction and the deduction for intangible drilling and development costs for small independent producers will likely significantly reduce the investment capital available to those in the industry as well as our Company. Lengthening the time to expense seismic costs would likely also have an adverse effect on our ability to explore and find new reserves.

We are subject to various operating and other casualty risks that could result in liability exposure or the loss of production and revenues.

Our oil and gas business involves a variety of operating risks, including, but not limited to, unexpected formations or pressures, uncontrollable flows of oil, natural gas, brine or well fluids into the environment (including groundwater contamination), blowouts, fires, explosions, pollution and other risks, any of which could result in personal injuries, loss of life, damage to properties and substantial losses. Although we carry insurance at levels that we believe are reasonable, we are not fully insured against all risks. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or under-insured events could have a material adverse effect on our financial condition and operations.

From time to time, due primarily to contract terms, pipeline interruptions or weather conditions, the producing wells in which we own an interest have been subject to production curtailments. The curtailments range from production being partially restricted to wells being completely shut-in. The duration of curtailments varies from a few days to several months. In most cases, we are provided only limited notice as to when production will be curtailed and the duration of such curtailments. We are not currently experiencing any material curtailment of our production.

We intend to increase to some extent our development and, to a lesser extent, exploration activities. Exploration drilling and, to a lesser extent, development drilling of oil and gas reserves involve a high degree of risk that no commercial production will be obtained and/or that production will be insufficient to recover drilling and completion costs. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment. Furthermore, completion of a well does not assure a profit on the investment or a recovery of drilling, completion and operating costs.

We depend on our key management personnel and technical experts and the loss of any of these individuals could adversely affect our business.

If we lose the services of our key management personnel, technical experts or are unable to attract additional qualified personnel, our business, financial condition, results of operations, development efforts and ability to grow could suffer. We have assembled a team of engineers and geologists who have considerable experience in applying advanced drilling and completion techniques to explore for and to develop crude oil and natural gas. We depend upon the knowledge, skill and experience of these experts to assist us in improving the performance and reducing the risks associated with our participation in crude oil and natural gas exploration and development projects. In addition, the success of our business depends, to a significant extent, upon the abilities and continued efforts of our management, particularly Chris Mazzini, our Chief Executive Officer, President and Chairman of the Board. We do not have an employment agreement with or key-man life insurance on Mr. Mazzini or any of our other employees.

The inability to continue to hire, train and retain operational, technical and managerial personnel could adversely affect our results of operations.

The average age of the employee base of the Company has been increasing for a number of years, with a number of employees becoming eligible to retire within the next five to ten years. If we were unable to hire appropriate personnel to fill future needs, the Company could encounter operating challenges and increased costs, primarily due to a loss of knowledge, errors due to inexperience or the lengthy time period typically required to adequately train replacement personnel. In addition, higher costs could result from the increased use of contractors to replace retiring employees, loss of productivity or increased safety compliance issues. The inability to hire, train and retain new operational, technical and managerial personnel adequately and to transfer institutional knowledge and expertise could adversely affect our ability to manage and operate our business. If we were unable to hire, train and retain appropriately qualified personnel, our results of operations could be adversely affected.

The costs of providing health care benefits to our employees may increase substantially.

We provide health care benefits to eligible full-time employees. The costs of providing health care benefits to our employees could significantly increase over time due to rapidly increasing health care inflation, and any future legislative changes related to the provision of health care benefits. The impact of additional costs which are likely to be passed on to the Company are difficult to measure at this time. Further, our costs of providing such benefits are also subject to a number of factors, including (i) changing demographics; and (ii) future government regulation.

Certain of our affiliates control a majority of our outstanding common stock, which may affect your vote as a shareholder.

Our executive officers, directors and their affiliates as of December 31, 2018 hold approximately 86.65% of our outstanding shares of common stock. As a result, officers, directors and their affiliates and such shareholders have the ability to exert significant influence over our business affairs, including the ability to control the election of directors and results of voting on all matters requiring shareholder approval. This concentration of voting power may delay or prevent a potential change in control.

Certain of our affiliates have engaged in business transactions with the Company, which may result in conflicts of interest.

Certain officers, directors and related parties, including entities controlled by Mr. Mazzini, the President and Chief Executive Officer, have engaged in business transactions with the Company which were not the result of arm's length negotiations between independent parties. Our management believes that the terms of these transactions were as favorable to us as those that could have been obtained from unaffiliated parties under similar circumstances. All future transactions between us and our affiliates will be on terms no less favorable than could be obtained from unaffiliated third parties and will be approved by a majority of the disinterested members of our Board of Directors.

Our common stock is traded on the Over-the-Counter market and is currently quoted on the OTC Market (Other), symbol "SPND".

The liquidity of our common stock may be adversely affected, and purchasers of our common stock may have difficulty selling our common stock, if our common stock does not continue to trade in that or another suitable trading market.

There is presently only a limited public market for our common stock, and there is no assurance that a ready public market for our securities will develop. It is likely that any market that develops for our common stock will be highly volatile and that the trading volume in such market will be limited. The trading price of our common stock could be subject to wide fluctuations in response to quarter-to-quarter variations in our operating results, announcements of our drilling results and other events or factors. In addition, the United States stock market has from time to time experienced extreme price and volume fluctuations that have affected the market price for many companies and which often have been unrelated to the operating performance of these companies. These broad market fluctuations may adversely affect the market price of our securities.

We do not intend to declare dividends in the foreseeable future.

Our Board of Directors presently intends to retain all of our earnings for the expansion of our business. We therefore do not anticipate the distribution of cash dividends in the foreseeable future. Any future decision of our Board of Directors to pay cash dividends will depend, among other factors, upon our earnings, financial position and cash requirements.

We are subject to certain title risks.

Our company employees and contract land professionals have reviewed title records or other title review materials relating to substantially all of our producing properties. The title investigation performed by us prior to acquiring undeveloped properties is thorough, but less rigorous than that conducted prior to drilling, consistent with industry standards. We believe we have satisfactory title to all our producing properties in accordance with standards generally accepted in the oil and gas industry. Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect the value of such properties. At December 31, 2018, our leaseholds for some of our net acreage were being kept in force by virtue of production on that acreage in paying quantities. The remaining net acreage was held by lease rentals and similar provisions and requires production in paying quantities prior to expiration of various time periods to avoid lease termination.

We expect to make acquisitions of oil and gas properties from time to time subject to available resources. In making an acquisition, we generally focus most of our title and valuation efforts on the more significant properties. It is generally not feasible for us to review in-depth every property we purchase and all records with respect to such properties. However, even an in-depth review of properties and records may not necessarily reveal existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their deficiencies and capabilities. Evaluation of future recoverable reserves of oil and gas, which is an integral part of the property selection process, is a process that depends upon evaluation of existing geological, engineering and production data, some or all of which may prove to be unreliable or not indicative of future performance. To the extent the seller does not operate the properties, obtaining access to properties and records may be more difficult. Even when problems are identified, the seller may not be willing or financially able to give contractual protection against such problems, and we may decide to assume environmental and other liabilities in connection with acquired properties.

Our business is highly capital-intensive, requiring continuous development and acquisition of oil and gas reserves. In addition, capital is required to operate and expand our oil and natural gas field operations and purchase equipment. At December 31, 2018, we had working capital of $11,392,000. We anticipate that we will be able to meet our cash requirements for the next 12 months. However, if such plans or assumptions change or prove to be inaccurate, we could be required to seek additional financing sooner than currently anticipated.

We have funded our operations, acquisitions and expansion costs primarily through our internally generated cash flow. Our success in obtaining the necessary capital resources to fund future costs associated with our operations and expansion plans is dependent upon our ability to: (i) increase revenues through acquisitions and recovery of our proved producing and proved developed non-producing oil and gas reserves; and (ii) maintain effective cost controls at the corporate administrative office and in field operations. However, even if we achieve some success with our plans, there can be no assurance that we will be able to generate sufficient revenues to achieve significant profitable operations or fund our expansion plans.

We have substantial capital requirements necessary for undeveloped properties for which we may not be able to obtain adequate financing.

Development of our properties will require additional capital resources. We have no commitments to obtain any additional debt or equity financing and there can be no assurance that additional financing will be available, when required, on favorable terms to us. The inability to obtain additional financing could have a material adverse effect on us, including requiring us to curtail significantly our oil and gas acquisition and development plans or farm-out development of our properties. Any additional financing may involve substantial dilution to the interests of our shareholders at that time.

Oil and natural gas prices fluctuate widely and low prices could have a material adverse impact on our business and financial results.

Our revenues, profitability and the carrying value of our oil and gas properties are substantially dependent upon prevailing prices of, and demand for, oil and natural gas and the costs of acquiring, finding, developing and producing reserves. Our ability to obtain borrowing capacity, to repay future indebtedness, and to obtain additional capital on favorable terms is also substantially dependent upon oil and natural gas prices. Historically, the markets for oil and natural gas have been volatile and are likely to continue to be volatile in the future. Prices for oil and natural gas are subject to wide fluctuations in response to: (i) relatively minor changes in the supply of, and demand for, oil and natural gas; (ii) market uncertainty; and (iii) a variety of additional factors, all of which are beyond our control. These factors include domestic and foreign political conditions, the price and availability of domestic and imported oil and natural gas, the level of consumer and industrial demand, weather, domestic and foreign government relations, the price and availability of alternative fuels and overall economic conditions. Furthermore, the marketability of our production depends in part upon the availability, proximity and capacity of gathering systems, pipelines and processing facilities. Volatility in oil and natural gas prices could affect our ability to market our production through such systems, pipelines or facilities. As of December 31, 2018, approximately 87% of our oil and natural gas production is currently sold to 16 purchasing firms on a month-to-month basis at prevailing spot market prices. Oil prices remained subject to unpredictable political and economic forces during 2018, 2017, and 2016, and experienced fluctuations similar to those seen in natural gas prices for the year. We believe that oil prices will continue to fluctuate in response to changes in the policies of the Organization of Petroleum Exporting Countries ("OPEC"), changes in demand from many Asian countries, current events in the Middle East and Eastern Europe, security threats to the United States, and other factors associated with the world political and economic environment. As a result of the many uncertainties associated with levels of production maintained by OPEC and other oil producing countries, the availabilities of worldwide energy supplies and competitive relationships and consumer perceptions of various energy sources, we are unable to predict what changes will occur in crude oil and natural gas prices.

Gathering and transporting natural gas involve risks that may result in accidents and additional operating costs.

Our natural gas pipeline business involves a number of hazards and operating risks that cannot be completely avoided, such as leaks, accidents and operational problems, which could cause loss of human life, as well as substantial financial losses resulting from property damage, damage to the environment and to our operations. We maintain liability and property insurance coverage in place for many of these hazards and risks. However, because some of our pipelines are near or are in populated areas, any loss of human life or adverse financial results resulting from such events could be large. If these events were not fully covered by our general liability and property insurance, which policies are subject to certain limits and deductibles, our operations or financial results could be adversely affected. Our pipelines are aging, and we will be responsible for eventually replacing these lines. The costs of maintaining and replacing our aging pipeline infrastructure may have a material adverse impact on our operating costs and financial results.

We will be responsible for additional costs in connection with abandonment of properties.

We are responsible for payment of plugging and abandonment costs on our oil and gas properties pro rata to our working interest. Based on our experience, we anticipate that in most cases, the costs of abandoning such properties will range from $20,000 to $100,000 or more per well. In addition, abandonment costs and their timing may change due to many factors, including actual production results, inflation rates and changes in environmental laws and regulations.

Risks that Involve the Oil & Gas Industry in General.

We are subject to various governmental regulations which may cause us to incur substantial costs.

Our operations are affected from time to time in varying degrees by political developments and federal, state, and local laws and regulations. In particular, oil and natural gas production-related operations are or have been subject to price controls, taxes and other laws and regulations relating to the oil and gas industry. Failure to comply with such laws and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, because such laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations.

Sales of natural gas by us are not regulated and are generally made at market prices. However, the Federal Energy Regulatory Commission ("FERC") regulates interstate natural gas transportation rates and service conditions, which affect the marketing of natural gas produced by us, as well as the revenues received by us for sales of such production. Sales of our natural gas currently are made at uncontrolled market prices, subject to applicable contract provisions and price fluctuations that normally attend sales of commodity products.

Since the mid-1980s, the FERC has issued a series of orders, culminating in Order Nos. 636, 636-A and 636-B ("Order 636"), that have significantly altered the marketing and transportation of natural gas. Order 636 mandated a fundamental restructuring of interstate pipeline sales and transportation service, including the unbundling by interstate pipelines of the sale, transportation, storage and other components of the city-gate sales services such pipelines previously performed. One of the FERC's purposes in issuing the orders was to increase competition within all phases of the natural gas industry. Order 636 and subsequent FERC orders issued in individual pipeline restructuring proceedings have been the subject of appeals, and the courts have largely upheld Order 636. Because further review of certain of these orders is still possible, and other appeals may be pending, it is difficult to exactly predict the ultimate impact of the orders on us and our natural gas marketing efforts. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines' traditional role as wholesalers of natural gas, and has substantially increased competition and volatility in natural gas markets.

