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, ~~2022~~2023

12-31

[ ] 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	Trading Symbol(s)	Name of each exchange on which registered
Common Stock	SPND	OTC Markets - Pink

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 ] Emerging growth company [ ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

Indicate by check mark whether the registrant has filed a report on and attestation to its managements’ assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. [ ]

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. [ ]

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to Section 240.10D-1(b). [ ]

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. $2,518,200 based upon a total of 839,400 shares held as of June 30, 2023, 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,~~750~~739,~~318~~943
(Class)	(Outstanding at April 1716, ~~2023~~2024)

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; and through one of its subsidiaries, the rental of oilfield equipment; and 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~~five states including: Texas, Oklahoma, New Mexico, Louisiana, ~~Arkansas,~~ and Alabama. We operate athe majority of our projects through the drilling and production phases. Our staff has numerous years of experience in the operations area. 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 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.

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

The Company has a long history with, and extensive knowledge of, the Fort Worth Basin of Texas. Our technical staff has extensive oil and gas experience in the Fort Worth Basin, and other geological basins in which the Company has operations.

The Company ~~looks~~analyzes 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.

During periods of lower product pricing the Company cost effectively added to its reserve base through value-priced acquisitions. The Company’s 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, develop our leasehold acreage, and acquire selective additional leasehold acreage for development purposes. We are pursuing growth primarily through acquisitions of good quality producing properties, participating in drilling projects with other operators, and selective drilling and recompletion activities. Supply chain shortages along with labor shortages have caused rapidly rising costs for the Company to develop and produce our oil and natural gas reserves. We believe that it is prudent to carefully evaluate all our options and consider whether 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 projects and value priced acquisitions to the extent the economics of such projects work in the current environment. The Company's long-term focus is to grow its oil and natural gas production through a strategic combination of selected property acquisitions, divestitures, participating in drilling projects with other operators, 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. 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 and outside consultants. The Company intends to fund operations primarily from cash flow generated by its operations.

On July 26, 2021, the Company announced that its Board of Directors has initiated a review of strategic alternatives to attempt to enhance shareholder value. The strategic alternatives being considered include a possible sale of all or a material portion of assets, either in one transaction or a series of transactions, a merger of the Company or other form of business combination involving the Company and a third party, the purchase of additional assets, the outright sale of the Company, or recapitalization of the Company.

No definitive timeline exists for the process, and there can be no assurance that the results of the review process will result in a transaction or other change. It is not expected that there will be further disclosure of developments in the review process unless and until the Board of Directors has approved the specific course of action or has otherwise determined that further disclosure is appropriate or required.

Areas of Operations

The Company owns various interests in wells located in numerous 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 6857,~~092~~562 gross acres ~~under~~(12,603 net acres) under lease in the states listed below. 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)		54,~~477~~683		54,~~151~~418		46,~~650~~429		~~153~~319		1011,~~127~~112		54,~~304~~737		1419.9033	%		3237.3459	%
East Texas		3,~~200~~201		2,~~814~~755		87,~~055~~007		~~815~~749		1110,~~255~~208		3,~~629~~504		1617.5373	%		2227.1380	%
Gulf Coast Texas		40		35		~~826~~666		6056		~~866~~706		9591		1.2723	%		0.5872	%
West Texas		~~918~~80		~~881~~43		32,~~510~~364		~~228~~171		42,~~428~~444		~~1,109~~214		64.5025	%		61.7670	%
Texas Panhandle		1,760		1,216		~~800~~320		7957		2,~~560~~080		1,~~295~~273		3.7661	%		710.9010	%
Alabama		1,160		634		1,~~520~~200		7943		2,~~680~~360		~~713~~677		34.9410	%		45.3537	%
Arkansas		~~1,286~~—		~~1,141~~—		~~1,618~~880		8243		~~2,904~~880		~~1,223~~43		41.2653	%		70.4634	%
Louisiana		80		80		848		40		928		120		1.3661	%		0.7395	%
New Mexico		21,276		1,~~827~~136		~~359~~40		43		21,~~635~~316		1,~~831~~139		32.8729	%		119.1604	%
Oklahoma		240		128		2423,~~437~~958		~~324~~577		24,~~677~~198		~~452~~705		3642.2404	%		25.7659	%
Colorado		—		—		240		—		240		—		0.35	%		0.00	%
Montana		—		—		10		2		10		2		0.02	%		0.02	%
Michigan		—		—		160		5		160		5		0.23	%		0.03	%
Wyoming		—		—		1,320		98		1,320		98		2.29	%		0.78	%
Montana		—		—		10		2		10		2		0.01	%		0.01	%
Total		12,520		10,445		45,042		2,158		57,562		12,603		100.03	%		100.00	%
North Dakota		—		—		302		15		302		15		0.44	%		0.09	%
Utah		—		—		2,520		473		2,520		473		3.70	%		2.88	%
Wyoming		—		—		1,800		134		1,800		134		2.64	%		0.82	%
Total		16,437		13,907		51,655		2,493		68,092		16,400		100.00	%		100.00	%
(1) North Texas includes the Fort Worth Basin

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.

The majority of the Company’s leasehold acres 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		588,705		69.63	%
North Texas including the Fort Worth Basin & Bend Arch		213,122		51.42	%
East Texas		~~137~~109,~~785~~822		1626.3049	%
Panhandle Texas		2619,~~207~~928		34.1081	%
West Texas		1711,~~317~~662		2.0581	%
Gulf Coast Texas		21,~~150~~780		0.2543	%
Total Texas		~~772~~356,~~164~~314		9185.3396	%
Alabama		4537,~~243~~900		59.3514	%
Arkansas		~~1,573~~—		0.1900	%
Oklahoma		1319,~~645~~154		14.6162	%
New Mexico		101,~~263~~140		10.2128	%
Wyoming		~~1,997~~—		0.2400	%
Michigan		~~638~~—		0.0800	%
Total Other States		7358,~~359~~194		814.6703	%
Total		~~845~~414,~~523~~508		100.00	%

North Texas - Fort Worth Basin & Bend Arch

The Fort Worth Basin has been a focal point of the Company since its inception. Our technical personnel have numerous 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 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.

Current Activities

~~West Texas~~Arkansas

Effective ~~March 4~~3/1/2023, ~~2022,~~ the Company sold its ~~interest~~interests in anfive operated ~~oil~~gas ~~well~~wells along with ~~its~~the associated leasehold acreage, in ~~Martin~~Crawford, ~~County~~Franklin and Pope Counties, ~~Texas~~Arkansas.

North Texas

Effective January 1, 2022, the Company sold its interest in two operated natural gas wells, two shut-in wells, five non-operated natural gas wells along with its associated leasehold acreage located in Hood County, Texas, to Giant NRG Co., LP, a related entity. The terms of the transaction are no less favorable than could be obtained from unaffiliated third parties and have been approve by a majority of our Board of Directors.

Oklahoma

The Company participated in the drilling of the Jake #1H and #2 wells in Carter Co. OK. Both horizontal wells were landed in the Sycamore formation. The wells have been drilled, cased, and completed and are now in the production phase. The Company owns 0.990517% non-operated working interest and a 0.760274% revenue interest in the Jake #1H well and 1.17187% non-operated working interest and a 0.899408% revenue interest in the Jake #2H well.

The Company participated in the drilling of the Harris 3H well in Grady Co., OK. The well has been drilled, cased, and completed in the Marchand Sand and is now in the production phase. The Company owns 0.664916% non-operated working interest.

East Texas

The Company participated in the drilling of the Smead #2 well in Gregg County, Texas. The well has been drilled, cased, and awaiting completion in the Travis Peak Sands. The Company owns 25% non-operated working interest and an 18.75% revenue interest.

Oil and Natural Gas Reserves

The Company’s net proved oil and natural gas reserves have been estimated by Company personnel. (See applicable footnote 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, ~~2022~~2023, based on SEC guidelines, were classified as follows:

	Barrels of Oil		BCF Gas
Proved Developed Producing		~~157~~139,~~840~~870		41,~~126~~648
Proved Developed Non-Producing		—		—
Proved Undeveloped		—		—
Total Proved Reserves		~~157~~139,~~840~~870		41,~~126~~648

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		~~687~~274,~~693~~638	8166	%
Oil Reserves		~~157~~139,~~840~~870	1934	%
Total Reserves		~~845~~414,~~533~~508	100	%
Proved Developed Producing		~~845~~414,~~533~~508	100	%
Proved Developed Non-Producing		—	0	%
Proved Undeveloped		—	0	%
Total Proved Reserves		~~845~~414,~~533~~508	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		~~629~~243,~~883~~053	7459	%
Non-Operated Wells		~~215~~171,~~650~~455	2641	%
Total		~~845~~414,~~533~~508	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. Reserves of oil and natural gas are depleted upon extraction. The Company is always seeking to replace its oil and gas reserves.

The Company is also engaged in the gathering and marketing of natural gas through its subsidiary PPC, which owns several miles of pipeline in Texas. Natural gas is gathered for a fee. Substantially all 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.

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, 2022.6

5The 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, 2023.