While significant regulatory uncertainty remains, Order 636 may ultimately enhance our ability to market and transport our natural gas, although it may also subject us to greater competition, more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.

The FERC has announced several important transportation-related policy statements and proposed rule changes, including the appropriate manner in which interstate pipelines release capacity under Order 636 and, more recently, the price which shippers can charge for their released capacity. In addition, in 1995, the FERC issued a policy statement on how interstate natural gas pipelines can recover the costs of new pipeline facilities. In January 1997, the FERC issued a policy statement and a request for comments concerning alternatives to its traditional cost-of-service rate making methodology. A number of pipelines have obtained FERC authorization to charge negotiated rates as one such alternative. While any additional FERC action on these matters would affect us only indirectly, these policy statements and proposed rule changes are intended to further enhance competition in natural gas markets. We cannot predict what the FERC will take on these matters, nor can we predict whether the FERC's actions will achieve its stated goal of increasing competition in natural gas markets. However, we do not believe that we will be treated materially differently than other natural gas producers and marketers with which we compete.

The price we receive from the sale of oil is affected by the cost of transporting such products to market. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rates to inflation, subject to certain conditions and limitations. These regulations could increase the cost of transporting oil by interstate pipelines, although the most recent adjustment generally decreased rates. These regulations have generally been approved on judicial review. We are not able to predict with certainty the effect, if any, of these regulations on its operations. However, the regulations may increase transportation costs or reduce wellhead prices for oil.

The State of Texas and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration for and production of oil and natural gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from wells and the regulation of spacing, plugging and abandonment of such wells. The statutes and regulations of certain states limit the rate at which oil and gas can be produced from our properties. However, we do not believe we will be affected materially differently by these statutes and regulations than any other similarly situated oil and gas company.

We may not have enough insurance to cover all of the risks we face, which could result in significant financial exposure.

We maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We may elect not to carry insurance if our management believes that the cost of insurance is excessive relative to the risks presented. If an event occurs that is not covered, or not fully covered, by insurance, it could harm our financial condition, results of operations and cash flows. In addition, we cannot fully insure against pollution and environmental risks.

Future new technologies could make the products we sell obsolete.

Future alternative technologies could dramatically impact the demand for the natural gas and crude oil we sell thereby causing a material adverse impact on our operations and financial results. Such alternative technologies could also cause a material adverse impact on the value of our oil and natural gas properties.

Cyber-attacks or acts of cyber-terrorism could disrupt our business operations and information technology systems or result in the loss or exposure of confidential or sensitive customer, employee or Company information.

Our business operations and information technology systems may be vulnerable to an attack by individuals or organizations intending to disrupt our business operations and information technology systems, even though the Company has implemented policies, procedures and controls to prevent and detect these activities. We use our information technology systems to manage our oil and gas operations and other business processes. Disruption of those systems could adversely impact our ability to safely operate our wells, operate our pipelines or otherwise run our business. Accordingly, if such an attack or act of terrorism were to occur, our operations and financial results could be adversely affected. In addition, we use our information technology systems to protect confidential or sensitive employee and Company information developed and maintained in the normal course of our business. Any attack on such systems that would result in the unauthorized release of employee or other confidential or sensitive data could have a material adverse effect on our business reputation, increase our costs and expose us to additional material legal claims and liability. If such an attack or act of terrorism were to occur, our operations and financial results would be adversely affected since we may not maintain insurance coverage to cover these risks.

Natural disasters, terrorist activities or other significant events could adversely affect our operations or financial results.

Natural disasters are always a threat to our assets and operations. In addition, the threat of terrorist activities could lead to increased economic instability and volatility in the price of natural gas that could affect our operations. Also, companies in our industry may face a heightened risk of exposure to actual acts of terrorism, which could subject our operations to increased risks. As a result, the availability of insurance covering such risks may become more limited, which could increase the risk that an event could adversely affect our operations or financial results.

The operations and financial results of the Company could be adversely impacted as a result of climate changes or related additional legislation or regulation in the future.

To the extent climate changes occur, our businesses could be adversely impacted, although we believe it is likely that any such resulting impacts would occur very gradually over a long period of time and thus would be difficult to quantify with any degree of specificity. To the extent climate changes would result in warmer temperatures in our areas of operations, financial results could be adversely affected through lower gas volumes and revenues. In addition, there have been a number of federal and state legislative and regulatory initiatives proposed in recent years in an attempt to control or limit the effects of global warming and overall climate change, including greenhouse gas emissions, such as carbon dioxide. The adoption of this type of legislation by Congress or similar legislation by states or the adoption of related regulations by federal or state governments mandating a substantial reduction in greenhouse gas emissions in the future could have far-reaching and significant impacts on the energy

industry. Such new legislation or regulations could result in increased compliance costs for us or additional operating restrictions on our business, affect the demand for natural gas, or impact the prices we charge to our customers. At this time, we cannot predict the potential impact of such laws or regulations that may be adopted on our future business, financial condition or financial results.

We are subject to various environmental risks which may cause us to incur substantial costs.

Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling and transportation of oil and natural gas and the discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and impose substantial liabilities for pollution resulting from our operations. The permits required for our various operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, penalties or injunctions. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us. The impact of such changes, however, would not likely be any more burdensome to us than to any other similarly situated oil and gas company.

The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the "Superfund" law, and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Furthermore, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We generate typical oil and gas field wastes, including hazardous wastes that are subject to the Federal Resources Conservation and Recovery Act and comparable state statutes. The United States Environmental Protection Agency and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our oil and gas operations that are currently exempt from regulation as "hazardous wastes" may in the future be designated as "hazardous wastes", and therefore be subject to more rigorous and costly operating and disposal requirements.

The Oil Pollution Act ("OPA") imposes a variety of requirements on responsible parties for onshore and offshore oil and gas facilities and vessels related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The "responsible party" includes the owner or operator of an onshore facility or vessel or the lessee or permittee of, or the holder of a right of use and easement for, the area where an onshore facility is located. OPA assigns liability to each responsible party for oil spill removal costs and a variety of public and private damages from oil spills. Few defenses exist to the liability for oil spills imposed by OPA. OPA also imposes financial responsibility requirements. Failure to comply with ongoing requirements or inadequate cooperation in a spill event may subject a responsible party to civil or criminal enforcement actions.

We own or lease properties that for many years have produced oil and natural gas. We also own natural gas gathering systems. It is not uncommon for such properties to be contaminated with hydrocarbons. Although we or previous owners of these interests may have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties or on or under other locations where such wastes have been taken for disposal. These properties may be subject to federal or state requirements that could require us to remove any such wastes or to remediate the resulting contamination. In addition to properties that we operate, we have interests in many properties which are operated by third parties over whom we have limited control. Notwithstanding our lack of control over properties operated by others, the failure of the previous owners or operators to comply with applicable environmental regulations may, in certain circumstances, adversely impact us.

Item 1B. Unresolved Staff Comments

None

Item 2. Properties

OIL AND GAS PROPERTIES

The following table sets forth pertinent data with respect to the Company-owned oil and gas properties, all located within the continental United States, as estimated by the Company:

	Years Ended December 31,
	2018		2017		2016
Gas and Oil Properties, net (1)
Proved developed gas reserves-Mcf (2)
Proved developed producing		6,849,000		7,173,000		3,843,000
Proved developed non-producing		—		—		—
Proved undeveloped gas reserves-Mcf (3)		—		—		—
Total proved gas reserves-Mcf		6,849,000		7,173,000		3,843,000

Proved Developed Crude Oil and
Condensate reserves-Bbls (2)
Proved developed producing		262,000		309,000		313,000
Proved developed non-producing		—		—		—
Proved Undeveloped crude oil and		—		—		—
Condensate reserves-Bbls (3)		—		—		—
		262,000		309,000		313,000

(1) The estimate of the net proved oil and natural gas reserves, future net revenues, and the present value of future net revenues.

(2) "Proved Developed Oil and Natural 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 17 to the Financial Statements, Supplemental Reserve Information (Unaudited), for further explanation of the changes for 2016 through 2018.

(4) Reserve amounts are rounded to the nearest thousand.

Productive Wells

The following table sets forth our domestic productive wells, shut-in wells, and includes both operated wells and wells operated by third parties at December 31, 2018.

Gas Wells		Oil Wells		Total Wells
Gross	Net	Gross	Net	Gross	Net

289	103.4	167	66.81	456	170.21

Acreage

The following table sets forth our undeveloped and developed gross and net leasehold acreage for our operated and non-operated wells at December 31, 2018. Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves. Undeveloped acreage should not be confused with undrilled acreage held by Production under the terms of a lease. Undrilled acreage held by production under the terms of a lease is included in the Developed Acreage category total shown below.

Undeveloped Acreage		Developed Acreage		Total Acreage
Gross	Net	Gross	Net	Gross	Net

4,772	1,634	86,402	21,322	91,174	22,956

All the leases for the undeveloped acreage summarized in the preceding table will expire at the end of their respective primary terms unless prior to that date, the existing leases are renewed or production has been obtained from the acreage subject to the lease, in which event the lease will remain in effect until the cessation of production. As is customary in the industry, we generally acquire oil and gas acreage without any warranty of title except as to claims made by, through or under the transferor. Although we have title to developed acreage examined prior to acquisition in those cases in which the economic significance of the acreage justifies the cost, there can be no assurance that losses will not result from title defect or from defects in the assignment of leasehold rights.

Wells Drilled and Completed

The Company's working interests in both operated and outside operated exploration and development wells completed during the years indicated were as follows:

	2018				2017				2016
	Gross		Net		Gross		Net		Gross		Net

Exploratory Wells (1):
Productive		—		—		—		—		—		—
Non-Productive		—		—		—		—		—		—
Total		—		—		—		—		—		—

Developed Wells (2):
Productive		—		—		—		—		1.000		0.691
Non-Productive		—		—		—		—		—		—
Total		—		—		—		—		1.000		0.691

Total Exploration & Development Wells:
Productive		—		—		—		—		1.000		0.691
Non-Productive		—		—		—		—		—		—
Total		—		—		—		—		1.000		0.691

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

The following tables set forth additional data with respect to production from Company-owned oil and gas operated and non-operated properties, all located within the continental United States:

	For the years ended December 31,
	2018		2017		2016		2015		2014

Oil and Gas Production, net:
Natural Gas (Mcf)		874,812		619,654		582,348		730,709		739,948
Crude Oil & Condensate (Bbl)		43,136		51,082		50,248		64,207		89,068

Average Sales Price per Unit Produced
Natural Gas (Mcf)	$	2.86	$	2.87	$	2.08	$	2.51	$	4.53
Crude Oil & Condensate (Bbl)	$	62.09	$	47.70	$	37.49	$	44.77	$	93.38

Average Production Cost per Equivalent Barrel (1) (2)	$	13.18	$	13.33	$	13.04	$	15.94	$	15.23

(1) Includes severance taxes and ad valorem taxes.

(2) Natural gas production is converted to equivalent barrels at the rate of six MCFG per barrel, representing relative energy content of natural gas to oil.

The Company owns producing royalties and overriding royalties under properties located in Texas. The revenue from these properties is not significant.

The Company is not aware of any major discovery or other favorable or adverse event that is believed to have caused a significant change in the estimated proved reserves since December 31, 2018.

OFFICE SPACE

The Company owns a commercial office building. The property is a two story multi-tenant, garden office building with a sub-grade parking garage. The building was built in 1983 and contains approximately 46,286 rentable square feet, sitting on a 1.4919 acre block of land situated in north Dallas, Texas in close proximity to hotels, restaurants and shopping areas (the Galleria Mall) with easy access to Interstate Highway 635 (LBJ Freeway) and Dallas Parkway (North Dallas Toll Road). The Company occupies approximately 12,759 rentable square feet of the building as its primary office headquarters, and leases the remaining space in the building to non-related third party commercial tenants at prevailing market rates.

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, several miles of natural gas pipelines in Texas and other states. These pipelines are steel and polyethylene and range in size from two inches to four inches. These pipelines primarily gather natural gas from wells operated by the Company and in which the Company owns a working interest, and may also gather for other parties.

The Company normally does not purchase and resell natural gas, but gathers natural 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.

Oilfield Production Equipment

The Company owns various natural gas compressors, pumping units, dehydrators and various other pieces of oilfield 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.

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 subsidiaries, nor are any of their properties subject to any proceedings.

During the fourth quarter of the fiscal year covered by this report, no proceeding previously reported was terminated.

Item 4. Mine Safety Disclosures

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. The following table shows high and low trading prices for each quarter in 2018, 2017, and 2016 as aggregated by Yahoo!.com from various OTC sources.