Dependence on Purchasers and Operators

Purchaser / Operator	~~2022~~2023			~~2021~~2022			~~2020~~2021
Energy Transfer Crude Marketing, LLC		1417	%		014	%		0	%
Giant NRG Co., LP		12	%		0	%		0	%
Enlink Gas Marketing, LTD.		11	%		9	%		14	%
Bedrock Energy Partners		10	%		9	%		0	%
Scissor Tail Exploration and Production		8	%		0	%		0	%
Enlink Gas Marketing, LTD.		9	%		14	%		12	%
Bedrock Energy Partners		7	%		10	%		9	%
Barnett Gathering, LP		7	%		6	%		5	%
Giant Energy Co., LP		6	%		12	%		0	%
Pruet Production Co.		5	%		45	%		34	%
ETC Texas Pipeline, LTD		4	%		4	%		2	%
BKV Midstream		4	%		4	%		0	%
Eastex Crude Company		4	%		4	%		3	%
Hunt Crude Oil Supply		4	%		3	%		2	%
BKV Midstream		4	%		0	%		0	%
Territory Resources, LLC		4	%		0	%		0	%
Hunt Crude Oil Supply		3	%		2	%		6	%
Trailblazer Energy, Formerly ETX Energy, LLC		4	%		2	%		1	%
Javelin Oil & Gas		3	%		0	%		0	%
Eastex Crude Company		4	%		4	%		4	%
Phillips 66		2	%		2	%		3	%
ETC Texas Pipeline, LTD		3	%		4	%		4	%
Bedrock Production LLC		2	%		2	%		10	%
Targa Midstream Services, LLC		3	%		0	%		11	%
Producer's Midstream		2	%		02	%		0	%
IACX Roswell LLC		2	%		3	%		0	%
Oasis Transportation & Marketing Group		2	%		2	%		1	%
Oasis Transportation & Marketing Group		2	%		1	%		1	%
Bedrock Production LLC		2	%		2	%		2	%
Trailblazer formerly ETX Energy, LLC		2	%		1	%		1	%
Javelin Oil & Gas		1	%		3	%		0	%
Empire Pipeline Corp.		2	%		2	%		1	%
Phillips 66		1	%		2	%		2	%
Webb Energy Resources, Inc.		1	%		1	%		1	%
Edinger Engineering Inc.		1	%		1	%		1	%
Midcoast Energy Partners LP		1	%		4	%		2	%
DCP Midstream, LP		1	%		1	%		0	%
Land and Natural Resource Development		1	%		1	%		1	%
Eagle Ridge Operating, Inc		1	%		1	%		1	%
Empire Pipeline Corp.		1	%		2	%		2	%
OXY USA, Inc.		1	%		1	%		1	%
Montare Operating, LTD		1	%		0	%		0	%
FDL Operating LLC		0	%		2	%		2	%
Edinger Engineering Inc.		1	%		1	%		1	%
Sunoco Partners Marketing		0	%		13	%		20	%
Callon Petroleum Operating		1	%		0	%		0	%
Targa Midstream Services, LLC		0	%		11	%		11	%
DCP Midstream, LP		1	%		1	%		1	%
Peveler Pipeline, LP		0	%		6	%		4	%
IACX Roswell LLC		0	%		2	%		3	%
Valero Energy Corporation		0	%		1	%		1	%
Webb Energy Resources, Inc.		0	%		1	%		1	%
ACE Gathering, Inc.		0	%		0	%		1	%
Barnett Gathering, LP		0	%		7	%		6	%
Lion Oil Trading & Transportation		0	%		0	%		1	%
Midcoast Energy Partners LP		0	%		1	%		4	%
Enterprise Crude Oil, LLC		0	%		0	%		1	%
Eagle Ridge Operating, Inc		0	%		1	%		1	%
OXY USA, Inc.		0	%		1	%		1	%
FDL Operating LLC		0	%		0	%		2	%
Sunoco Partners Marketing		0	%		0	%		13	%
Peveler Pipeline, LP		0	%		0	%		6	%
Valero Energy Corporation		0	%		0	%		1	%

Oil and natural gas production is sold to many different purchasers/operators under market sensitive, short-term contracts.

Except as set forth above, there are no other purchasers/operators of the Company’s oil and natural gas production 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, ~~2022~~2023.

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 operated and non-operated 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. The Company may sell interests 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 landmen, 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 and Independent Contractors

As of December 31, ~~2022~~2023, the Company employed or contracted for the services of a total of approximately 4338 people. Of this total, 13 are full-time employees, and the remainder are part-time employees or independent contractors. We believe that our relationships with our employees and contractors 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.

6Other Matters

Energy Prices

As an oil and natural gas producer, we are impacted by changes in the prices for oil and natural gas. During the last three years, average United States commodity prices have fluctuated, at times drastically. Due to the many uncertainties associated with the world political and economic environment (for example, the actions of other crude oil exporting nations, including the Organization of Petroleum Exporting Countries, or the global impacts of wars or military conflicts involving such nations or regions), the global supply of, and demand for, oil and natural gas and the availability of other energy supplies, the relative competitive relationships of the various energy sources in the view of consumers and other factors, the Company is unable to predict what changes may occur in the prices of oil and natural gas in the future. For additional discussion regarding changes in oil and natural gas prices, the potential impacts on the Company and the risks that such changes may present to the Company, see ITEM 1A, Risk Factors. All of the Company’s oil and natural gas activities are subject to the risks normally incident to the exploration for, and development, production and transportation of, oil and natural gas, including rig and well explosions, loss of well control and leaks and spills, each of which could result in damage to life, property and/or the environment. The Company’s operations are also subject to certain perils, including hurricanes, tropical storms, flooding, winter storms and other adverse weather events. Moreover, our activities are subject to governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. Losses and liabilities arising from such events could reduce our revenues and increase costs to the Company to the extent not covered by insurance. Insurance is maintained by the Company against some, but not all, of these risks in accordance with what the Company believes are customary industry practices and in amounts and at costs that the Company believes to be prudent and commercially practicable.

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.

"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.

"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 drain a reservoir more adequately.

"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 unweighted 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 producibility. The area of a reservoir considered proved

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

"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,

"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.

812

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 health, economic and market risks that are beyond our control, which could adversely affect our financial results and capital requirements.

~~The~~Prices COVID-19 pandemic and the measures being taken to address and limit the spread of the virus adversely affected the economies and financial markets of the world, resulting in an economic downturn beginning in early 2020 that negatively impacted global demand and prices for ~~crude~~ oil and ~~condensate,~~ natural gas ~~liquids~~fluctuate ~~(NGLs) and natural gas~~widely. ~~The~~ ~~effects~~Among ~~of COVID-19 mitigation efforts, including~~ the ~~wide availability of vaccines, combined with the waning intensity of the pandemic,~~interrelated have resulted in increased demand and prices for crude oil and condensate. In addition, worldwide oil inventories, from a historical perspective, remain low and concerns exist with the ability of OPEC and other oil producing nations to meet forecasted future oil demand growth, with many OPEC countries not able to produce at their OPEC agreed upon quota levels due to their limited capital investments directed towards developing incremental oil supplies over the past few years. Furthermore, sanctions, import bans and price caps on Russia have been implemented by various countries in response to the war in Ukraine, further impacting global oil supply. As a result of these and other oil supply constraints, the world has experienced significant increases in energy costs. During December 2022, OPEC announced a continuation of its 2 MMBOPD production cut that started in November 2022 related to the uncertainty surrounding the global economy and future oil demand. As a result of the global supply and demand imbalances, oil and gas prices remained strong through December 2022. In addition, the ongoing pandemic, combined with the Russia/Ukraine conflict, has resulted in global supply chain disruptions, which has led to significant cost inflation and the potential for a global recession. Specifically, the Company was impacted by higher than expected inflation in steel, services and chemical prices, among other items. Global oil price levels and inflationary pressures will ultimately depend on various factors that ~~are~~can ~~beyond~~or ~~the~~could ~~Company's~~cause control, such as (i) the ability of OPEC and other oil producing nations to manage the global oil supply, (ii) the impact of sanctions and import bans on production from Russia, (iii) the timing and supply impact of any Iranian sanction relief on their ability to export oil, (iv) the effectiveness of responses by businesses and governments to combat any additional outbreaks of the COVID-19 virus and their impact on domestic and worldwide demand, (v) the global supply chain constraints associated with manufacturing and distribution delays, (vi) oilfield service demand and cost inflation, (vii) political stability of oil consuming countries and (viii) increasing expectations that the world may be heading into a global recession. The Company continues to assess and monitor the impact of these factors and consequences on the Company and its operations. Natural gas prices were robust during 2022. As a result, additional natural gas supplies oversaturated the markets causing natural gas prices to deteriorate in the first quarter of 2023. Several of the natural gas price ~~indexes~~fluctuations ~~have now dropped below $2.00 per mmbtu.~~are:

the duration and economic and financial impact of epidemics, pandemics or other public health issues, such as the COVID-19 pandemic ;

domestic and worldwide supplies of, and consumer and industrial/commercial demand for oil and natural gas;

domestic and international drilling activity;

the actions of other oil producing and exporting nations, including the Organization of Petroleum Exporting Countries;

worldwide economic conditions, geopolitical factors and political conditions, including, but not limited to, the imposition of tariffs or trade or other economic sanctions, political instability or armed conflict in oil and gas producing regions;

the availability, proximity and capacity of appropriate transportation, gathering, processing, compression, storage, and refining and export facilities;

the price and availability of, and demand for, competing energy sources, including alternative energy sources;

the effect of worldwide energy conservation measures, alternative fuel requirements and climate change-related legislation, policies, initiatives and developments.

technological advances and consumer and industrial/commercial behavior, preferences and attitudes, in each case affecting energy generation, transmission, storage and consumption.

the nature and extent of governmental regulation, including environmental and other climate change-related regulation, regulation of financial derivative transactions and hedging activities, tax laws and regulations and laws and regulations with respect to the import and export of oil, and natural gas and related commodities.

the level and effect of trading in commodity futures markets, including trading by commodity price speculators and others; and

natural disasters, weather conditions and changes in weather patterns.