	Price Per Share
	High		Low

2018
First Quarter	$ 3.86		$ 2.00
Second Quarter	$ 3.98		$ 2.11
Third Quarter	$ 3.95		$ 3.25
Fourth Quarter	$ 4.00		$ 2.09

2017
First Quarter	$ 3.48		$ 2.40
Second Quarter	$ 3.46		$ 3.05
Third Quarter	$ 3.46		$ 2.70
Fourth Quarter	$ 3.91		$ 3.11

2016
First Quarter	$ 1.91		$ 1.40
Second Quarter	$ 2.00		$ 1.54
Third Quarter	$ 2.10		$ 1.76
Fourth Quarter	$ 2.95		$ 1.76


During the First Quarter of 2019 subsequent to year end, the following high and low prices were recorded for the Company's common stock.

	Price Per Share
	High	Low
2019
First Quarter	$ 3.97	$ 3.65

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

According to the transfer records of the Company at March 29, 2019, common stock of the Company was held by approximately 536 known holders of record.

The following chart compares the yearly percentage change in the cumulative total stockholder return on the Company's Common Stock during the five years ended December 31, 2018 with the cumulative total return of the Standard and Poor's 500 Stock Index and of the Dow Jones U.S. Exploration and Production Index (formerly Dow Jones Secondary Oil Stock Index). The comparison assumes $100 was invested on December 31, 2013 in the Company's Common Stock and in each of the foregoing indices and assumes reinvestment of dividends. The Company paid no dividends on its Common Stock during the five-year period. Figures shown are past results and are not predictive of results in future periods.

Stock Performance Chart

Comparison of Five-Year Cumulative Total Return Among

Spindletop Oil & Gas Co., S&P 500 Index and

the Dow Jones U.S. Exploration and Production Index

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

The Company has not approved nor authorized any standing repurchase program for its common stock.

During the fourth quarter of the fiscal year ended December 31, 2018, the Company made the following one-time repurchase of its common stock:

Effective December 6, 2018, the Company repurchased 126,667 shares of its common stock as a “block” from a single stockholder at its request for a purchase price of $269,801 or $2.13 per share.

The repurchased shares are held as Treasury Stock.

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,
	2018		2017			2016			2015			2014

Total Revenue	$	6,734,000	$	5,604,000		$	4,515,000		$	5,944,000		$	13,208,000
Net Income (Loss)		264,000		(3,000	)		(1,329,000	)		(5,777,000	)		3,205,000
Earnings (Loss) per Share	$	0.04	$	0.00		$	(0.19	)	$	(0.83	)	$	0.46


	For the years ended December 31,
		2018		2017			2016			2015			2014

Total Assets	$	24,398,000	$	24,132,000		$	23,365,000		$	25,889,000		$	33,506,000
Long-Term Debt		—		—			—			—			—

Item 7. Management's Discussion And Analysis Of Financial Condition And

Results Of Operations

The following discussion should be read in conjunction with the financial statements and notes thereto appearing elsewhere in this report.

This Report on Form 10-K may contain forward-looking statements within the meaning of the federal securities laws, principally, but not only, under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” We caution investors that any forward-looking statements in this report, or which management may make orally or in writing from time to time, are based on management’s beliefs and on assumptions made by, and information currently available to, management. When used, the words “anticipate,” “believe,” “expect,” “intend,” “may,” “might,” “plan,” “estimate,” “project,” “should,” “will,” “result” and similar expressions which do not relate solely to historical matters are intended to identify forward-looking statements. These statements are subject to risks, uncertainties, and assumptions and are not guarantees of future performance, which may be affected by known and unknown risks, trends, uncertainties, and factors, that are beyond our control. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated, estimated, or projected. We caution you that while forward-looking statements reflect our good faith beliefs when we make them, they are not guarantees of future performance and are impacted by actual events when they occur after we make such statements. We expressly disclaim any responsibility to update our forward-looking statements, whether as a result of new information, future events or otherwise. Accordingly, investors should use caution in relying on past forward-looking statements, which are based on results and trends at the time they are made, to anticipate future results or trends.

Some of the risks and uncertainties that may cause our actual results, performance or achievements to differ materially from those expressed or implied by forward-looking statements include, among others, the factors listed and described at Item 1A “Risk Factors” in the Company’s Annual Report on Form 10-K discussed above, which investors should review.

Other sections of this report may also include suggested factors that could adversely affect our business and financial performance. Moreover, we operate in a very competitive and rapidly changing environment. New risks may emerge from time to time and it is not possible for management to predict all such matters; nor can we assess the impact of all such matters on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. Given these uncertainties, investors should not place undue reliance on forward-looking statements as a prediction of actual results. Investors should also refer to our quarterly reports on Form 10-Q for future periods and current reports on Form 8-K as we file them with the SEC, and to other materials we may furnish to the public from time to time through Forms 8-K or otherwise.

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 natural gas reserves are capitalized in cost centers on a country-by-country basis. For each cost center, capitalized costs, less accumulated amortization and related deferred income taxes, shall not exceed an amount (the cost center ceiling) equal to the sum of:

The present value of estimated future net revenues computed by applying current prices of oil and natural gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions; plus

The cost of properties not being amortized; plus

The lower of cost or estimated fair market value of unproven properties included in the costs being amortized; less

Income tax effects related to differences between the book and tax basis of the properties.

In order to test the cost center ceiling, the Company prepares a “Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves (Unaudited)” as of the end of each calendar year (“the Reserve Report”). The Company prepared its annual Reserve Report as of December 31, 2018.

Reserve estimates are prepared in accordance with standard Security and Exchange Commission guidelines. The estimated net future net cash flows for 2018, 2017, and 2016, were computed using a 12-month average price, calculated as the un-weighted arithmetic average of the first-day-of-the month price for each month of the year. 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 deductions were made for interest. 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. For the year ended December 31, 2016, the Company recorded an impairment expense in the carrying value of its proved oil and gas properties of $695,000. This impairment was due primarily to declines in the average realized prices for sales of its crude oil and natural gas.

These Reserve Reports do 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 natural 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. 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 natural gas reserves, the remaining estimated lives of the oil and natural 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.

During the year ended December 31, 2018, average quarterly natural gas prices per mcf for the Company were $3.03, $2.55, $2.74, and $2.93 respectively. During the year ended December 31, 2017, average quarterly natural gas prices per mcf for the Company were $2.25, $2.79, $2.83, and $2.82 respectively. Average quarterly natural gas prices per mcf for the Company for the year ended December 31, 2016 were $1.34, $1.77, $2.25, and $2.62 respectively.

During the year ended December 31, 2018, average quarterly crude oil prices per bbl for the Company were $51.95, $65.00, $57.61, and $52.48 respectively. During the year ended December 31, 2017, average quarterly crude oil prices per bbl for the Company were $46.24, $44.42, $44.06, and $49.72 respectively. Average quarterly crude oil prices per bbl for the Company for the year ended December 31, 2016 were $30.62, $38.02, $39.80, and $41.95 respectively.

The increases or decreases in the Company’s product prices have a direct effect on its cash flow, profits, projected development and drilling schedules, and the estimated net present value of its proved reserves. Prolonged, substantial decreases in oil and natural gas prices would likely have a material adverse effect on the Company’s business, financial condition, and results of operations, and could further limit the Company's access to liquidity and credit, and could hinder its ability to satisfy its capital requirements.

We may incur further impairments to our crude oil and natural gas properties in 2019 if prices do not increase. The possibility and amount of any future impairment is difficult to predict, and will depend, in part, upon future crude oil and natural gas prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs. We cannot assure you that we will not experience write-downs in the future. If commodity prices decline or if any of our proved reserves are revised downward, a write-down of the carrying value of our oil and gas properties may be required.

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. Substantial decreases in crude oil and natural gas prices would likely have a material adverse effect on the Company’s business, financial condition, and results of operations, and could further limit the Company's access to liquidity and credit, and could hinder its ability to satisfy its capital requirements. Accordingly, the Company may be required to seek additional financing from third parties in order to fund its exploration and development programs.

As noted in our Results of Operations discussion below, the Company has focused on lowering costs through headcount reduction by attrition and spending only on essential general and administrative expenditures. In order to raise additional revenue, the Company is pursuing the acquisition of new operated and non-operated reserves through acquisitions of producing properties and drilling ventures. The Company believes that it is well positioned to take advantage of the declining prices for existing wells with its cash reserves and ability to borrow in order to effect any acquisition.

Results of Operations

2018 Compared to 2017

Oil and natural gas revenues for the year ended December 31, 2018 were $5,848,000 compared to $4,495,000 for the year ended December 31, 2017, an increase of $1,353,000 or 30.1%.

Oil revenue for 2018 was approximately $3,350,000 compared to $2,717,000 for 2017, an increase of approximately $633,000 or 23.3%. Average oil prices increased to an average of $62.09 per barrel in 2018 from an average of $47.70 per barrel in 2017, an increase of $14.39 per barrel or 30.2%. Oil sales decreased to 43,136 barrels from approximately 51,082 barrels in 2017, a decrease of 7,946 barrels or 15.6%.

Natural gas revenue for 2018 was approximately $2,498,000 compared to $1,778,000 for 2017, an increase of approximately $720,000 or 40.5%. Natural gas sales increased to approximately 875,000 mcf in 2018 from approximately 620,000 mcf in 2017, an increase of approximately 255,000 mcf or 41.1%. Natural gas prices decreased to an average of $2.86 per mcf in 2018, a decrease of $0.01 or 0.3% from an average of $2.87 per mcf in 2017.

The increase in oil revenue is predominantly due to an increase in crude oil prices during 2018 compared to 2017. In addition, the increase in natural gas revenue is primarily due to natural gas production increases related to producing wells acquired during the fourth quarter of 2017.

Revenue from lease operations was approximately $258,000 for 2018, compared to approximately $394,000 in 2017, a decrease of approximately $136,000 or 34.5%. Revenue from lease operations results from field supervision charges on operated wells as well as administrative overhead billed to working interest owners.

Revenues from gas gathering, compression, and equipment rental for 2018 were approximately $136,000, an increase of $10,000 or 7.9% from approximately $126,000 in 2017. The increase was due primarily to an increase in natural gas volume sold through PPC.

Real estate rental revenue for 2018 was approximately $232,000, a decrease of $42,000 or 15.3% from approximately $274,000 in 2017. The decrease was due to an increase in vacancies at the Company’s corporate office building.

Interest income for 2018 was approximately $181,000, an increase of $14,000 from approximately $167,000 in 2017 or 8.4%. The increase in interest income was due to the Company investing its funds in both long-term and short-term certificates of deposit and depository accounts paying higher rates of interest than those received in prior years.

Other revenue for 2018 was $79,000, as compared to $148,000 in 2017, a decrease of $69,000 or 46.6%. The reduction in 2018 is due in part to the recognition of fees earned under a marketing agreement during 2017.

Lease operating expenses 2018 were $1,656,000 as compared to $1,542,000 in 2017, a net increase of approximately $114,000, or 7.4%. There were both increases and decreases within different segment categories of lease operating expenses. Amounts billed by third-party operators as operating expenses on non-operated properties decreased by approximately $50,000. There was an approximate $114,000 increase in expenses due to several wells that were acquired during late 2017. Workover expenses decreased approximately $73,000 between years. There was an increase of approximately $151,000 in 2018 over the prior year which included recovery through insurance proceeds. The remaining $28,000 represents net increases and decreases on various properties due to general price fluctuations and levels of operation activity.

Production taxes, gathering, and marketing expenses for 2018 were approximately $835,000 compared to $515,000 in 2017, an increase of approximately $320,000, or 62.1%. This increase was directly related to the increase in oil and natural gas production and revenues, which have been partially offset by a decrease in overall gathering and marketing expenses for non-operated leases.

Pipeline and rental expenses for 2018 were $49,000 compared to $40,000 for 2017, an increase of $9,000, or 22.5%.

Real estate expenses in 2018 were approximately $196,000 compared to $183,000 during the same period in 2017, an increase of approximately $13,000 or 7.1%.

Depreciation and amortization expense for 2018 was $499,000 compared to $522,000 for 2017, a decrease of $23,000 or 4.4%. Amortization of the full cost pool of oil and natural gas assets for 2018 was $439,000 compared to $457,000 for the year ended 2017, a decrease of $18,000 or 3.9%. The Company re-evaluated its proved oil and gas reserves as of December 31, 2018, and decreased its estimated total proved reserves by approximately 102,000 BOE to 1,403,000 BOE at the end of 2018 compared to 1,505,000 BOE at the end of 2017, a decrease of approximately 6.8%. Sales of oil and natural gas products during 2018 increased by 35,000 BOE from approximately 154,000 BOE in 2017 to approximately 189,000 BOE in 2018, an increase of approximately 22.7 %. (See Footnote 17 to the Financial Statements). This resulted in an increase in the depletion rate factor from 9.305% in 2017 on an unamortized full cost pool base of $4,922,000 to a depletion rate factor of 11.868% on an unamortized full cost pool base of $3,700,000 in 2018. The net decrease in the unamortized full cost pool base of $1,222,000 was due to accumulated depletion of $457,000 from 2017. In addition, $965,000 of proceed from sales of properties was credited to the full cost pool in accordance with GAAP. Proceeds from the sales of properties were used to acquire new properties whose purchase prices totaling $21,000 was added to the full cost pool. Other capitalized additions during 2018 of $179,000 were also added.

Asset Retirement Obligation (“ARO”) accretion expense for 2018 was $189,000 up from $12,000 in 2017, an increase of $177,000 or 1475.0%. The ARO calculation is based on the Company’s annual reserve report and takes into consideration the changes between years of the Company’s estimated obligation to plug its interest in existing wells. This estimated future cost is discounted using a 10% discount factor based on the estimated life of each property. Changes are incorporated as applicable into the full cost pool and the carrying value of the liability. Accretion expense measures and incorporates changes due to the passage of time into the carrying amount of the liability.

General and administrative expenses for 2018 were approximately $2,943,000 as compared to approximately $2,560,000 for 2017, an increase of approximately $383,000 or 15.0%. The increase was primarily due to increased salary, wages and employee benefits as new employees were added in late 2017 and during 2018. The Company also saw a significant increase in health insurance costs in 2018.

2017 Compared to 2016

Oil and natural gas revenues for the year ended December 31, 2017 were $4,495,000 compared to $3,320,000 for the year ended December 31, 2016, an increase of $1,175,000 or 35.4%.

Oil revenue for 2017 was approximately $2,717,000 compared to $2,106,000 for 2016, an increase of approximately $611,000 or 29.0%. Average oil prices increased to an average of $47.70 per barrel in 2017 from an average of $37.49 per barrel in 2016, an increase of $10.21 per barrel or 27.2%. Oil sales increased to 51,082 barrels from approximately 50,248 barrels in 2016, an increase of 834 barrels or 1.7%.

Natural gas revenue for 2017 was approximately $1,778,000 compared to $1,214,000 for 2016, an increase of approximately $564,000 or 46.5%. Natural gas sales increased to approximately 620,000 mcf in 2017 from approximately 582,000 mcf in 2016, an increase of approximately 38,000 mcf or 6.5%. Natural gas prices increased to an average of $2.87 per mcf in 2017, an increase of $0.79 or 38.0% from an average of $2.08 per mcf in 2016.

The increase in oil and gas revenue is predominantly due to an increase in crude oil and natural gas prices during 2017 compared to 2016. In addition, production increases were aided by production from producing wells acquired during the fourth quarter of 2017.

Revenue from lease operations was approximately $394,000 for 2017, compared to approximately $415,000 in 2016, a decrease of approximately $21,000 or 5.1%. Revenue from lease operations results from field supervision charges on operated wells as well as administrative overhead billed to working interest owners.

Revenues from gas gathering, compression, and equipment rental for 2017 were approximately $126,000, an increase of $12,000 or 10.5% from approximately $114,000 in 2016. This was due primarily to an increase in natural gas volume sold through PPC.

Real estate rental revenue for 2017 was approximately $274,000, a decrease of $40,000 or 12.7% from approximately $314,000 in 2016. The decrease was due to an increase in vacancies at the Company’s corporate office building.

Interest income for 2017 was approximately $167,000, an increase of $84,000 from approximately $83,000 in 2016 or 101.2%. The increase in interest income was due to the Company investing its funds in both long-term and short-term certificates of deposit and depository accounts paying higher rates of interest than those received in prior years.

Other revenue for 2017 was $148,000, as compared to $269,000 in 2016, a decrease of $121,000 or 45.0%. The reduction in 2017 is due in part to the timing of a negotiated settlement in 2016 as well as recognition of fees earned under a drilling venture during 2016.

Lease operating expenses 2017 were $1,542,000 as compared to $1,499,000 in 2016, a net increase of approximately $43,000, or 2.9%. There were both increases and decreases within different segment categories of lease operating expenses. Amounts billed by third-party operators as operating expenses on non-operated properties decreased by approximately $51,000. There was an approximate $25,000 decrease in expenses due to several wells that were either divested or plugged during 2016. Workover expenses increased approximately $124,000 between years. Workover activity in 2016 was reduced due to reduced drilling and workover activity as the result of lower oil and natural gas price economics in 2016. There was a decrease of approximately $26,000 related to an environmental remediation expense associated with a nonrecurring weather event in 2016 of approximately $140,000 for which the expense was offset in 2017 with a $114,000 recovery through insurance proceeds. The remaining $65,000 represents net increases and decreases on various properties due to general price fluctuations and levels of operation activity.

Production taxes, gathering, and marketing expenses for 2017 were approximately $515,000 compared to $422,000 in 2016, an increase of approximately $93,000, or 22.0%. This increase was directly related to the increase in oil and natural gas production and revenues, which have been partially offset by a decrease in overall gathering and marketing expenses for non-operated leases.

Pipeline and rental expenses for 2017 were $40,000 compared to $46,000 for 2016, a decrease of $6,000, or 13.0%.

Real estate expenses in 2017 were approximately $183,000 compared to $175,000 during the same period in 2016, an increase of approximately $8,000 or 4.6%.

Depreciation and amortization expense for 2017 was $522,000 compared to $1,104,000 for 2016, a decrease of $582,000 or 52.7%. Amortization of the full cost pool of oil and natural gas assets for 2017 was $457,000 compared to $1,038,000 for the year ended 2016, a decrease of $581,000 or 56.0%.

The Company re-evaluated its proved oil and gas reserves as of December 31, 2017, and increased its estimated total proved reserves by approximately 551,000 BOE to 1,505,000 BOE at the end of 2017 compared to 954,000 BOE at the end of 2016, an increase of approximately 57.8%. Sales of oil and natural gas products during 2017 increased by 7,000 BOE from approximately 147,000 BOE in 2016 to approximately 154,000 BOE in 2017, an increase of approximately 4.8 %. (See Footnote 17 to the Financial Statements). This resulted in a decrease in the depletion rate factor from 13.378% in 2016 on an unamortized full cost pool base of $7,756,000 to a depletion rate factor of 9.305% on an unamortized full cost pool base of $4,922,000 in 2017. The net decrease in the unamortized full cost pool base of $2,834,000 was due to accumulated depletion of $1,038,000 from 2016. There was an additional impairment of the full cost pool for 2016 of $695,000 (See paragraph below). In addition, $4,732,000 of proceed from sales of properties was credited to the full cost pool in accordance with GAAP. Proceeds from the sales of properties were used to acquire new properties whose purchase prices totaling $3,228,000 was added to the full cost pool. Other capitalized additions during 2017 of $403,000 were also added.

The Company recorded an impairment expense in the carrying value of its proved oil and gas properties of $5,116,000 in 2015 and $695,000 in 2016 due primarily to declines in the average realized prices for sales of its crude oil and natural gas on the first calendar day of each month during the trailing 12-month period prior to December 31, 2015 and 2016 respectively. The net present value of the Company’s proved oil and natural gas reserves, discounted at 10% at December 31, 2016, was approximately $6,023,000 compared to $7,006,000 at December 31, 2015 and $22,218,000 at December 31, 2014. (See Footnote 17 to the Financial Statements).

A ceiling test at December 31, 2016, determined that the unamortized cost of the full cost pool of $7,756,000 less the current year amortization of $1,038,000 equaled $6,718,000, which is $695,000 above the net present value of the Company’s proved oil and gas reserves. The impairment provision was credited to accumulated depreciation and amortization on the balance sheet. No impairment of oil and gas properties charge was recorded for 2017.

Asset Retirement Obligation (“ARO”) accretion expense for 2017 was $12,000 down from $36,000 in 2016, a decrease of $24,000 or 66.7%. The ARO calculation is based on the Company’s annual reserve report and takes into consideration the changes between years of the Company’s estimated obligation to plug its interest in existing wells. This estimated future cost is discounted using a 10% discount factor based on the estimated life of each property. Changes are incorporated as applicable into the full cost pool and the carrying value of the liability. Accretion expense measures and incorporates changes due to the passage of time into the carrying amount of the liability.

General and administrative expenses for 2017 were approximately $2,560,000 as compared to approximately $2,512,000 for 2016, an increase of approximately $48,000 or 1.9%. The decreases for 2017 and 2016 as compared to 2015 were primarily due to decreases in salary, wages and related employee benefits. In view of the large decreases in oil and gas prices and reduction of revenues during 2016, the Company has made a concentrated effort to reduce its general and administrative costs. Personnel costs have been reduced primarily through an approximate 8.0% reduction in headcount through attrition. As employees left the Company, they were not replaced and responsibilities have been spread among the remaining staff. This decrease has been partially offset by cost of living wage adjustments and higher health insurance premiums.

Item 8. Consolidated Financial Statements and

Schedules Index at Page 44

Item 9. Changes In And Disagreements With Accountants On Accounting And Financial Disclosure

None

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial and Accounting Manager, we conducted an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e)) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), which are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Principal Executive Officer and Principal Financial and Accounting Manager, as appropriate to allow timely decisions regarding required disclosure. Based on this evaluation, our Principal Executive Officer and Principal Financial and Accounting Manager concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. There are inherent limitations to the effectiveness of any system of internal control over financial reporting. These limitations include the possibility of human error, the circumvention of overriding of the system and reasonable resource constraints. Because of its inherent limitations, our internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with policies or procedures may deteriorate.

Management assessed the effectiveness of the Company’s internal controls over financial reporting as of December 31, 2018. In making this assessment, management used the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on management’s assessments and those criteria, management has concluded that Company’s internal control over financial reporting was effective as of December 31, 2018.

This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial report. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.

Changes in Internal Control over Financial Reporting

In preparation for management’s report on internal control over financial reporting, we documented and tested the design and operating effectiveness of our internal control over financial reporting. There were no changes in our internal controls over financial reporting (as such term is defined in Exchange Act Rule 13a-15(f)) that occurred during the quarter ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

Not Applicable

PART III

Item 10. Directors and Executive Officers Of The Registrant

The Directors and Executive Officers of the Company and certain information concerning them is set forth below:

Name	Age	Position

Chris G. Mazzini	61	Chairman of the Board, Director, and President

Michelle H. Mazzini	57	Director, Vice President, Secretary, and Treasurer

Ted R. Munselle	63	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. 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.

Mr. Ted R. Munselle has been a member of the Board of Directors of Spindletop Oil & Gas Co. since 2012. Mr. Munselle is Vice President and Chief Financial Officer (since October 1998) of Landmark Nurseries, Inc. He is a Certified Public Accountant (since 1980) who was employed as an Audit Partner in two Dallas, Texas based CPA firms (1986 to 1998), as an Audit Manager at Grant Thornton, LLP (1983 to 1986) and as Audit Staff to Audit Supervisor at Laventhol & Horwath (1977 to 1983). Mr. Munselle is also a director (since February 2004) of American Realty Investors, Inc. and Transcontinental Realty Investors, Inc., both of which are Nevada corporations which have their common stock listed and traded on the New York Stock Exchange (“NYSE”), as well as a director (since May 2009) of Income Opportunity Realty Investors, Inc., a Nevada corporation which has its common stock listed and traded on the NYSE American.

Key and Technical Employees

In addition to the services provided by Mr. Mazzini and Ms. Mazzini (both of whom have biographies listed above), the Company also relies extensively on the key and the technical employees identified below.

Dave Chivvis, Petroleum Engineer, joined the Company in May, 2008. Mr. Chivvis earned his Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1993. After graduation, he worked for Cox Resources Corporation, an independent oil and gas company located in Dallas, Texas. Mr. Chivvis worked in various engineering areas from operations to acquisitions of oil and gas properties in Texas, Oklahoma, Louisiana, and Arkansas. He then moved to Los Angeles in 2001 to pursue other opportunities before moving back to Texas to join the Company.

Charles (Chuck) D. Howell, Jr., Geologist, joined the Company in April, 2008. Mr. Howell earned a Bachelor of Science in Geology from Southern Methodist University in 1999. Currently, he is finishing his Ph.D. in Geology at the University of Texas at Dallas. Mr. Howell has been in the energy industry since 2003. He began his career at Pioneer Natural Resources working in the Gulf of Mexico. During 2005, Mr. Howell was an Independent Consulting Geologist for Anadarko Petroleum Corporation and worked on development of the historic Salt Creek Oil Field. In 2007, immediately before joining Spindletop Oil and Gas Company, he was a Geologist for Chevron Energy Technology Company in Houston, Texas and was part of a team of stratigraphic specialists for the West Coast of Africa. Mr. Howell is a long-standing and active member of the American Association of Petroleum Geologists, the Society for Sedimentary Geology, the Geological Society of America, the International Association of Sedimentologists, and remains associated with the Ichnology Research Group.

Dick A. Mastin, Petroleum Landman, has been a full-time employee of the Company since February, 2006. Mr. Mastin graduated cum laude from Stephen F. Austin State University in 1980 with a Bachelor of Science in Forestry and a minor in General Business. From September of 1980 until December of 1985, Mr. Mastin worked for Spindletop Oil & Gas Co. as a Petroleum Landman. He received his Masters of Science in Management and Administrative Sciences from the University of Texas at Dallas in 1990. In January of 1987, he took a position with the Dallas office of the Federal Bureau of Investigation. After a year with the Bureau, he accepted a position with the Internal Revenue Service as a Revenue Agent. Fifteen of his eighteen years with the Service were spent in the Large and Mid-Sized Business unit auditing tax returns of the largest business entities.