The above-described factors and the volatility of commodity prices make it difficult to predict oil and natural gas prices in 2024 and thereafter. As a result, there can be no assurance that the prices for oil and/or natural gas will sustain, or increase from, their current levels, nor can there be any assurance that the prices for oil and/or natural gas will not decline. The Company continues to assess and monitor the impact of these factors and consequences on the Company and its operations.

Our cash flows, financial condition and results of operations depend to a great extent on prevailing commodity prices. Accordingly, substantial and extended declines in commodity prices can materially and adversely affect the amount of cash flows we have available for our capital expenditures and operating costs; the terms on which we can access the credit and capital markets; our results of operations; and our financial condition. As a result, the trading price of our common stock may be materially and adversely affected. Lower commodity prices can also reduce the amount of oil and natural gas that we can produce economically. Substantial and extended declines in the prices of these commodities can render uneconomic a portion of our exploration and development projects, resulting in our having to make downward adjustments to our estimated reserves and also possibly shut in or plug and abandon certain wells. In addition, significant prolonged decreases in commodity prices may cause the expected future cash flows from our properties to fall below their respective net book values, which would require us to write down the value of our properties. Such reserve write-downs and asset impairments can materially and adversely affect our results of operations and financial position and, in turn, the trading price of our common stock.

Rising inflation and other uncertainties regarding the global economy, financial environment, and global conflict 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. 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.

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 interest in one or more of its properties. Such transactions, if undertaken, could result in a reduction in the Company's operating interests or require the Company to relinquish the right to operate the property. There can be no assurance that any such transactions can be completed or that such transactions will satisfy the Company's operating capital requirements. If the Company is not successful in obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable to the Company, 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.

A negative shift in some of the public’s attitudes toward the oil and natural gas industry could adversely affect the Company’s ability to raise debt and equity capital. Certain segments of the investment community have developed negative sentiments about investing in the oil and natural gas industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain wealth funds, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and natural gas sector based on their social and environmental considerations. Certain other stakeholders have also pressured commercial and investment banks to halt financing oil and natural gas production and related infrastructure projects. Such developments, including environmental, social and governance (“ESG”) activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and natural gas companies. The Company’s stock price could be adversely affected by these developments. This may also potentially result in a reduction of available capital funding for potential development projects, impacting the Company’s future financial results.

The Company faces various risks associated with increased negative attitudes toward oil and natural gas exploration and development activities. Opposition to oil and natural gas drilling and development activities has been growing globally and is expanding in the United States. Companies in the oil and natural gas industry are often the target of efforts from both individuals and nongovernmental organizations regarding safety, human rights, climate change, environmental matters, sustainability, and business practices. Anti-development groups are working to reduce access to federal and state government lands and delay or cancel certain operations such as drilling and development along with other activities. Opposition to oil and natural gas activities could materially and adversely impact the Company’s ability to operate our business and raise capital.

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

Other factors that may affect the demand for oil and natural gas, and therefore impact our results, include technological improvements in energy efficiency; seasonal weather patterns; increased competitiveness of, or government policy support for, alternative energy sources; changes in technology that alter fuel choices, such as technological advances in energy storage that make wind and solar more competitive for power generation; changes in consumer preferences for our products, including consumer demand for alternative fueled or electric transportation or alternatives to plastic products; and broad-based changes in personal income levels.

Commodity prices and margins also vary depending on a number of factors affecting supply. For example, increased supply from the development of new oil and gas supply sources and technologies to enhance recovery from existing sources tend to reduce commodity prices to the extent such supply increases are not offset by commensurate growth in demand.

Other sections of this report may also include suggested factors that could adversely affect our business and financial performance. Moreover, we operate in an extremely 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.

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 ~~2022~~2023, ~~2021~~2022, and ~~2020~~2021. 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~~expenses, 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 several 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, ~~2022~~2023, approximately 2641% 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~~interest 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, landmen, and geologists who have considerable experience in 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 key employees. Many of our key personnel are either eligible for retirement or will become eligible in the next one to four years. The Company does not have a succession plan in place for key management and technical personnel replacements.

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 several years, with a number of employees either currently eligible to retire or becoming eligible to retire within the next one to four years. If we are 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 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, ~~2022~~2023, hold approximately 87.4155% 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. 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 members of our Board of Directors.

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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 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 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, ~~2022~~2023, 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. On December 31, ~~2022~~2023, we had working capital of $92,~~838~~776,000. 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 significantly curtail 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, ~~2022~~2023, approximately 9194% of our oil and natural gas production is currently sold to 1924 purchasers/operators on a month-to-month basis at prevailing spot market prices. Oil prices remained subject to unpredictable political and economic forces during ~~2022~~2023, ~~2021~~2022, and ~~2020~~2021, 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.

Natural gas prices plummeted in the first quarter of 2023 due to an oversupply of natural gas.

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

Our natural gas pipeline business involves several 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~~the 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 $40,000 to $~~150~~200,000 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.

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Risks that Involve the Oil and 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 the risks we face, which could result in significant financial exposure.

We maintain insurance ~~coverage~~ against ~~some~~many, but not all, ~~potential~~such losses to ~~protect~~and ~~against~~liabilities in ~~the~~accordance ~~risks~~with what we ~~face.~~believe Weare ~~may~~customary ~~elect~~industry ~~not~~practices toand ~~carry~~in ~~insurance~~amounts ifand ~~our~~at ~~management~~costs ~~believes~~ that ~~the~~we ~~cost~~believe ofto ~~insurance~~be isprudent ~~excessive~~and commercially ~~relative~~practicable. toHowever, the ~~risks~~occurrence ~~presented.~~of Ifany anof ~~event~~these ~~occurs~~events ~~that~~and isany ~~not~~losses ~~covered~~or liabilities incurred as a result of such events, if uninsured or ~~not~~in ~~fully~~excess ~~covered,~~of byour insurance coverage, itwould reduce the funds available to us for our operations and could, ~~harm~~in turn, have a material and adverse effect on our business, financial condition, and results of operations ~~and cash flows~~. In addition, we cannot fully insure against pollution and environmental risks. In the future, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums, retentions, and deductibles for our insurance policies will change over time and could escalate. In addition, some forms of insurance may become unavailable or unavailable on economically acceptable terms.

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, cybersecurity breaches, 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~~could ~~and~~be ~~information~~materially ~~technology~~and ~~systems~~adversely ~~may~~affected beby ~~vulnerable~~security threats, toincluding cybersecurity threats, and other disruptions. As an ~~attack~~oil byand ~~individuals~~gas orproducer, ~~organizations~~we ~~intending~~face various security threats, including (i) cybersecurity threats to ~~disrupt~~gain ~~our~~unauthorized ~~business~~access ~~operations~~to, ~~and~~or control of, our sensitive information ~~technology~~or to render our data or systems, ~~even~~corrupted ~~though~~or unusable; (ii) threats to the ~~Company~~security ~~has~~of ~~implemented~~our ~~policies~~facilities and infrastructure or to the security of third-party facilities and infrastructure, ~~procedures~~such as gathering, transportation, and ~~controls~~processing facilities; and (iii) threats from terrorist acts. The potential for such security threats has subjected our operations to ~~prevent~~increased risks that could have a material and ~~detect~~adverse ~~these~~effect ~~activities~~on our business. We ~~use~~rely ~~our~~extensively on information technology systems, toincluding ~~manage~~internally ~~our~~developed ~~oil~~databases, ~~and~~data ~~gas~~hosting ~~operations~~platforms, real-time data acquisition systems, third-party software, cloud services and other ~~business~~internally ~~processes.~~or ~~Disruption~~externally ofhosted ~~those~~hardware ~~systems~~and ~~could~~software ~~adversely~~platforms, ~~impact~~to (i) estimate our ~~ability~~oil toand ~~safely~~gas ~~operate~~reserves, ~~our~~(ii) ~~wells~~process and record financial and operating data, ~~operate~~(iii) ~~our~~process ~~pipelines~~and oranalyze ~~otherwise~~all ~~run~~stages of our business. ~~Accordingly~~operations, including ifdrilling, ~~such~~completion, anproduction, ~~attack~~gathering orand ~~act~~processing, oftransportation, ~~terrorism~~pipelines ~~were~~and other related activities and (iv) tocommunicate ~~occur,~~with our ~~operations~~employees and ~~financial~~vendors, ~~results~~suppliers ~~could~~and beother ~~adversely~~third ~~affected~~parties. ~~In addition~~Further, ~~we use~~ our ~~information~~reliance on technology ~~systems~~has increased due to ~~protect~~the ~~confidential~~increased oruse ~~sensitive~~of ~~employee~~personal devices and ~~Company~~remote ~~information~~communications. ~~developed~~Although we have implemented and ~~maintained~~will incontinue ~~the~~to ~~normal~~implement ~~course~~controls and ofprocedures ~~our~~that ~~business.~~are ~~Any attack~~designed onto ~~such~~protect our systems, ~~that~~identify ~~would~~and ~~result~~remediate vulnerabilities in ~~the~~our ~~unauthorized~~systems ~~release~~and related infrastructure and monitor and mitigate the risk of ~~employee,~~data orloss and other ~~confidential~~cybersecurity orthreats, ~~sensitive~~such ~~data~~measures ~~could~~cannot ~~have~~entirely aeliminate cybersecurity ~~material~~threats ~~adverse~~and ~~effect~~the oncontrols and procedures we have implemented may prove to be ineffective. Our systems and networks, and those of our business associates, ~~reputation~~may become the target of cybersecurity attacks, ~~increase~~including, ~~our~~without ~~costs~~limitation, ~~and~~denial-of-service ~~expose~~attacks; usmalicious software; data privacy breaches by employees, insiders or others with authorized access; cyber or phishing-attacks; ransomware; attempts to ~~additional~~gain unauthorized ~~material~~access ~~legal~~to ~~claims~~our data and ~~liability. If~~systems; ~~such~~and another ~~attack~~electronic orsecurity ~~act~~breaches. If any of ~~terrorism~~these security breaches were to occur, we could suffer disruptions to our normal operations, including our drilling, completion, production and ~~financial~~corporate ~~results~~functions, ~~would~~which becould materially and adversely ~~affected~~affect ~~since~~us wein ~~may~~a ~~not maintain~~variety ~~insurance~~of ~~coverage~~ways, toincluding, ~~cover~~but ~~these~~not ~~risks.~~limited to, the following:

unauthorized access to, and release of, our business data, reserve information, strategic information or other sensitive or proprietary information, which could have a material and adverse effect on our ability to compete for oil and gas resources;

data corruption, communication interruption, or other operational disruptions during our drilling activities, which could result in our failure to reach the intended target or a drilling incident;

data corruption or operational disruptions of our production-related infrastructure, which could result in loss of production or accidental discharges;

unauthorized access to, and release of, personal information of our royalty owners, employees and vendors, which could expose us to allegations that we did not sufficiently protect such information;

a cybersecurity attack on a vendor or service provider, which could result in supply chain disruptions and could delay or halt our operations;

a cybersecurity attack on third-party gathering, transportation, or processing facilities, which could result in reduced demand for our production or delay or prevent us from transporting and marketing our production, in either case resulting in a loss of revenues;

a cybersecurity attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production, resulting in a loss of revenues;

a deliberate corruption of our financial or operating data could result in events of non-compliance which could then lead to regulatory fines or penalties;

a cybersecurity attack on a communications network or power grid, which could cause operational disruptions resulting in a loss of revenues; and

a cybersecurity attack on automated and surveillance systems, which could cause a loss of production and potential environmental hazards.

Further, strategic targets, such as energy-related assets, may be at a greater risk of terrorist attacks or cybersecurity attacks than other targets in the United States. Moreover, external digital technologies control nearly all of the crude oil and natural gas distribution systems, which are necessary to transport and market our production. A cybersecurity attack directed at, for example, oil and natural gas distribution systems could (i) damage critical distribution and storage assets or the environment; (ii) disrupt energy supplies and markets, by delaying or preventing delivery of production to markets; and (iii) make it difficult or impossible to accurately account for production and settle transactions.

Any such terrorist attack or cybersecurity attack that affects us, our customers, suppliers, or others with whom we do business and/or energy-related assets could have a material adverse effect on our business, including disruption of our operations, damage to our reputation, a loss of counterparty trust, reimbursement or other costs, increased compliance costs, significant litigation exposure and legal liability or regulatory fines, penalties, or intervention. Our operations may be adversely affected by significant and widespread disruption to our systems and the infrastructure that supports our business. While we have implemented policies and procedures to try to protect against cyber-attacks, there can be no assurance that they will be effective in avoiding disruption and business impacts. Further, our insurance may not be adequate to compensate us for all resulting losses, and the cost to obtain adequate coverage may increase for us in the future and some insurance coverage may become more difficult to obtain, if available at all. Additionally, the continuing and evolving threat of cybersecurity attacks has resulted in evolving legal and compliance matters, including increased regulatory focus on prevention and new disclosure requirements recently enacted by the SEC with respect to material cybersecurity incidents and cybersecurity risk management, strategy and governance, which could make it difficult for us as a small company to meet such requirements.

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 because 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.

1324

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 the properties that we operate, we have interests in many ~~properties~~ 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

14Item 1C. Cybersecurity

The Company utilizes information technology systems throughout its business. As its reliance on information technology systems and data has increased, the Company obtained cybersecurity insurance and utilizes third party risk assessments.

Cyber Risk Management & Strategy

As part of its overall risk management system, the Company utilizes a third party to assess the Company’s processes and practices for managing and mitigating cybersecurity risks.

The Company focuses on building cybersecurity awareness with its employees and other end-users through training and security exercises and communicates the Company's expectations of employees and contractors with respect to cybersecurity matters.

The Company uses third-party cybersecurity professionals to review and assess the Company’s cybersecurity controls and procedures.

Although the Company has implemented policies and procedures to try to protect against cyber-attacks, there can be no assurance that they will be effective in avoiding disruption and business impacts. See Item 1A, Risk Factors for related discussion.

Cyber Expertise and Experience

The Company relies on third party cybersecurity professionals to provide risk assessments to help assess cybersecurity risks.

Cyber Governance & Oversight

Members of management report to the Company’s Board of Directors regarding cybersecurity matters, including the cyber risk assessments performed for the Company.

As part of its risk oversight responsibility, the Board oversees our policies and strategies for mitigating cybersecurity risks.

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,
	2022		2021		2020
	2023		2022		2021
Gas and Oil Properties, net (1)
Proved developed gas reserves-Mcf (2)
Proved developed producing		41,~~126~~648,000		54,~~184~~126,000		25,~~913~~184,000
Proved developed non-producing		—		—		—
Proved undeveloped gas reserves-Mcf (3)		—		—		—
Total proved gas reserves-Mcf		41,~~126~~648,000		54,~~184~~126,000		25,~~913~~184,000
Proved Developed Crude Oil and
Condensate reserves-Bbls (2)
Proved developed producing		~~158~~140,000		~~187~~158,000		~~145~~187,000
Proved developed non-producing		—		—		—
Proved Undeveloped crude oil and		—		—		—
Condensate reserves-Bbls (3)		—		—		—
		158,000		187,000		145,000
		140,000		158,000		187,000

(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 the footnote to the Financial Statements, Supplemental Reserve Information (Unaudited), for further explanation of the changes for ~~2020~~2021 through ~~2022~~2023.

(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 and non-operated wells at December 31, ~~2022~~2023.

Gas Wells		Oil Wells		Total Wells
Gross	Net	Gross	Net	Gross	Net
214	73.56	152	51.14	366	124.70
159	55.7	119	35.31	278	91.01

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, ~~2022~~2023. 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 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
5,658	1,925	68,092	16,399	73,750	18,324
3,120	950	54,442	11,653	57,562	12,603

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:

	2022				2021				2020
	2023				2022				2021
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells (1):
Productive		—4.000		—0.278		~~1.000~~—		~~0.200~~—		1.000		0.~~030~~200
Non-Productive		—		—		—		—		—		—
Total		—4.000		—0.278		~~1.000~~—		~~0.200~~—		1.000		0.~~030~~200
Developed Wells (2):
Productive		—		—		—		—		—		—
Non-Productive		—		—		—		—		—		—
Total		—		—		—		—		—		—
Total Exploration & Development Wells:
Productive		—4.000		—0.278		~~1.000~~—		~~0.200~~—		1.000		0.~~030~~200
Non-Productive		—		—		—		—		—		—
Total		—4.000		—0.278		~~1.000~~—		~~0.200~~—		1.000		0.~~030~~200

(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,
	2022		2021		2020		2019		2018
	2023		2022		2021		2020		2019
Oil and Gas Production, net:
Natural Gas (Mcf)		~~652~~608,~~786~~499		~~778~~652,~~462~~786		~~743~~778,~~465~~462		~~916~~743,~~456~~465		~~874~~916,~~812~~456
Crude Oil & Condensate (Bbl)		3533,~~698~~522		3335,~~604~~698		3033,~~900~~604		~~4191 9~~30,900		434,~~136~~191
Average Sales Price per Unit Produced
Natural Gas (Mcf)	$	62.4294	$	46.2342	$	14.8423	$	21.0884	$	2.8608
Crude Oil & Condensate (Bbl)	$	9274.4979	$	5692.8749	$	4156.7187	$	5541.7671	$	6255.0976
Average Production Cost per Equivalent Barrel (1) (2)	$	2016.6708	$	1220.8767	$	12.9287	$	1312.2692	$	13.1826

(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, ~~2022~~2023.

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 10,273 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 Company has noticed a decline in interest in rental inquiries for its office building since the onset of the COVID pandemic in 2020. Many companies are renting less space than previously due to an increase in remote work policies.

The building is 41 years old and although the Company replaced some of the HVAC components, such as the chiller and cooling tower for the building in 2022, the building still has its original roof, parking lot, elevator system, fan coil units, and other mechanical systems in the building, all of which need to be replaced. In addition, both of the front staircases outside the front entrance to the building have sunk and need to be replaced. The Company is in the process of obtaining bids to determine and budget for the replacement of these major building components and mechanical systems, the costs of which are likely to be significant.

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. 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, through a subsidiary, owns various natural gas compressors, pumping units, dehydrators, and various other pieces of oilfield production equipment.

Substantially all 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

On July 23, 2020, a subsidiary of the Company received notice of a lawsuit filed in Louisiana against the Company’s subsidiary and numerous other oil and gas companies alleging a pollution claim for properties operated by the defendants in Louisiana, and the Company’s subsidiary filed an answer. The Plaintiffs filed a First Supplemental and Amending Petition for Damages on January 21, 2021. The litigation is currently in the discovery phase. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of contingencies for litigation. The Company will continue to defend its subsidiary vigorously in this matter..

Item 4. Mine Safety Disclosures

Not Applicable

PART II

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 ~~2022~~2023, ~~2021~~2022, and ~~2020~~2021 as aggregated by Yahoo!.com from various OTC sources.