Glenn E. Sparks is the Land Director and also acts as Associate General Counsel to the Company. Mr. Sparks was previously employed as a Landman by the Company from 1982 through 1986, prior to attending law school. Mr. Sparks holds a B.B.A. with a concentration in Finance from the University of Texas at Arlington, and a J.D. from Texas Tech University School of Law. From 1990 to 2005, Mr. Sparks practiced law in a private practice focusing primarily on oil and gas law and real estate, as a partner in the law firm of Logan & Sparks, PLLC, and has acted as outside legal counsel for the Company in numerous oil and gas transactions during his years in private practice. Mr. Sparks left his private law practice and joined the Company again as an employee in his current position in 2005. Mr. Sparks is Board Certified in Oil & Gas Mineral Law by the Texas Board of Legal Specialization.

Christine Tesdall, Accounting Manager, joined the Company in August, 2013. Ms. Tesdall graduated from Texas A&M University in 1989 with a BBA degree in Accounting and began her accounting career as an auditor with Coopers & Lybrand. Ms. Tesdall has been a Certified Public Accountant since 1991.

Family Relationships

Michelle Mazzini, Vice President, Secretary, Treasurer, 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.

Board Meetings and Committees

The Board of Directors met one time in 2018. The Board has established an audit committee. The Board is small and all members of the Board serve on the audit committee. The function of the audit committee is to assist the Board in fulfilling its oversight responsibilities by reviewing the financial information that will be provided to the shareholders and others, the systems of internal controls that management and the Board of Directors have established, and the audit process. During 2018, Mr. Munselle was Chairman of the Audit Committee.

With respect to nominations to the Board, compensation, financial planning, strategies, and business alternatives, the Company does not have separate committees as the Board is small and all members of the Board participate in making recommendations and decisions on these matters.

Item 11. Executive Compensation

Cash Compensation

Cash compensation including salaries and bonuses, of $227,389, $221,114, and $169,687 was paid to Mr. Mazzini in 2018, 2017, and 2016 respectively. Cash compensation including salaries and bonuses of $157,558, $155,336, and $130,207 was paid to Ms. Mazzini in 2018, 2017, and 2016 respectively.

The Company has no stock option or incentive plan, does not grant any plan-based awards or awards of equity securities. The Company has no pension plan for its employees.

Compensation Pursuant to Plan

None

Other Compensation

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

Compensation of Directors

Directors who are employees of the Company are not currently compensated for their services on the Board. Mr. Munselle was paid a director’s fee of $10,000 in 2018, $10,000 in 2017 and $10,000 in 2016 to compensate him for his position as the Board of Directors’ Financial Expert. Mr. Munselle also receives $2,500 for each Board of Directors’ meeting during the year other than the annual meeting.

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 April 1, 2019 with respect to: (i) any person who is known to the Registrant to be the owner of more than five percent of the Registrant's common stock; (ii) the common stock of the Registrant beneficially owned by each of the directors of the Registrant, and (iii) by all officers and directors as a group. Each person has sole investment and voting power with respect to the shares indicated, except as otherwise set forth in the footnotes to the table.

Name and Address of Beneficial Owner	Number of Shares	Nature of Beneficial Ownership *	Percent Based on Outstanding Percent of Class **

Chris Mazzini and Michelle Mazzini	5,900,543	(1)	86.65%
12850 Spurling Rd., Suite 200
Dallas, Texas 75230

All officers and directors as a group	5,900,543		86.65%

* “Beneficial Ownership” means the sole or shared power to vote, or direct the voting of, a security or investment power with respect to a security, or any combination thereof.

** Percentages are based upon 6,809,602 shares of Common Stock outstanding at April 1, 2019.

(1) Chris Mazzini directly owns 39,654 shares (0.5823%). Giant Energy Corp. directly owns 5,860,889 shares (86.0680%). Chris Mazzini owns 100% of the common stock of Giant Energy Corp.

Changes in control

The Company is not aware of any arrangements or pledges with respect to its securities that may result in a change in control of the Company.

Item 13. Certain Relationships And Related Transactions

Transactions with management and others

Certain Business Relationships

On October 1, 2008, Giant entered into an Administrative Services Agreement with the Company whereby Giant pays the Company $250 per month for the Company providing administrative services to Giant. On October 1, 2008, the Company entered into a similar agreement with Giant NRG, LP (“NRG”) a limited partnership with Chris Mazzini and Michelle Mazzini as limited partners. Under this agreement NRG pays a monthly fee of $2,500 to the Company in exchange for the Company providing certain administrative services to NRG. Effective August 1, 2016, this administrative services fee was reduced to $1,500 per month. The Company has entered into a similar arrangement with Peveler Pipeline, LP ("Peveler"), whereby Peveler pays the Company a monthly charge of $250 in exchange for the Company providing administrative services to Peveler. Chris and Michelle Mazzini are the owners of Peveler Pipeline, LP, a limited partnership which owns a pipeline gathering system servicing wells owned by Giant, another related entity, described elsewhere in this report. The Company entered into a similar agreement with M-R Ventures, LLC (“MRV”) a limited liability company that operates some wells in Michigan, and that is owned by Chris and Michelle Mazzini. Pursuant to this agreement, MRV pays the Company a monthly fee in the amount of $500 for certain administrative services that the Company provides to MRV. The Company entered into a similar agreement with Reserve Royalty Company (“Reserve”) a sole proprietorship that holds some royalty interests owned by Chris and Michelle Mazzini. Pursuant to this agreement, Reserve pays the Company a monthly fee in the amount of $350 for certain administrative services that the Company provides to Reserve. See also note 5 to the Financial Statements.

Item 14. Principal Accounting Fees and Services

The following table sets forth the aggregate fees for professional services rendered to Spindletop Oil & Gas Co. and Subsidiaries for the years 2018 and 2017 by accounting firm, Farmer, Fuqua, & Huff, P.C.

Type of Fees	2018		2017

Audit Fees	$	47,500	$	47,500
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. an independent registered public accounting firm, 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 2018 and 2017were 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	48-49
	Consolidated Balance Sheets	50-51
	Consolidated Statements of Operations	52
	Consolidated Statements of Changes in Stockholders' Equity	53
	Consolidated Statements of Cash Flows	54
	Notes to Consolidated Financial Statements	55


	(2) FINANCIAL STATEMENT SCHEDULES:

	Schedule II - Valuation and Qualifying Accounts	73
	Schedule III - Real Estate and Accumulated Depreciation	74


	Other financial statement schedules have been omitted because the information required to be set forth therein is not applicable, is immaterial or is shown in the consolidated financial statements or notes thereto.

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

	Exhibit Designation		Exhibit Description

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

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

	14		Code of Ethics for Senior Financial Officers (Incorporated by reference to Exhibit 14 to the registrant's annual report Form 10-K for the fiscal year ended December 31, 2005)

	21	*	Subsidiaries of the Registrant

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

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

	32.	*	Officers' Section 1350 Certifications

	* Filed herewith

(b) The Index of Exhibits is included following the Financial Statement Schedules beginning at page 73 of this Report.

(c) The Index to Consolidated Financial Statements and Supplemental Schedules is included following the signatures, beginning at page 47 of this Report

(d) Supplemental Reserve Information (unaudited) is included in Note 17 to the Consolidated Financial Statements.

SIGNATURES

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

SPINDLETOP OIL & GAS CO.

Date: April 01, 2019

	By:/s/ Chris G. Mazzini
	Chris G. Mazzini
	President, Principal Executive Officer


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

Signatures
Principal Executive Officers	Capacity	Date


/s/ Chris Mazzini
	President, Director	April 01, 2019
Chris Mazzini	(Chief Executive Officer


/s/ Michelle Mazzini
	Vice President, Secretary,	April 01, 2019
Michelle Mazzini	Treasurer, Director


/s/ Ted R. Munselle
	Director	April 01, 2019
Ted R. Munselle


/s/ Christine L. Tesdall	Principal Financial	April 01, 2019
	and Accounting Manager
Christine L. Tesdall

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


	Page

Report of Independent Registered Public Accounting Firm	48-49

Consolidated Balance Sheets - December 31, 2018 and 2017	50-51

Consolidated Statements of Operations for the years ended
December 31, 2018, 2017 and 2016	52

Consolidated Statements of Changes in Shareholders' Equity
for the years ended December 31, 2018, 2017 and 2016	53

Consolidated Statements of Cash Flows
for the years ended December 31, 2018, 2017 and 2016	54

Notes to Consolidated Financial Statements	55

Schedules for the years ended December 31, 2018, 2017 and 2016
II - Valuation and Qualifying Accounts	73
III - Real Estate and Accumulated Depreciation	74


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.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and

Shareholders of Spindletop Oil & Gas Co.

Opinion of the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Spindletop Oil & Gas Co. (A Texas Corporation) and subsidiaries as of December 31, 2018 and 2017, and the related consolidated statements of operations, shareholders' equity and cash flows for each of the years in the three-year period ended December 31, 2018, and the related notes and schedules (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

Basis of Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. 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, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Supplemental Information

Our audits were made for the purpose of forming an opinion on the basic consolidated financial statements taken as a whole. The schedules listed in the index of the consolidated financial statements are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic consolidated financial statements. Spindletop Oil & Gas Co.’s management is responsible for the schedules. 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.

We are uncertain as to the year our predecessor firm began serving as the auditor of the Company’s consolidated financial statements; however, we are aware that we have been the Company’s auditor consecutively since at least 1995.

/s/ Farmer, Fuqua & Huff, P.C.

Richardson, Texas

April 1, 2019

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

		December 31,			December 31,
		2018			2017
ASSETS

Current Assets
Cash and cash equivalents	$	14,036,000		$	11,707,000
Restricted cash		363,000			363,000
Accounts receivable		2,615,000			3,178,000
Income tax receivable		235,000			259,000
Total Current Assets		17,249,000			15,507,000

Property and Equipment - at cost
Oil and gas properties (full cost method)		27,892,000			28,566,000
Rental equipment		412,000			406,000
Gas gathering system		115,000			115,000
Other property and equipment		296,000			296,000
		28,715,000			29,383,000
Accumulated depreciation and amortization		(25,256,000	)		(24,804,000	)
Total Property and Equipment		3,459,000			4,579,000

Real Estate Property - at cost
Land		688,000			688,000
Commercial office building		1,580,000			1,580,000
Accumulated depreciation		(945,000	)		(897,000	)
Total Real Estate Property		1,323,000			1,371,000

Other Assets
Other long-term investments		2,358,000			2,666,000
Other		9,000			9,000
Total Other Assets		2,367,000			2,675,000
Total Assets	$	24,398,000		$	24,132,000



The accompanying notes are an integral part of these statements.

SPINDLETOP OIL & GAS Co. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

		December 31,			December 31,
		2018			2017
LIABILITIES AND SHAREHOLDERS' EQUITY

Current Liabilities
Accounts payable and accrued liabilities	$	5,857,000		$	5,608,000
Total Current Liabilities		5,857,000			5,608,000

Noncurrent Liabilities
Asset retirement obligation		1,324,000			1,180,000
Total Noncurrent Liabilities		1,324,000			1,180,000

Deferred Income Tax Payable		86,000			207,000

Total Liabilities		7,267,000			6,995,000

Shareholders' Equity
Common stock, $.01 par value, 100,000,000 shares authorized; 7,677,471 shares issued. 6,809,602 shares outstanding at December 31, 2018 and 6,936,269 shares outstanding at December 31, 2017.		77,000			77,000
Additional paid-in capital		943,000			943,000
Treasury stock, at cost		(1,806,000	)		(1,536,000	)
Retained earnings		17,917,000			17,653,000
Total Shareholders' Equity		17,131,000			17,137,000
Total Liabilities and Shareholders' Equity	$	24,398,000		$	24,132,000






The accompanying notes are an integral part of these statements.

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

	Years Ended December 31,
	2018			2017			2016
Revenues
Oil and gas revenues	$	5,848,000		$	4,495,000		$	3,320,000
Revenue from lease operations		258,000			394,000			415,000
Gas gathering, compression, equipment rental		136,000			126,000			114,000
Real estate rental income		232,000			274,000			314,000
Interest Income		181,000			167,000			83,000
Other		79,000			148,000			269,000
Total Revenues		6,734,000			5,604,000			4,515,000

Expenses
Lease operations		1,656,000			1,542,000			1,499,000
Production taxes, gathering and marketing		835,000			515,000			422,000
Pipeline and rental operations		49,000			40,000			46,000
Real estate operations		196,000			183,000			175,000
Depreciation and amortization		499,000			522,000			1,104,000
Impairment of oil & gas properties		—			—			695,000
ARO accretion expense		189,000			12,000			36,000
General and administrative		2,943,000			2,560,000			2,512,000
Total Expenses		6,367,000			5,374,000			6,489,000
Income (Loss) Before Income Tax		367,000			230,000			(1,974,000	)

Current income tax provision (benefit)		224,000			44,000			(173,000	)
Deferred income tax provision (benefit)		(121,000	)		189,000			(472,000	)
Total income tax provision (benefit)		103,000			233,000			(645,000	)
Net Income (Loss)	$	264,000		$	(3,000	)	$	(1,329,000	)

Earnings (Loss) per Share of Common Stock
Basic and Diluted	$	0.04		$	—		$	(0.19	)

Weighted Average Shares Outstanding
Basic and Diluted		6,925,511			6,936,269			6,936,269

The accompanying notes are an integral part of these statements.

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
For the Years Ended December 31, 2018, 2017, and 2016


	Common Stock Shares		Common Stock Amount		Additional Paid-In Capital	Treasury Stock Shares		Treasury Stock Amount			Retained Earnings

Balance December 31, 2015	7,677,471	$	77,000	$	943,000	741,202	($	1,536,000	)	$	18,985,000

Net Loss	—		—		—	—		—			(1,329,000	)
Balance December 31, 2016	7,677,471		77,000		943,000	741,202		(1,536,000	)		17,656,000

Net Loss	—		—		—	—		—			(3,000	)
Balance December 31, 2017	7,677,471		77,000		943,000	741,202		(1,536,000	)		17,653,000

Purchase of 126,667 shares of Common Stock as Treasury Stock						126,667		(270,000	)
Net Income	—		—		—	—		—			264,000
Balance December 31, 2018	7,677,471	$	77,000	$	943,000	867,869	($	1,806,000	)	$	17,917,000



The accompanying notes are an integral part of these statements.

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

	Twelve Months Ended
	December 31,			December 31,			December 31,
	2018			2017			2016
Cash Flows from Operating Activities
Net Income (Loss)	$	264,000		$	(3,000	)	$	(1,329,000	)
Reconciliation of net income (loss) to net cash
provided by operating activities
Depreciation and amortization		499,000			522,000			1,104,000
Impairment of oil and gas properties		—			—			695,000
Accretion of asset retirement obligation		189,000			12,000			36,000
Insurance proceeds received for environmental remediation		—			278,000			—
Gain on insurance proceeds received		—			(157,000	)		—
Changes in accounts receivable		(16,000	)		(671,000	)		(93,000	)
Changes in income tax receivable		24,000			668,000			(173,000	)
Changes in accounts payable and accrued liabilities		249,000			222,000			(518,000	)
Changes in deferred Income tax payable		(121,000	)		189,000			(472,000	)
Changes in other assets		—			—			(3,000	)
Net cash provided (used) for operating activities		1,088,000			1,060,000			(753,000	)

Cash Flows from Investing Activities
Capitalized acquisition, exploration and development		(320,000	)		(192,000	)		(990,000	)
Changes in Other long-term investments		308,000			(1,116,000	)		50,000
Proceeds from sale of oil and gas properties		1,523,000			934,000			—
Refund of prepaid drilling costs not spent		—			—			232,000
Net cash provided (used) for investing activities		1,511,000			(374,000	)		(708,000	)

Cash Flows from Financing Activities
Purchase of 126,667 shares of treasury stock		(270,000	)		—			—
Net cash used for financing activities		(270,000	)		—			—
Increase (Decrease) in cash, cash equivalents, and restricted cash		2,329,000			686,000			(1,461,000	)

Cash, cash equivalents, and restricted cash at beginning of period		12,070,000			11,384,000			12,845,000
Cash, cash equivalents, and restricted cash at end of period	$	14,399,000		$	12,070,000		$	11,384,000


The accompanying notes are an integral part of these statements.

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION AND ORGANIZATION

Merger and Basis of Presentation

On July 13, 1990, Prairie States Energy Co., a Texas corporation, (the Company) merged with Spindletop Oil & Gas Co., a Utah corporation (the Acquired Company). The name of Prairie States Energy Co. was changed to Spindletop Oil & Gas Co., a Texas corporation at the time of the merger.

Organization and Nature of Operations

The Company was organized as a Texas corporation in September 1985, in connection with the Plan of Reorganization ("the Plan"), effective September 9, 1985, of Prairie States Exploration, Inc., ("Exploration"), a Colorado corporation, which had previously filed for Chapter 11 bankruptcy. In connection with the Plan, Exploration was merged into the Company, with the Company being the surviving corporation.

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

The Company owns land along with a commercial office building which contains approximately 46,286 of rentable square feet, of which the Company occupies approximately 12,759 rentable square feet as its corporate office headquarters. The Company leases the remaining space in the building to non-related third party commercial tenants at prevailing market rates.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Consolidation

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

Cash and Cash Equivalents

The Company considers all highly liquid instruments with a maturity of three months or less at time of original issuance to be cash equivalents.

Other Investments

Other short-term and long-term investments consist of certificates of deposit with maturities of more than three months. Carrying amounts approximate fair value.

Allowance for Doubtful Accounts

The Company provides an allowance for doubtful accounts equal to the estimated uncollectible portion of accounts receivable. This estimate is based on historical collection experience and a review of the current status of accounts receivable.

Oil and Gas Properties

The Company follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs associated with acquisition, exploration and development of oil and natural gas reserves are capitalized and accounted for in cost centers, on a country-by-country basis. For each cost center, capitalized costs, less accumulated amortization and related deferred income taxes, shall not exceed an amount (the cost center ceiling) equal to the sum of:

The cost of properties not being amortized; plus

The lower of cost or estimated fair market value of unproven properties included in the costs being amortized; less

Income tax effects related to differences between the book and tax basis of the properties.

If unamortized costs capitalized within a cost center, less related deferred income taxes, exceed the cost center ceiling (as defined), the excess is charged to expense and separately disclosed during the period in which the excess occurs. Amounts required to be written off will not be reinstated for any subsequent increase in the cost center ceiling. For the year ended December 31, 2016, the Company recorded an impairment expense in the carrying value of its proved oil and gas properties of $695,000. This impairment was due primarily to declines in the average realized prices for sales of its crude oil and natural gas. There were no impairments for the years ended December 31, 2017 and 2018.

Depreciation and amortization for each cost center are computed on a composite unit-of-production method, based on estimated proven reserves attributable to the respective cost center. All costs associated with oil and gas properties are currently included in the base for computation and amortization. Such costs include all acquisition, exploration, development costs and estimated future expenditures for proved undeveloped properties as well as estimated dismantlement and abandonment costs as calculated under the asset retirement obligation category, net of salvage value. All of the Company's oil and gas properties are located within the continental United States.

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

Property and Equipment

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

The Company, as operator, transports natural gas through its natural 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 natural gas gathering systems, 4 to 5 years for other property and equipment). The straight-line method of depreciation is used for financial reporting purposes, while accelerated methods are used for tax purposes.

Real Estate Property

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

Investments in Real Estate

All investments in real estate holdings are stated at cost or adjusted carrying value. ASC Topic 360, “Accounting for the Impairment or Disposal of Long-Lived Assets”, requires that a property be considered impaired if the sum of the expected future cash flows (undiscounted and without interest charges) is less than the carrying amount of the property. If impairment exists, an impairment loss is recognized by a charge against earnings equal to the amount by which the carrying amount of the property exceeds fair market value less cost to sell the property. If impairment of a property is recognized, the carrying amount of the property is reduced by the amount of the impairment, and a new cost for the property is established. Depreciation is provided over the properties estimated remaining useful life. There was no charge to earnings during 2018, 2017, or 2016 due to impairment of real estate holdings.

Accounting for Asset Retirement Obligations

The Company adopted ASC Topic 410-20, "Accounting for Asset Retirement Obligations" on December 31, 2005. This statement requires the recording of a liability in the period in which an asset retirement obligation ("ARO") is incurred, in an amount equal to the discounted estimated fair value of the obligation that is capitalized. Thereafter, each quarter, this liability is accreted up to the final retirement cost. The determination of the ARO is based on an estimate of the future cost to plug and abandon our oil and gas wells. The actual costs could be higher or lower than current estimates.

The following table reflects the changes of the asset retirement obligations during the period ending December 31;

	2018			2017
Carrying amount of asset retirement obligation	$	1,180,000		$	916,000
Liabilities added		54,000			304,000
Liabilities divested or settled		(99,000	)		(52,000	)
Current period accretion expenses		189,000			12,000
Carrying amount as of December 31,	$	1,324,000		$	1,180,000

Revenue Recognition

The Company follows the “sales” (takes or cash) method of accounting for oil and natural gas revenues. Under this method, the Company recognizes revenues on oil and natural gas production as it is taken and delivered to the purchasers. The volumes sold may be more or less than the volumes the Company is entitled to take based on our ownership in the property. These differences result in a condition known as a production imbalance. Our crude oil and natural gas imbalances are insignificant.

Income Taxes

In June, 2006, an interpretation of ASC Topic 740-10, “Accounting for Uncertainty in Income Taxes” was issued. The interpretation creates a single model to address accounting for uncertainty in tax positions. Specifically, the pronouncement prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition of certain tax positions. Federal and state tax authorities generally have the right to examine and audit the previous three years of tax returns filed.

The Company accounts for income taxes pursuant to ASC Topic 740-10 "Accounting for Income Taxes" , which requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been recognized in the Company's financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities, using enacted tax rates in effect in the years in which the differences are expected to reverse. The temporary differences primarily relate to depreciation, depletion and intangible drilling costs.

Use of Estimates

The preparation of financial statements in conformity with U. S. Generally Accepted Accounting Principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Share-Based Payments

Effective January 1, 2006, the Company adopted ASC Topic 718-10, “Share-Based Payment". ASC Topic 718-10 requires compensation costs related to share-based payments to be recognized in the income statement over the requisite service period. The amount of the compensation cost is to be measured based on the grant-date fair value of the instrument issued. ASC Topic 718-10 is effective for awards granted or modified after the date of adoption and for awards granted prior to that date that have not vested. ASC Topic 718-10 does not materially change the Company's existing accounting practices or the amount of share-based compensation recognized in earnings.

Recently Issued Accounting Pronouncements

In February 2016, the FASB issued Accounting Standards Update No. 2016-02: Leases (Topic 842). The FASB issued this Update to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The accounting for Lessees relates primarily to finance leases and for operating leases. The Company does not currently have any finance or operating leases as a lessee. The accounting applied by a lessor is largely unchanged from that applied under previous GAAP. Under GAAP accounting, lessors should continue to recognize lease income for those leases on a generally straight-line basis over the lease term. The Company does lease space in its commercial office building to third-party tenants under rental lease agreements as the lessor, and recognizes lease income from tenants on a straight-line basis. The amendments in this Update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years for public business entities. The Company does not anticipate that this new guidance will have a material impact on the Company’s consolidated financial position or results of operations for the periods presented.

In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606) ("ASU 2014-09"), which supersedes nearly all existing revenue recognition guidance under existing generally accepted accounting principles. This new standard is based upon the principal that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2017.

Revenue from Contracts with Customers

Sales of oil, condensate, natural gas and natural gas liquids (“NGLs”) are recognized at the time control of the products are transferred to the customer. Based upon the Company’s current purchasers’ past experience and expertise in the market, collectability is probable, and there have not been payment issues with the Company’s purchasers over the past year or currently. Generally, the Company’s gas processing and purchase agreements indicate that the processors take control of the gas at the inlet of the plant and that control of residue gas is returned to the Company at the outlet of the plant. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs. The Company delivers oil and condensate to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product.

When sales volumes exceed the Company’s entitled share, a production imbalance occurs. If production imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. Production imbalances have not had and currently do not have a material impact on the financial statements, and this did not change with the adoption of ASC 606.

Generally, the Company’s contracts have an initial term of one year or longer but continue month to month unless written notification of termination in a specified time period is provided by either party to the contract. The Company has used the practical expedient in ASC 606 which states that the Company is not required to disclose that transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligation is not required.

Contract Balances

The Company receives purchaser statements from the majority of its customers but there are a few contracts where the Company prepares the invoice. Payment is unconditional upon receipt of the statement or invoice. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606. The majority of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and supply and demand conditions. The price of these commodities fluctuates to remain competitive with supply.

Prior Period Performance Obligations

The Company records revenue in the month production is delivered to the purchaser. Settlement statements may not be received for 30 to 90 days after the date production is delivered, and therefore the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Differences between the Company’s estimates and the actual amounts received for product sales are generally recorded in the following month that payment is received. Any differences between the Company’s revenue estimates and actual revenue received historically have not been significant. The Company has internal controls in place for its revenue estimation accrual process.

Impact of Adoption of ASC 606

The Company has completed its review of its primary oil and natural gas marketing agreements in order to assess the impact of adoption, and it has assessed that adoption of this standard will not have a material impact on the Company's financial statements because revenue will continue to be recognized as production is delivered. The Company adopted this standard in the first quarter of 2018 utilizing the modified retrospective method.

In August 2016, the FASB issued Accounting Standards Update No 2016-15: Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. The FASB issued this Accounting Standards Update to address eight specific cash flow issues with the objective of reducing the existing diversity in practice. The amendments in this Update are effective for public entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years.