	Price Per Share
	High		Low
2024
First Quarter	$	3.00	$	2.81
2023
First Quarter	$	3.86	$	2.56
Second Quarter	$	3.10	$	2.73
Third Quarter	$	3.05	$	2.15
Fourth Quarter	$	3.75	$	2.51
2022
First Quarter	$	3.88	$	2.85
Second Quarter	$	3.61	$	3.05
Third Quarter	$	3.90	$	3.35
Fourth Quarter	$	3.94	$	3.00
2021
First Quarter	$	2.49	$	1.61
Second Quarter	$	2.49	$	1.63
Third Quarter	$	4.02	$	1.65
Fourth Quarter	$	4.12	$	2.62
2020
First Quarter	$	2.86	$	1.01
Second Quarter	$	1.96	$	1.05
Third Quarter	$	2.22	$	1.51
Fourth Quarter	$	2.65	$	1.52

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 on April 1716, ~~2023~~2024, common stock of the Company was held by approximately ~~535~~529 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, ~~2022~~2023, 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, ~~2017~~2018, 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 ~~fiscal~~ three-year ~~ended~~period ending December 31, ~~2020~~2023, the Company made the following ~~one-time~~ repurchase of its common stock:

Effective ~~April~~July 67, ~~2020~~2022, ~~and June 20, 2020,~~ the Company repurchased ~~45,036~~ ~~shares and 9~~5,~~248~~000 shares of its common stock from a non-controlling, unaffiliated shareholder of the Company for a negotiated purchase price of $5615,~~295~~500 ~~and $11,560 respectively,~~ or $13.2510 per share. The repurchased shares are held as Treasury Stock.

~~During~~Effective ~~the~~June ~~fiscal~~30, ~~year~~2023, ~~ended~~the ~~December~~Company 31repurchased 10,375 ~~2022~~shares of its common stock from a non-controlling, unaffiliated shareholder of the Company ~~made~~for ~~the~~a ~~following one-time~~negotiated ~~repurchase~~purchase price of ~~its~~$30,000 ~~common~~or ~~stock:~~$2.89 per share. The repurchased shares are held as Treasury Stock.

Effective July 7, 2022, the Company repurchased 5,000 shares of its common stock from a non-controlling, unaffiliated shareholder of the Company for a negotiated purchase price of $15,500 or $3.10 per share.31

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.~~[Reserved]

	For the years ended December 31,
	2022		2021		2020			2019			2018
Total Revenue	$	10,027,000	$	6,620,000	$	4,179,000		$	5,587,000		$	6,734,000
Net Income (Loss)		669,000		1,037,000		(894,000	)		(646,000	)		264,000
Earnings (Loss) per Share	$	0.10	$	0.15	($	0.13	)	($	0.09	)	$	0.04

	For the years ended December 31,
	2022		2021		2020		2019		2018
Total Assets	$	27,807,000	$	26,085,000	$	22,670,000	$	23,898,000	$	24,398,000
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.

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.

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. All the Company’s oil and gas properties are located within the United States and are accounted for in one cost center.

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, 2022.33

~~Reserve~~In ~~estimates~~order ~~are~~to ~~prepared~~test inthe ~~accordance~~cost ~~with~~center ~~standard Security and Exchange Commission guidelines. The estimated net future net cash flows for 2022~~ceiling, ~~2021,~~the ~~and~~Company ~~2020,~~prepares ~~were computed using~~ a ~~12-month average~~“Standardized ~~price,~~Measure ~~calculated as the un-weighted arithmetic average~~ of ~~the~~Discounted ~~first~~Future ~~day-of-the~~Net ~~month~~Cash ~~price~~Flows ~~for~~and ~~each~~Changes ~~month~~Therein ofRelating ~~the~~to ~~year.~~Proved ~~Lease~~Oil ~~operating costs, compression, dehydration, transportation, ad valorem taxes, severance taxes,~~ and ~~federal~~Natural ~~income~~Gas ~~taxes~~Reserves ~~were~~(Unaudited)” ~~deducted. Costs and~~as ~~prices~~of ~~were held constant and were not escalated over~~ the ~~life~~end of ~~the~~each ~~properties.~~calendar Noyear ~~deductions~~(“the ~~were~~Reserve ~~made for interest~~Report”). The ~~annual~~Company ~~discount of~~prepared ~~estimated~~its ~~future~~annual ~~cash~~Reserve ~~flows~~Report ~~is defined, for use herein,~~ as ~~future~~of ~~cash~~December ~~flows discounted at 10% per year~~31, ~~over the expected period of~~ ~~realization~~2023.

Reserve estimates are prepared in accordance with standard Security and Exchange Commission guidelines. The estimated net future net cash flows for 2023, 2022, and 2021, 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.

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, ~~2022~~2023, average quarterly crude oil prices per bbl for the Company were $7173.3444, $8371.9489, $9472.1566, and $8077.8073. respectively. During the year ended December 31, ~~2021~~2022, average quarterly crude oil prices per bbl for the Company were $4971.34, $5983.5394, $5394.5515, and $5680.8780. During the year ended December 31, ~~2020~~2021, average quarterly ~~crude~~ crude oil prices per bbl for the Company were $4549.2634, $2359.4653, $3653.4855, and $4456.9487. ~~respectively.~~

During the year ended December 31, ~~2022~~2023, average quarterly natural gas prices per ~~bbl~~mcf for the Company were $53.6770, $62.2553, $72.8149, and $52.9263 respectively. During the year ended December 31, ~~2021~~2022, average quarterly natural gas prices per mcf for the Company were $35.0767, $26.9325, $47.1581, and $45.2392. During the year ended December 31, ~~2020~~2021, average quarterly natural gas prices per mcf for the Company were $13.2607, $12.0693, $14.8815, and $24.~~20 respectively~~23.

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 impairments to our crude oil and natural gas properties in future years. 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 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. 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 to effect any acquisition.

Results of Operations

2023 Compared to 2022

Oil and natural gas revenues for the year ended December 31, 2023, were $4,502,000 compared to $7,775,000 for the year ended December 31, 2022, a decrease of $3,273,000 or 42.1%.

Oil revenue for 2023 was approximately $2,711,000 compared to $3,583,000 for 2022, a decrease of approximately $872,000 or 24.4%. Oil sales decreased to approximately 33,500 barrels from approximately 35,700 barrels in 2022, a decrease of approximately 2,200 barrels or 6.3%. Oil prices decreased to an average of $74.79 per barrel in 2023 from an average of $92.49 per barrel in 2022, a decrease of $17.70 per barrel or 19.14%.

Natural gas revenue for 2023 was approximately $1,791,000 compared to $4,192,000 for 2022, a decrease of approximately $2,401,000 or 57.3%. Natural gas sales were approximately 608,500 mcf in 2023 from approximately 653,000 mcf in 2022, a decrease of approximately 44,500 mcf or 6.8%. Natural gas prices decreased to an average of $2.94 per mcf in 2023 a decrease of $3.48 or 54.2% from an average of $6.42 per mcf in 2022.

In general, revenues from oil and natural gas producing operations experienced a significant decrease for the year ending December 31, 2023, as compared to the same period in 2022. These decreases resulted in part from decreased oil and natural gas prices, as well as decreases in oil and natural gas production.

Revenue from lease operations was approximately $156,000 for 2023, compared to approximately $183,000 in 2022, a decrease of approximately $27,000 or 14.8%. 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 2023 were approximately $120,000, an increase of approximately $31,000 or 34.8% from approximately $89,000 in 2022. This increase is due primarily to the addition of two new rental compressors during 2023.

Real estate rental revenue for 2023 was approximately $270,000, an increase of approximately $25,000 or 10.2% from approximately $245,000 in 2022. This increase was due to a new tenant rent for a full year in 2023 and due to rental rate increases.

Interest income for 2023 was approximately $761,000, an increase of $619,000 from $142,000 in 2022. Interest income is derived from investments in both short-term and long-term certificates of deposit as well as money market accounts at banks. This increase is primarily due to the overall general increase in interest rates during 2023.

Miscellaneous revenue for 2023 was $57,000, as compared to $62,000 in 2022, a decrease of $5,000 or 8.1%.

Lease operating expenses 2023 were $1,469,000 as compared to $2,120,000 in 2022, a net decrease of approximately $651,000, or 30.7%. 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 represented approximately 33% of the total 2023 amount with the remaining representing net increases and decreases on various operated properties due to general service cost fluctuations and levels of operational activity.

Production taxes, gathering, and marketing expenses for 2023 were approximately $701,000 compared to $867,000 in 2022, a decrease of approximately $166,000, or 19.2%. These expenses relate directly to the overall decrease in crude oil and natural gas production and revenues.

Pipeline and rental expenses for 2023 were approximately $54,000 compared to approximately $21,000 for 2022, an increase of approximately $33,000, or 157.1%. Approximately $19,000 of this amount was for an increase of pipeline maintenance over 2022, and approximately $14,000 is due to increased compressor maintenance for the same period.

Real estate expenses in 2023 were approximately $161,000 compared to $174,000 during the same period in 2022, a decrease of approximately $13,000 or 7.5%.

Depreciation and amortization expense for 2023 was $229,000 compared to $74,000 for 2022, an increase of approximately $155,000 or 209.6%. Amortization of the full cost pool for crude oil and natural gas assets for 2023 was $134,000, as compared to no amortization for the year 2022, an increase of $134,000. The Company re-evaluated its proved oil and gas reserves as of December 31, 2023, and decreased its estimated total proved reserves by approximately 431,000 BOE to 415,000 BOE at the end of 2023 compared to 846,000 BOE at the end of 2022, a decrease of approximately 51.0%. The net decrease in the unamortized full cost pool base, is due primarily to credits to the full cost pool from the sale of properties during 2022 in accordance with full cost accounting procedures and the related reduction of liabilities in the recalculation of the Asset Retirement Obligation. (See Footnote 17 to the Financial Statements).