Currently, there are no other new accounting pronouncements that were issued to be effective in 2018 or subsequent thereto that would have a material impact on the Company’s financial reporting.

Subsequent Events

The Company has evaluated subsequent events through the issuance date of April 1, 2019.

3. ACCOUNTS RECEIVABLE

	December 31,
	2018			2017

Trade	$	118,000		$	155,000
Accrued receivable		2,512,000			2,459,000
Qualified Intermediary		—			579,000
		2,630,000			3,193,000
Less: Allowance for losses		(15,000	)		(15,000	)
	$	2,615,000		$	3,178,000

Receivable from Qualified Intermediary is funds on deposit related to sale proceeds for which the Company is pursuing treatment under IRC Section 1031-Like Kind Exchange. These funds are released as the 180 day replacement period expires.

Accrued receivables are receivables from purchasers of oil and gas. These revenues are booked from check stub detail after receipt of the check for sales of oil and natural gas products. These payments are for sales of oil and natural gas produced in the reporting period, but for which payment has not yet been received until after the closing date of the reporting period. Therefore these sales are accrued as receivables as of the balance sheet date. Revenues for oil and natural gas production that has been sold but for which payment has not yet been received is accrued in the period sold.

4. ACCOUNTS PAYABLE

	December 31,
	2018		2017

Trade payables	$	2,166,000	$	2,139,000
Production proceeds payable		3,016,000		2,789,000
Prepaid drilling costs		675,000		680,000
	$	5,857,000	$	5,608,000

5. RELATED PARTY TRANSACTIONS

6. COMMON STOCK

Effective January 1, 2006, the Company adopted ASC Topic 718-10, "Share-Based Payment". ASC Topic 718-10 requires compensation costs related to share-based payments to be recognized in the income statement over the requisite service period. The amount of the compensation cost is to be measured based on the grant date fair value of the instrument issued. ASC Topic 718-10 is effective for awards granted or modified after the date of adoption and for awards granted prior to that date that have not vested. ASC Topic 718-10 does not materially change the Company's existing accounting practices or the amount of share-based compensation recognized in earnings.

During the three year period ending December 31, 2018, the Company did not issue any compensation related to share-based payments.

The Company has not approved nor authorized any standing repurchase program for its common stock.

During the fourth quarter of the fiscal year ended December 31, 2018, the Company made the following repurchase of its common stock:

Effective December 6, 2018, the Company repurchased 126,667 shares of its common stock as a one-time transaction for a purchase price of $269,801 or $2.13 per share.

The repurchased shares are held as Treasury Stock.

7. INCOME TAXES

The Company accounts for income taxes pursuant to ASC Topic 740-10, "Accounting for Income Taxes". ASC Topic 740-10 utilizes the liability method of computing deferred income taxes.

Income tax differed from the amounts computed by applying an effective United States federal income tax rate of 21% to pretax income in 2018, and a rate of 34% to pretax income in 2017 and 2016, as a result of the following:

	2018			2017			2016
Computed expected tax expense (benefit)	$	77,000		$	78,000		$	(671,000	)
Miscellaneous timing differences related to book and tax depletion differences and the expensing of intangible drilling costs		(233,000	)		(89,000	)		380,000
NOL Carryforward		—			(106,000	)		118,000
Gain on sale of oil and gas properties'		303,000			235,000			—
Expired and surrendered leases		—			(74,000	)		—
Correction of prior year estimate		77,000			—			—

Expected Federal income tax expense (benefit)	$	224,000		$	44,000		$	(173,000	)

Income Tax expense (benefit) for the years ended December 31, 2018, 2017, and 2016 consisted of the following:

	2018		2017		2016
Federal income taxes (benefit)	$	224,000	$	44,000	$	(173,000	)
State income taxes		—		—		—
Current income tax provision (benefit)	$	224,000	$	44,000	$	(173,000	)

Deferred income taxes reflect the effects of temporary differences between the tax bases of assets and liabilities and the reported amounts of those assets and liabilities for financial reporting purposes. Deferred income taxes also reflect the value of investment tax credits and an offsetting valuation allowance. The Company's total deferred tax assets and corresponding valuation allowance at December 31, 2018 and 2017 consisted of the following:

	December 31,
	2018			2017
Deferred tax assets
Depletion and amortization		282,000			414,000
Expired leasehold		134,000			121,000
Other, net		4,000			4,000
Depreciation		—			15,000
Total deferred tax assets		420,000			554,000

Deferred tax liabilities
Intangible drilling costs		(482,000	)		(656,000	)
Installment sale income		—			(105,000	)
Depreciation		(24,000	)		—
Total deferred tax liability		(506,000	)		(761,000	)
Net deferred income tax payable	$	(86,000	)	$	(207,000	)

On December 22, 2017, the U.S. Congress enacted the Tax Cuts and Jobs Act (the “Act”) which made significant changes to U.S. federal income tax law, including lowering the federal statutory corporate income tax rate to 21% beginning January 1, 2018. The income tax effects of changes in tax laws are recognized in the period when enacted. The Company re-measured its deferred tax balances by applying the reduced rate and recorded a provisional deferred tax expense of $189,000 during the year ended December 31, 2017. The change in the deferred tax balances due to the rate reduction has been calculated to comprise $128,000 of the $189,000 reported in the consolidated statements of operations for the year ended December 31, 2017.

The Company's estimate does not reflect effects of any state tax law changes and uncertainties regarding interpretations that may arise as a result of federal tax reform.

8. 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 the following:

	2018		2017		2016

Income taxes	$	200,000	$	130,000	$	—

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

	2018			2017			2016

Addition (Reduction) of oil & gas properties by recognitions of asset retirement obligation	$	(45,000	)	$	251,184		$	(239,000	)
	$	(45,000	)	$	251,184		$	(239,000	)


Proceeds from sales of oil and gas properties	$	965,000		$	4,767,000		$	—
Less:
Capital acquisition under IRC Section 1031		(21,000	)		(3,228,000	)		—
Qualified Intermediary accounts receivable		579,000			(579,000	)		—
Negotiated settlements		—			(26,000	)		—
	$	1,523,000		$	934,000		$	—

9. EARNINGS PER SHARE

Earnings per share ("EPS") are calculated in accordance with ASC Topic 260-10, "Earnings per Share", which was adopted in 1997 for all years presented. Basic EPS is computed by dividing income available to common shareholders by the weighted average number of common shares outstanding during the period. The adoption of ASC Topic 260-10 had no effect on previously reported EPS. Diluted EPS is computed based on the weighted number of shares outstanding, plus the additional common shares that would have been issued had the options outstanding been exercised.

10. CONCENTRATIONS OF CREDIT RISK

Deposits held in non-interest-bearing transaction accounts at the same institution are now aggregated with any interest-bearing deposits the owner may hold in the same ownership category, and the combined total insured up to at least $250,000.

As of December 31, 2018 the Company had approximately $6,997,000 in checking and money market accounts at one bank, $6,476,000 at a second bank, $849,000 and $451,000 invested at two other banks. The Company also had approximately $1,713,000 of long-term certificates of deposit invested at these banks. Cash amounts on deposit at these institutions exceeded current per account FDIC protection limits by approximately $7,914,000.

Most of the Company's business activity is located in Texas. Accounts receivable as of December 31, 2018 and 2017 are due from both individual and institutional owners of joint interests in oil and gas wells as well as purchasers of oil and natural gas. A portion of the Company's ability to collect these receivables is dependent upon revenues generated from sales of oil and natural gas produced by the related wells.

11. FINANCIAL INSTRUMENTS

The estimated fair value of the Company's financial instruments at December 31, 2018 and 2017 follows:

	2018				2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash	$	14,036,000	$	14,036,000	$	11,707,000	$	11,707,000
Restricted cash		363,000		363,000		363,000		363,000
Long-term investments		2,358,000		2,358,000		2,666,000		2,666,000
Accounts receivable		2,615,000		2,615,000		3,178,000		3,178,000

The fair value amounts for each of the financial instruments listed above approximate carrying amounts due to the short maturities of these instruments.

12. COMMITMENTS AND CONTINGENCIES

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.

At December 31, 2018 the Company has acquired bonds and letters of credit issued in favor of various state regulatory agencies as mandated by state law in order to comply with financial assurance regulations required to perform oil and gas operations within the various state jurisdictions.

The Company has seven, $5,000 single-well bonds totaling $35,000 and one $10,000 single well bond with an insurance company, for wells the Company operates in Alabama. The $5,000 bonds are written for a three year period and have expiration dates of August 1, 2019. The $10,000 bond is written for a one year period and expired February 16, 2019. Subsequent to year-end, this bond has been extended through February 16, 2020.

The Company has nine letters of credit from a bank issued for the benefit of various state regulatory agencies in Texas, New Mexico, Oklahoma, and Louisiana, ranging in amounts from $17,875 to $100,000 and totaling $363,000. These letters of credit are fully secured by funds on deposit with the bank in business money market accounts. There are seven letters of credit that automatically extend for a period of one year unless cancelled by the beneficiary and two letters of credit that automatically extend for a period of five years unless cancelled by the beneficiary.

The Company also has eight letters of credit secured with eight certificates of deposit at a second bank totaling $1,313,000. The letters of credit have expiration dates ranging from January 31, 2019 to September 30, 2020.

13. ADDITIONAL OPERATIONS AND BALANCE SHEET INFORMATION

Certain information about the Company's operations for the years ended December 31, 2018, 2017 and 2016 follows.

Dependence on Customers

Purchaser / Operator	2018			2017			2016
Sunoco Partners Marketing		18	%		18	%		12	%
Enlink Gas Marketing, LTD.		10	%		13	%		9	%
Enervest Operating, LLC		10	%		3	%		2	%
Targa Midstream Services, LLC		9	%		13	%		14	%
ETX Energy, LLC formerly New Gulf Resources		5	%		7	%		13	%
DCP Midstream, LP		4	%		3	%		3	%
Barnett Gathering, LP		4	%		1	%		0	%
ACE Gathering, Inc.		4	%		2	%		0	%
Shell Trading (US) Company		4	%		4	%		4	%
ETC Texas Pipeline, Ltd		4	%		2	%		1	%
Eastex Crude Company		3	%		7	%		10	%
Midcoast Energy Partners LP		3	%		4	%		4	%
Pruet Production Co.		3	%		3	%		3	%
Land and Natural Resources Development		2	%		0	%		0	%
Devon OEI Operating, Inc.		2	%		0	%		0	%
LPC Crude Oil Marketing LLC		2	%		3	%		3	%
Phillips 66		1	%		1	%		1	%
OXY USA, Inc.		1	%		2	%		4	%
Valero Energy Corporation		1	%		3	%		2	%
FDL Operating LLC		1	%		0	%		0	%
Enterprise Crude Oil, LLC		1	%		0	%		1	%
XTO Energy, Inc.		1	%		1	%		1	%
Empire Pipeline Corp.		1	%		1	%		1	%
Sandridge Energy, Inc.		1	%		1	%		1	%
Lucid Energy Group II (Formerly Agave Energy Co.)		1	%		2	%		0	%
Webb Energy Resources, Inc.		1	%		1	%		1	%
Range Resources Corporation		1	%		1	%		1	%
Courson Oil & Gas, Inc.		0	%		1	%		1	%
Corum Production Company		0	%		0	%		1	%
Ward Petroleum Corporation		0	%		1	%		1	%
Agave Energy Company		0	%		0	%		2	%
Linear Energy Management LLC		0	%		0	%		1	%

Oil and natural gas is sold to approximately 109 different purchasers under market sensitive, short-term contracts computed on a month to month basis.

Except as set forth above, there are no other customers of the Company that individually accounted for more than one percent (1%) of the Company's oil and gas revenues during the three years ended

December 31, 2018.