Asset Retirement Obligation (“ARO”) accretion expense for 2023 was $509,000 down from $2,014,000 in 2022, a decrease of $1,505,000. The ARO calculation is an estimate 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 interests in existing wells. This estimated future plugging 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. In view of increasing plugging costs and regulatory agencies putting pressure on operators to plug and abandon wells faster than in prior years, management evaluated this year’s provision and estimated that the liability to plug and abandon its wells in the future, should be increased.

General and administrative expenses for 2023 were approximately $2,970,000 as compared to approximately $3,126,000 for 2022, a decrease of approximately $156,000 or 5.0%. A portion of the decrease between years is the result of a bad debt expense relating to a third-party working interest owner written off in 2022, leaving an overall increase of approximately $14,000 between years.

2022 Compared to 2021

Oil and natural gas revenues for the year ended December 31, 2022, were $7,775,000 compared to $5,466,000 for the year ended December 31, 2021, an increase of $2,309,000 or 42.2%.

Oil revenue for 2022 was approximately $3,583,000 compared to $2,177,000 for 2021, an increase of approximately $1,406,000 or 64.58%. Oil prices increased to an average of $92.49 per barrel in 2022 from an average of $56.87 per barrel in 2021, an increase of $35.62 per barrel or 62.6%. Oil sales increased to approximately 35,700 barrels from approximately 33,600 barrels in 2021, an increase of 2,100 barrels or 6.3%.

Natural gas revenue for 2022 was approximately $4,192,000 compared to $3,289,000 for 2021, an increase of approximately $903,000 or 27.49%. Natural gas sales were approximately 653,000 mcf in 2022 from approximately 778,500 mcf in 2021, a decrease of approximately 125,500 mcf or 16.1%. Natural gas prices increased to an average of $6.42 per mcf in 2022 an increase of $2.19 or 51.8% from an average of $4.23 per mcf in 2021.

In general, revenues from oil and natural gas producing operations experienced a significant increase for the year ended December 31, 2022, as compared to the same period in 2021. These increases resulted in part from increased oil and natural gas prices, as well as oil production increases.

Revenue from lease operations was approximately $183,000 for 2022, compared to approximately $219,000 in 2021, a decrease of approximately $36,000 or 16.4%. 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 2022 were approximately $89,000, a decrease of approximately $10,000 or 10.1% from approximately $99,000 in 2021.

Real estate rental revenue for 2022 was approximately $245,000, an increase of approximately $5,000 or 2.1% from approximately $240,000 in 2021.

Interest income for 2022 was approximately $142,000, a decrease of approximately $7,000 from approximately $149,000 in 2021 or 4.7%. Interest income is derived from investments in both short-term and long-term certificates of deposit as well as money market accounts at banks.

Debt forgiveness income. On March 18, 2021, the Company received funding of a loan pursuant to the Paycheck Protection Program (“PPP”) under the Coronavirus Aid, Relief and Economic Security Act, enacted March 27, 2020, in the amount of $403,572. In December 2021, the Company received notification that the Small Business Administration authorized full forgiveness of the PPP loan. The amount of the loan which was fully forgiven is recorded as debt forgiveness income.

~~Other~~Miscellaneous revenue for 2022 was $62,000, as compared to $44,000 in 2021, an increase of $18,000 or 40.9%.

Lease operating expenses 2022 were $2,120,000 as compared to $1,207,000 in 2021, a net increase of approximately $913,000, or 75.6%. 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 represented approximately 25% of the total 2022 amount with the remaining representing net increases and decreases on various operated properties due to general service cost fluctuations and levels of operational activity.

Production taxes, gathering, and marketing expenses for 2022 were approximately $867,000 compared to $896,000 in 2021, a decrease of approximately $29,000, or 3.2%.

Pipeline and rental expenses for 2022 were approximately $21,000 compared to approximately $17,000 for 2021, an increase of approximately $4,000, or 23.5%.

Real estate expenses in 2022 were approximately $174,000 compared to $167,000 during the same period in 2021, an increase of approximately $7,000 or 4.2%.

Depreciation and amortization expense for 2022 was $74,000 compared to $121,000 for 2021, a decrease of approximately $74,000 or 34.8%. There was no amortization of the full cost pool of oil and natural gas assets for 2022 as compared to $63,000 for the year ended 2021, a decrease of approximately $63,000 or 84.0%. The Company re-evaluated its proved oil and gas reserves as of December 31, 2022, and decreased its estimated total proved reserves by approximately 205,000 BOE to 846,000 BOE at the end of 2022 compared to 1,051,000 BOE at the end of 2021, a decrease of approximately 19.6%. The net decrease in the unamortized full cost pool base, is due primarily to credits to the full cost pool from the sale properties during 2022 in accordance with full cost accounting procedures and the related reduction of liabilities in the recalculation of the Asset Retirement Obligation. (See Footnote 17 to the Financial Statements).

Asset Retirement Obligation (“ARO”) accretion expense for 2022 was $2,014,000 up from $572,000 in 2021, an increase of $1,442,000. 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 interests in existing wells. This estimated future plugging 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. In view of increasing plugging costs and regulatory agencies putting pressure on operators to plug and abandon wells faster than in prior years, management evaluated this year’s provision and estimated that the liability to plug and abandon its wells in the future, should be increased.

General and administrative expenses for 2022 were approximately $3,126,000 as compared to approximately $2,685,000 for 2021, an increase of approximately $441,000 or 16.4%. Approximately $218,000 is attributed to increases in personnel salaries and benefits. In addition, $170,000 of bad debt expense relating to a third party working interest owner was written off.

2021 Compared to 2020

Oil and natural gas revenues for the year ended December 31, 2021, were $5,466,000 compared to $2,924,000 for the year ended December 31, 2020, an increase of $2,542,000 or 86.9%.

Oil revenue for 2021 was approximately $2,177,000 compared to $1,552,000 for 2020, an increase of approximately $625,000 or 40.3%. Oil prices increased to an average of $56.87 per barrel in 2021 from an average of $41.71 per barrel in 2020, an increase of $15.16 per barrel or 36.5%. Oil sales increased to 33,600 barrels from approximately 30,900 barrels in 2020, an increase of 2,700 barrels or 8.7%.

Natural gas revenue for 2021 was approximately $3,289,000 compared to $1,372,000 for 2020, an increase of approximately $1,917,000 or 139.7%. Natural gas sales increased to approximately 778,500 mcf in 2021 from approximately 743,000 mcf in 2020, an increase of approximately 35,500 mcf or 4.8%. Natural gas prices increased to an average of $4.23 per mcf in 2021 an increase of $2.39 or 129.9% from an average of $1.84 per mcf in 2020.

In general, revenues from oil and natural gas producing operations experienced a significant increase for the year ended December 31, 2021, as compared to the same period in 2020. These increases resulted in part from increased oil and natural gas prices, as well as production increases. A significant number of both operated and non-operated wells were shut-in during 2020 due to historic low oil and natural gas prices and most of these wells were returned to production in 2021 and were producing at December 31, 2021.

Revenue from lease operations was approximately $219,000 for 2021, compared to approximately $233,000 in 2020, a decrease of approximately $14,000 or 6.0%. 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 2021 were approximately $99,000, an increase of approximately $10,000 or 11.2% from approximately $89,000 in 2020. The increase was due primarily to an increase in natural gas volume sold through PPC.

Real estate rental revenue for 2021 was approximately $240,000, a decrease of approximately 32,000 or 11.7% from approximately $272,000 in 2020. The decrease was due to lease re-negotiations and the loss of tenants.

Interest income for 2021 was approximately $149,000, a decrease of approximately $67,000 from approximately $216,000 in 2020 or 31.0%. Interest income is derived from investments in both short-term and long-term certificates of deposit as well as money market accounts at banks.

Other revenue for 2021 was $44,000, as compared to $42,000 in 2020, an increase of $2,000 or 4.8%.

Lease operating expenses 2021 were $1,207,000 as compared to $1,324,000 in 2020, a net decrease of approximately $117,000, or 8.8%. 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 $95,000. The remaining decrease of approximately $22,000 represents net increases and decreases on various operated properties due to general price fluctuations and levels of operation activity.

Production taxes, gathering, and marketing expenses for 2021 were approximately $896,000 compared to $675,000 in 2020, an increase of approximately $221,000, or 32.7%. This increase was directly related to the increase in oil and natural gas production and revenues.

Pipeline and rental expenses for 2021 were approximately $17,000 compared to approximately $9,000 for 2020, an increase of approximately $8,000, or 88.9%. The increase is primarily due to repair and maintenance expenses in 2021 as compared to 2020.

Real estate expenses in 2021 were approximately $167,000 compared to $174,000 during the same period in 2020, a decrease of approximately $7,000 or 4.0%.