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,
	2018			2017			2016
Capitalized costs relating to oil and gas
producing activities:
Unproved properties	$	1,896,000		$	1,891,000		$	1,891,000
Proved properties		25,996,000			26,675,000			27,770,000
Total capitalized costs		27,892,000			28,566,000			29,661,000
Accumulated amortization		(24,454,000	)		(24,015,000	)		(23,557,000	)
Total capitalized costs, net	$	3,438,000			4,551,000			6,104,000

	Year Ended December 31,
	2018		2017		2016
Costs incurred in oil and gas property
acquisitions, exploration and development:
Acquisition of properties	$	354,000	$	3,629,000	$	470,000
Development costs		191,000		856,000		281,000
Total costs incurred	$	545,000	$	4,485,000	$	751,000

	Year Ended December 31,
	2018		2017		2016
Results of operations from producing activities:
Sales of oil and gas	$	5,848,000	$	4,495,000	$	3,320,000

Production costs		2,491,000		2,058,000		1,920,000
Amortization of oil and gas properties		439,000		458,000		1,038,000
Total production costs		2,930,000		2,516,000		2,958,000
Total net revenue	$	2,918,000	$	1,979,000	$	362,000

	Year Ended December 31,
	2018		2017		2016
Sales price per equivalent Mcf	$	5.16	$	4.85	$	3.76
Production costs per equivalent Mcf	$	2.20	$	2.22	$	2.17
Amortization per equivalent Mcf	$	0.39	$	0.49	$	1.17

	Year Ended December 31,
	2018		2017		2016
Results of operations from gas gathering
and equipment rental activities:
Revenue	$	136,000	$	126,000	$	114,000
Operating expenses		49,000		40,000		46,000
Depreciation		1,000		5,000		13,000
Total costs		50,000		45,000		59,000
Total net revenue	$	86,000	$	81,000	$	55,000

14. BUSINESS SEGMENTS

The Company's three business segments are (1) oil and gas exploration, acquisition, 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, 2018:

	Year Ended December 31,
	2018		2017		2016
Revenues: (1)
Oil and gas exploration, production	$	6,106,000	$	4,889,000	$	3,735,000
and operations
Gas gathering, compression and		136,000		126,000		114,000
equipment rental
Real estate rental		232,000		274,000		314,000
	$	6,474,000	$	5,289,000	$	4,163,000

	Year Ended December 31,
	2018		2017		2016
Depreciation, depletion, and
amortization expense:
Oil and gas exploration, production	$	451,000	$	461,000	$	1,043,000
and operations
Impairment of oil and gas assets		—		—		695,000
Gas gathering, compression and		1,000		13,000		13,000
equipment rental
Real estate rental		47,000		48,000		48,000
	$	499,000	$	522,000	$	1,799,000

	Year Ended December 31,
	2018			2017			2016
Income (loss) from operations:
Oil and gas exploration, production	$	2,975,000		$	2,359,000		$	40,000
and operations
Gas gathering, compression and		86,000			73,000			55,000
equipment rental
Real estate rental		(11,000	)		43,000			91,000
		3,050,000			2,475,000			186,000
Corporate and other (2)		(2,786,000	)		(2,478,000	)		(1,515,000	)
Consolidated net income (loss)	$	264,000		$	(3,000	)	$	(1,329,000	)

	Year Ended December 31,
	2018		2017		2016
Identifiable assets net of DDA:
Oil and gas exploration, production
and operations	$	3,449,000	$	4,574,000	$	6,139,000
Gas gathering, compression and
equipment rental		10,000		5,000		10,000
Real estate rental		1,323,000		1,371,000		1,418,000
		4,782,000		5,950,000		7,567,000
Corporate and other (3)		19,616,000		18,182,000		15,798,000
Consolidated total assets	$	24,398,000	$	24,132,000	$	23,365,000

Note (1): All reported revenues are from external customers.

Note (2): Corporate and other includes general and administrative expenses,

other non-operating income and expense and income taxes.

Note (3): Corporate and other includes cash, accounts and notes receivable,

inventory, other property and equipment and intangible assets.

15. SUPPLEMENTARY INCOME STATEMENT INFORMATION

The following items were charged directly to expense:

	Year Ended December 31,
	2018		2017		2016
Maintenance and repairs	$	47,000	$	38,000	$	12,000
Production taxes		242,000		154,000		127,000
Taxes, other than payroll and income taxes		14,000		11,000		8,000

16. QUARTERLY DATA (UNAUDITED)

The table below reflects selected quarterly information for the years ended December 31, 2018, 2017 and 2016.

	Year Ended December 31, 2018
		First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenue	$	1,631,000		$	2,063,000		$	1,479,000		$	1,561,000
Expense		(1,381,000	)		(1,574,000	)		(1,304,000	)		(2,108,000	)
Operating income (loss)		250,000			489,000			175,000			(547,000	)
Current tax (provision)		(66,000	)		(17,000	)		(98,000	)		(43,000	)
Deferred tax (provision) benefit		121,000			230,000			(172,000	)		(58,000	)
Net income (loss)	$	305,000		$	702,000		$	(95,000	)	$	(648,000	)
Earnings (loss) per share of
common stock
Basic and diluted	$	0.04		$	0.10		$	(0.01	)	$	(0.09	)

	Year Ended December 31, 2017
		First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenue	$	1,294,000		$	1,327,000		$	1,274,000		$	1,709,000
Expense		(1,272,000	)		(1,442,000	)		(1,317,000	)		(1,343,000	)
Operating income (loss)		22,000			(115,000	)		(43,000	)		366,000
Current tax (provision) benefit		(5,000	)		4,000			1,000			(44,000	)
Deferred tax (provision) benefit		185,000			249,000			287,000			(910,000	)
Net income (loss)	$	202,000		$	138,000		$	245,000		$	(588,000	)
Earnings (loss) per share of
common stock
Basic and diluted	$	0.03		$	0.02		$	0.04		$	(0.09	)

	Year Ended December 31, 2016
		First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenue	$	893,000		$	1,356,000		$	1,089,000		$	1,177,000
Expense		(1,345,000	)		(1,540,000	)		(1,347,000	)		(2,257,000	)
Operating (loss)		(452,000	)		(184,000	)		(258,000	)		(1,080,000	)
Current tax benefit		—			—			—			173,000
Deferred tax (provision) benefit		152,000			270,000			155,000			(105,000	)
Net income (loss)	$	(300,000	)	$	86,000		$	(103,000	)	$	(1,012,000	)
Earnings (loss) per share of
common stock
Basic and diluted	$	(0.04	)	$	0.01		$	(0.01	)	$	(0.15	)

17. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)

The Company’s net proved oil and natural gas reserves as of December 31, 2018, 2017, and 2016, have been estimated by Company personnel.

All estimates are in accordance generally accepted petroleum engineering and evaluation principles and definitions and with guidelines established by the Securities and Exchange Commission. All of the Company’s reserves are located in the United States of America and accounted for under one cost center.

Our policies and practices regarding internal control over the estimating of reserves are structured to objectively and accurately estimate our oil and natural gas reserve quantities and present values in compliance with the U.S. Securities and Exchange Commission (“SEC”) regulations and accounting principles generally accepted in the United States of America. We maintain an internal staff of petroleum engineers and geosciences professionals who work closely with the accounting and financial departments to insure the integrity, accuracy and timeliness of data used in the estimation process. The data used in our reserve estimation process is based on historical results for production, oil and natural gas prices received, lease operating expenses and development costs incurred, ownership interest and other required data. Historical oil and natural gas prices, lease operating expenses, and ownership interests are provided by and verified by the Company’s accounting department.

The Petroleum Engineer responsible for the supervision and preparation of the Company’s internally generated reserve report has a Bachelor of Science degree in Petroleum Engineering from a major university and has experience in preparing economic evaluations and reserve estimates. He meets the requirements regarding qualifications, objectivity and confidentiality set forth in the Standards Pertaining to the Engineering and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

The Company has established a written internal control procedure to verify that the data entered into our engineering evaluation software is complete and correct. These internal control procedures establish the source of the data both internally and externally, the personnel that will collect the data and testing of the data collected to ensure its accuracy.

The following reserve estimates were based on existing economic and operating conditions. Oil and natural gas prices for 2018, 2017, and 2016 were calculated using a 12-month average price, calculated as the un-weighted arithmetic average of the first-day-of-the month price for each month of each year. 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 natural gas reserves or the costs that would be incurred to obtain equivalent reserves.

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

Quantities of Proved Reserves:	Crude Oil Bbls			Natural Gas Mcf
Balance December 31, 2015		285,540			4,039,740
Sales of reserves in place		—			—
Acquired properties		65,520			118,030
Extensions and discoveries		17,150			4,670
Revisions of previous estimates *		(4,682	)		262,897
Production		(50,248	)		(582,348	)
Balance December 31, 2016		313,280			3,842,989
Sales of reserves in place		(80	)		(54,210	)
Acquired properties		24,800			3,589,330
Extensions and discoveries		630			310,000
Revisions of previous estimates *		21,392			104,975
Production		(51,082	)		(619,654	)
Balance December 30, 2017		308,940			7,173,430
Sales of reserves in place		—			—
Acquired properties		1,100			3,020
Extensions and discoveries		230			325,070
Revisions of previous estimates *		(5,634	)		222,642
Production		(43,136	)		(874,812	)
Balance December 31, 2018		261,500			6,849,350
		—			—
* May also include divestitures, not only changes in engineering.

Proved Developed Reserves:
Balance December 31, 2016		313,280			3,842,989
Balance December 30, 2017		308,940			7,173,430
Balance December 31, 2018		261,500			6,849,350

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

The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural 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 natural gas, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision.

Reserve estimates were prepared in accordance with standard Security and Exchange Commission guidelines. The future net cash flow for 2018, 2017, and 2016, was computed using a 12-month average price, calculated as the un-weighted arithmetic average of the first-day-of-the month price for each month of the year. 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. 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 57 operated wells and 72 non-operated wells. Materially insignificant operated and non-operated wells were excluded from the reserve estimate.

The Company emphasizes that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is reasonably possible that, because of changes in market conditions or the inherent imprecision of these reserve estimates, that the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of the oil and natural 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.

	Year Ended December 31,
	2018			2017			2016
Future production revenue	$	35,572,000		$	33,992,000		$	19,964,000
Future development costs		—			—			—
Future production costs		(17,830,000	)		(18,700,000	)		(10,801,000	)
Future net cash flow before Federal income taxes		17,742,000			15,292,000			9,163,000
Future income taxes		(2,661,000	)		(3,211,000	)		(2,566,000	)
Future net cash flows		15,081,000			12,081,000			6,597,000
Effect of 10% annual discounting		(4,030,000	)		(2,287,000	)		(574,000	)
Standardized measure of discounted cash flows	$	11,051,000		$	9,794,000		$	6,023,000

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

	Year Ended December 31,
	2018			2017			2016
Beginning of the year	$	9,794,000		$	6,023,000		$	7,006,000
Sales of oil and gas, net of production costs		(3,194,000	)		(2,318,000	)		(1,332,000	)
Net changes in prices and production costs		2,171,000			721,000			(662,000	)
Extensions, discoveries, additions less related costs		475,000			211,000			271,000
Development costs incurred		181,000			415,000			267,000
Net changes in future development cost		—			—			—
Revisions of previous quantity estimates		284,000			698,000			(756,000	)
Net change in purchase and sales of minerals in place		33,000			3,103,000			884,000
Accretion of discount		979,000			602,000			701,000
Net change in income taxes		(103,000	)		(250,000	)		(80,000	)
Other		431,000			589,000			(276,000	)
End of year	$	11,051,000		$	9,794,000		$	6,023,000

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DECEMBER 31, 2018, 2017, AND 2016

SCHEDULE I I

		Balance		Costs & Expenses		Deductions		Ending Balance
Allowance for doubtful accounts

December 31, 2018	$	15,000	$	—	$	—	$	15,000

December 31, 2017	$	15,000	$	—	$	—	$	15,000

December 31, 2016	$	15,000	$	—	$	—	$	15,000

SCHEDULE III

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES

REAL ESTATE AND ACCUMULATED DEPRECIATION

Initial Cost to Corporation

Total Cost

Description

Encumbrances

Land

Buildings

Subsequent
to Acquisition

Two story multi-tenant garden office building with sub-grade parking garage located in Dallas, Texas

(b)

688,000

1,298,000

282,000

Gross amounts at which carried at close of year


	Land		Buildings		Total		Accumulated Depreciation	Life on which Depreciation Calculated	Date Acquired

$	688,000	$	1,580,000	$	2,268,000	$	945,000	(a)	12/27/2004

Notes to Schedule III

(a) See Footnote 2 to the Financial Statements outlining depreciation methods and lives.

(b) None

(c) The reconciliation for investments in real estate and accumulated depreciation for the years ended December 31, 2018 are as follows


		Investments in Real Estate		Accumulated Depreciation
Balance, December 31, 2005	$	1,986,000	$	49,000
Acquisitions		210,000
Depreciation expense				71,000
Balance, December 31, 2006		2,196,000		120,000
Acquisitions		34,000
Depreciation expense				84,000
Balance, December 31, 2007		2,230,000		204,000
Acquisitions		38,000
Depreciation expense				96,000
Balance, December 31, 2008		2,268,000		300,000
Acquisitions
Depreciation expense				100,000
Balance, December 31, 2009		2,268,000		400,000
Acquisitions
Depreciation expense				101,000
Balance, December 31, 2010		2,268,000		501,000
Acquisitions
Depreciation expense				100,000
Balance, December 31, 2011		2,268,000		601,000
Acquisitions
Depreciation expense				51,000
Balance, December 31, 2012		2,268,000		652,000
Acquisitions
Depreciation expense				52,000
Balance, December 31, 2013		2,268,000		704,000
Acquisitions
Depreciation expense				52,000
Balance, December 31, 2014		2,268,000		756,000
Acquisitions
Depreciation expense				47,000
Balance, December 31, 2015		2,268,000		803,000
Acquisitions
Depreciation expense				47,000
Balance, December 31, 2016		2,268,000		850,000
Acquisitions
Depreciation expense				47,000
Balance, December 31, 2017		2,268,000		897,000
Acquisitions
Depreciation expense				48,000
Balance, December 31, 2018		2,268,000		945,000