Depreciation and amortization expense for 2021 was $121,000 compared to $452,000 for 2020, a decrease of approximately $331,000 or 73.2%. Amortization of the full cost pool of oil and natural gas assets for 2021 was approximately $63,000 compared to $393,000 for the year ended 2020, a decrease of approximately $330,000 or 84.0%. The Company re-evaluated its proved oil and gas reserves as of December 31, 2021, and increased its estimated total proved reserves by approximately 421,000 BOE to 1,051,000 BOE at the end of 2021 compared to 630,000 BOE at the end of 2020, an increase of approximately 66.8%. Sales of oil and natural gas products during 2021 increased by approximately 8,000 BOE from approximately 155,000 BOE in 2020 to approximately 163,000 BOE in 2021, an increase of 5.1%. (See Footnote 17 to the Financial Statements). This resulted in a decrease in the depletion rate factor from 19.722% in 2020 on an unamortized full cost pool base of $1,994,000 to a depletion rate factor of 13.107% on an unamortized full cost pool base of $477,000 in 2021. The net decrease in the unamortized full cost pool base of $1,517,000 is due primarily to a credit to the full cost pool of approximately $1,511,000 from the sale properties during 2021 in accordance with full cost accounting procedures.

Asset Retirement Obligation (“ARO”) accretion expense for 2021 was $572,000 up from $139,000 in 2020, an increase of $433,000 or 311.5%. 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 interests in existing wells. This estimated future plugging 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 2021 were approximately $2,685,000 as compared to approximately $2,640,000 for 2020, an increase of approximately $45,000 or 1.7%.

Item 8. Consolidated Financial Statements and

Schedules Index at Page 46

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~~invherent 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, ~~2022~~2023. 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, ~~2022~~2023.

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~~ control over financial reporting. There were no changes in our internal controls over financial reporting (as such term is defined in ~~Exchange~~ Exchange Act Rule 13a-15(f)) that occurred during the quarter ended December 31, ~~2022~~2023, that have materially affected, or are reasonably ~~likely~~ likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

Not Applicable

PART III

Item 10. Directors, Executive Officers, and Corporate Governance

The Directors and Executive Officers of the Company and certain information concerning them is set forth below:
Name	Age	Position
Chris G. Mazzini	6566	Chairman of the Board, Director, and President
Michelle H. Mazzini	6162	Director, Vice President, Secretary, and Treasurer
Ted R. Munselle	6768	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.

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 Master of Science in Management and Administrative Sciences from the University of Texas at Dallas in 1990. In January of 1987, he took a position with the Dallas office of the Federal Bureau of Investigation. After a year with the Bureau, he accepted a position with the Internal Revenue Service as a Revenue Agent. Fifteen of his eighteen years with the Service were spent in the Large and Mid-Sized Business unit auditing tax returns of the largest business entities.

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

Family Relationships

Michelle Mazzini, Vice President, Secretary, 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, Committees, and Corporate Governance

The Board of Directors met one time in ~~2022~~2023. 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 ~~2022~~2023, Mr. Munselle was Chairman of the Audit Committee. Mr. Munselle is qualified as an “audit committee financial expert” within the meaning of SEC Regulations.

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 $~~526~~517,~~245~~396, $~~501~~526,~~431~~245, and $~~404~~501,~~447~~431 was paid to Mr. Mazzini in ~~2022~~2023, ~~2021~~2022, and ~~2020~~2021 respectively. Cash compensation including salaries and bonuses of $~~426~~416,223, $~~392~~426,~~230~~223, and $~~332~~392,~~898~~230 was paid to Ms. Mazzini in ~~2022~~2023, ~~2021~~2022, and ~~2020~~2021 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 projects 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 a program, and the frequency and amounts are largely controlled by the economics of each project. 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 ~~2022~~2023, $10,000 in ~~2021~~2022 and $10,000 in ~~2020~~2021 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 1716, ~~2023~~2024 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	)		87.4155	%
12850 Spurling Rd., Suite 200
Dallas, Texas 75230
All officers and directors as a group		5,900,543					87.4155	%

* “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,~~750~~739,~~318~~943 shares of Common Stock outstanding on April 1716, ~~2023~~2024.

(1) Chris Mazzini directly owns 39,654 shares (0.~~5874~~5883%). Giant Energy Corp. directly owns 5,860,889 shares (86.~~8240~~9675%). 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.

2442

Transactions with Management and Others

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

Certain Business Relationships

Certain officers, directors, and related parties including entities controlled by officers of the Company, engage in business transactions with the Company which were not the result of arms-length negotiations between independent parties. Accounts receivable and accounts payable contain $78,000 and $215,000, respectively, for the year ended December 31, 2022, relating to these transactions. Amounts for the year ended December 31, ~~2021~~2023 and 2022, were not material.

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; this agreement was terminated in 2021. On October 1, 2008, the Company entered into a similar agreement with Giant NRG Co., LP (“NRG”) a limited partnership with Chris Mazzini and Michelle Mazzini as limited partners. Under this agreement NRG pays a monthly fee of $1,500.00 to the Company in exchange for the Company providing certain administrative services to NRG. The Company has entered into a similar arrangement with Peveler Pipeline, LP ("Peveler"), whereby Peveler pays the Company a monthly charge of $250.00 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 $500.00 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 $350.00 for certain administrative services that the Company provides to Reserve. See also Footnote 5 to the Financial Statements.

partners. Under this agreement NRG pays a monthly fee of $1,500.00 to the Company in exchange for the Company providing certain administrative services to NRG. The Company has entered into a similar arrangement with Peveler Pipeline, LP ("Peveler"), whereby Peveler pays the Company a monthly charge of $250.00 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 $500.00 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 $350.00 for certain administrative services that the Company provides to Reserve. See also Footnote 5 to the Financial Statements.

During the year ended December 31, 2022, the Company sold four properties to a related party for a sales price of $563,000 with the offset being an adjustment to the full cost pool. No gain or loss was recognized related to this transaction.

During the fourth quarter of ~~2021~~2022, the Company participated in the ~~completion~~drilling of the ~~Howe~~Smead Heirs #1H2 well located in ~~the~~Gregg ~~Normangee East block of Madison~~ County, Texas, operated by Giant NRG Co., LP, a related entity.

During the fourth quarter of 2022, the Company participated in the drilling of the Smead Heirs #2 well located in Gregg County, Texas, operated by Giant NRG Co. LP, a related entity.x

Director Independence

Although the Company is not a listed issuer, the Board of Directors has determined to utilize a definition of independence from the NYSE American exchange standard. Utilizing that standard, the Board of Directors, which consists of only three individuals, two of whom are also executive officers of the Company, has determined that Director Ted R. Munselle, is “independent”, utilizing the standards of the NYSE American exchange.

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 ~~2022~~2023 and ~~2021~~2022 by accounting firm, Farmer, Fuqua, & Huff, P.C.

Type of Fees	~~2022~~2023		~~2021~~2022
Audit Fees	$	5749,~~955~~500	$	4557,~~500~~995
Audit Related Fees		—821		—
Tax Fees		1215,~~000~~750		—12,000
All other fees		—		—

Members of the Board of Directors (the "Board") fulfill the responsibilities of an audit committee and have established policies and Procedures for the 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 ~~2022~~2023 and ~~2021~~2022 were pre-approved by the Board or were within the pre-approved guidelines for permitted non-audit services and fees established by the Board, and there were no instances of waiver of approved requirements or guidelines during the same periods.

2544

PART IV

Item 15. Exhibits and Financial Statement Schedules

The following documents are filed as a part of this report:
(1) FINANCIAL STATEMENTS: The following financial statements of the Registrant and Report of Independent Registered Public Accounting Firm therein are filed as part of this Report on Form 10-K:
			Page
Report of Farmer, Fuqua & Huff, P.C Independent Registered Public Accounting Firm			29-30
Consolidated Balance Sheets			31-32
Consolidated Statements of Operations			33
Consolidated Statements of Changes in Stockholders' Equity			34
Consolidated Statements of Cash Flows			35
Notes to Consolidated Financial Statements			36
(2) FINANCIAL STATEMENT SCHEDULES:
Schedule II - Valuation and Qualifying Accounts			49
Schedule III - Real Estate and Accumulated Depreciation			50
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.

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	49-51
	Consolidated Balance Sheets	52-53
	Consolidated Statements of Operations	54
	Consolidated Statements of Changes in Stockholders' Equity	55
	Consolidated Statements of Cash Flows	56
	Notes to Consolidated Financial Statements	57


	(2) FINANCIAL STATEMENT SCHEDULES:

	Schedule II - Valuation and Qualifying Accounts	74
	Schedule III - Real Estate and Accumulated Depreciation	75


	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 46 of this Report.

(c) The Index to Consolidated Financial Statements and Supplemental Schedules is included following the signatures, beginning at page 49 of this Report.

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

Item 16. Form 10-K Summary

Optional and not included herein.

2646

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 have been signed in its behalf by the undersigned, thereunto duly authorized.
SPINDLETOP OIL & GAS CO.
Date: April 17, 2023
Date: April 16, 2024
	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 1716, ~~2023~~2024
Chris Mazzini	(Chief Executive Officer
/s/ Michelle Mazzini
	Vice President, Secretary,	April 1716, ~~2023~~2024
Michelle Mazzini	Treasurer, Director
/s/ Ted R. Munselle
	Director	April 1716, ~~2023~~2024
Ted R. Munselle
/s/ Robert E. Corbin	Principal Financial Officer	April 1716, ~~2023~~2024
	and Accounting Manager
Robert E. Corbin

2747

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
Index to Consolidated Financial Statements and Schedules
	Page	~~Page~~
Report of Independent Registered Public Accounting Firm	49-51	~~29-30~~
Consolidated Balance Sheets - December 31, 2022, and 2021		31-32
Consolidated Balance Sheets - December 31, 2023 and 2022	52-53
Consolidated Statements of Operations for the Years Ended
Consolidated Statements of Operations for the years ended
December 31, 2022, 2021 and 2020		33
December 31, 2023, 2022 and 2021	54
Consolidated Statements of Changes in Shareholders' Equity
for the Years Ended December 31, 2022, 2021 and 2020		34
for the years ended December 31, 2023, 2022 and 2021	55
Consolidated Statements of Cash Flows
for the Years Ended December 31, 2022, 2021 and 2020		35
for the years ended December 31, 2023, 2022 and 2021	56
Notes to Consolidated Financial Statements	57	36
Schedules for the Years Ended December 31, 2022, 2021 and 2020
Schedules for the years ended December 31, 2023, 2022 and 2021
II - Valuation and Qualifying Accounts	74	49
III - Real Estate and Accumulated Depreciation	75	50
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.

2848

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, ~~2022~~2023 and ~~2021~~2022, 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, ~~2022~~2023, and the related notes and schedules (collectively referred to as the “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, ~~2022~~2023 and ~~2021~~2022, and the results of operations and its cash flows for each of the three years in the period ended December 31, ~~2022~~2023, 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.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which they relate.

~~Gain on sale of oil and gas property~~49

As discussed in Note 2 to the consolidated financial statements, the Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under full cost method of accounting, gains and losses are treated as adjustments to the capitalized costs unless such adjustment would significantly alter the relationship between capitalized costs and proved oil and gas reserves attributed to a cost center. Significant judgment is required to determine whether adjustment to capitalized costs would result in significant alteration. When it is determined that a gain or loss should be recognized on such a sale, total capitalized costs within the cost center are allocated between the reserves sold and those retained. The allocation of capitalized costs should be allocated on the basis of the relative fair values of the properties. During the year ended December 31, 2022, the Company sold a property for approximately $1,531,000. At the recognition of the sale, the Company’s unamortized capitalized costs for its only cost center were approximately $319,000 and at December 31, 2022 were fully amortized. The most recent reserve report at the time of the sale contained no reserves related to this property. The Company determined that an adjustment to capitalized costs would result in a significant alteration between properties sold and those retained and as such recognized a gain on sale of the property.

We identified the recognition of a gain on the sale of an oil and gas property under the full cost method of accounting as a critical audit matter. Significant judgment is required to determine whether to recognize a gain on the sale of a property when the Company follows the full cost method of accounting.

The following are the primary procedures we performed to address this critical audit matter. We obtained an understanding of the internal controls over the Company’s procedures for accounting for significant transactions. We examined the executed purchase and sale agreement agreeing the property description and the sales amount. We examined the executed assignment and bill of sale as filed with the country in which the property is located. We reviewed the journal entry recording the sale and recognition of the gain and vouched the receipt of the proceeds to the Company’s bank. We determined that the Company’s most recent reserve report at the sale of the property did not include any reserves for the property and that the unamortized capital costs at the recording of the sale were approximately $319,000 and $-0- at December 31, 2022.

Accounting for asset retirement obligations

At December 31, ~~2022~~2023, the asset retirement obligation (ARO) balance totaled $34,~~654~~414,000. As further described in Note 2, the Company’s ARO primarily represents the estimated present value of the amount the Company will incur to plug, abandon, and remediate producing properties at the end of their productive lives, in accordance with applicable state laws. The Company determined its asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The asset retirement obligation is recorded as a liability at its estimated present value at its inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the statement of operations.

The Company’s liability is determined using significant assumptions, including current estimates of plugging and abandonment costs and the productive life of wells. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the varying estimated lengths of the lives of the Company’s wells, the costs to ultimately retire the wells may vary significantly from previous estimates.

We determined the accounting for the asset retirement obligation as a critical audit matter as the calculation of the ARO is complex and highly judgmental because of the significant estimation by management in determining the obligation. In particular, the estimate was sensitive to significant subjective assumptions such as retirement cost estimates and the estimated timing of settlements which are both affected by expectations about future market and economic conditions.

We obtained an understanding of the Company’s internal controls over its ARO estimation process, including management’s review of the significant assumptions that have a material effect on the determination of the obligations. Our audit procedures included, among others, assessing the significant assumptions and inputs used in the valuation, such as retirement cost estimates and timing of settlement assumptions. Additionally, we compared the ARO against historical results, reviewed the reasonableness of the discount rate utilized in the estimate, and considered the completeness of the properties included in the estimate by comparing to the Company’s reserve report.

2950

Estimated proved reserves of oil and natural gas

~~The~~As discussed in Note 2, the Company uses the full cost method of accounting for its investment in oil and natural gas properties. The Company’s proved oil and natural gas properties are amortized using the units of production method and are evaluated for impairment by the full cost ceiling impairment test utilizing the Company’s oil and natural gas reserves in accordance with accounting principles generally accepted in the United States and SEC guidelines. The Company’s capitalized costs were fully amortized at December 31, 2022 and no amortization or impairment was recorded for the year ending December 31, 2022. The Company’s internal reserve engineer prepares the reserve report. Estimates of economically recoverable oil and natural gas properties depend upon a number of factors and assumptions, including quantities of oil and natural gas that are ultimately recovered, the timing of the recovery of oil and natural gas reserves, the operating costs incurred, the amount of future development expenditures, and the price received for the production. The methodology used to prepare the report is in conformity with SEC guidelines. Information contained in the reserve report is used in the calculation of the asset retirement obligation. Estimated oil and natural gas reserves represent potential future revenue through production or sale of properties.

At December 31, 2023, the Company’s capitalized costs in the full cost pool were $411,000, net of amortization. The Company recorded amortization of $134,000 and no full-cost ceiling impairment was necessary. The Company reported a reserve value of $6,894,000 and $4,819,000, gross and net, respectively, of oil and natural gas properties as of December 31, 2023. The Company’s internal reserve engineer prepares the reserve report. Estimates of economically recoverable oil and natural gas properties depend on a number of factors and assumptions, including quantities of oil and natural gas that are ultimately recovered, the timing of the recovery of oil and natural gas reserves, the operating costs incurred, the amount of future development expenditures, and the price received for the production. The methodology used to prepare the report is in conformity with SEC guidelines. Information contained in the reserve report is used in the calculation of the asset retirement obligation. Estimated oil and natural gas reserves represent potential future revenue through production or sale of properties.

We identified the estimation of proved oil and nature gas reserves as a critical audit matter. There is a high degree of subjectivity in evaluating the estimate of proved oil and natural gas reserves, as auditor judgment was required to evaluate the assumptions used by the Company related to determining the value and quantity of future oil and gas reserves.

The following are the primary procedures we performed to address this critical audit matter. We obtained an understanding of the internal controls over the Company’s processes for providing information to the internal reserve engineer and his processes for preparing the reserve report. We evaluated (1) the professional qualifications of the Company’s internal reserve engineer and (2) the knowledge, skill, and ability of the Company’s internal reserve engineer. We assessed the methodology used by the Company to estimate the reserves for consistency with industry and regulatory standards and obtained confirmation from the internal reserve engineer. We tested the current year pricing, production, and expenses used in the preparation of the reserve report. InWe ~~addition, we~~ performed a retrospective review of the prior year reserve report. We analyzed the amortization expense calculation for compliance with industry and regulatory standards and recalculated it. We also analyzed the ceiling test impairment calculation for compliance with industry and regulatory standards. In addition, we performed an independent calculation of the ceiling test impairment calculation and compared our results with the Company’s results.

Supplemental Information

The supplemental information contained in Schedules II and III has been subjected to audit procedures performed in conjunction with the audit of the Company’s consolidated financial statements. The supplemental information is the responsibility of the Company’s management. Our audit procedures included determining whether the supplemental information reconciles to the consolidated financial statements or underlying accounting and other records, as applicable, and performing procedures to test the completeness and accuracy of the information presented in the supplemental information. In forming our opinion on the supplemental information, we evaluated whether the supplemental information, including its form and content, is presented in conformity with the Security and Exchange Commission’s rules. In our opinion, the supplemental information is fairly stated, in all material respects, in relation to the consolidated financial statements as a whole.

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

Richardson, Texas

April 1716, ~~2023~~2024

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.

782

3051

SPINDLETOP OIL & GAS Co. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

		December 31,			December 31,
		2022			2021
		2023			2022
ASSETS
Current Assets
Cash and cash equivalents	$	136,~~597~~868,000		$	1013,~~673~~597,000
Restricted cash		270,000			~~370~~270,000
Accounts receivable		2,~~200~~090,000			32,~~104~~200,000
Income tax receivable		~~630~~90,000			~~450~~630,000
Total Current Assets		169,~~697~~318,000			1416,~~597~~697,000
Property and Equipment - at cost
Oil and gas properties (full cost method)		2526,~~321~~087,000			2625,~~305~~321,000
Rental equipment		~~412~~465,000			412,000
Gas gathering system		115,000			115,000
Other property and equipment		~~395~~479,000			~~317~~395,000
		26,243,000			27,149,000
		27,146,000			26,243,000
Accumulated depreciation and amortization		(26,~~140~~300,000	)		(26,~~127~~140,000	)
Total Property and Equipment		~~103~~846,000			1103,~~022,~~000
Real Estate Property - at cost
Land		688,000			688,000
Commercial office building		1,~~903~~907,000			1,~~624~~903,000
Accumulated depreciation		(1,~~163~~232,000	)		(1,~~102~~163,000	)
Total Real Estate Property		1,~~428~~363,000			1,~~210~~428,000
Other Assets
Deferred Income Tax Asset		—40,000			~~311,000~~—
Other long-term investments		916,575,000			89,~~941~~575,000
Other		4,000		$	4,000
Total Other Assets		916,~~579~~619,000			9,~~256~~579,000
Total Assets	$	2728,~~807~~146,000		$	2627,~~085~~807,000
The accompanying notes are an integral part of these statements.

3152

SPINDLETOP OIL & GAS Co. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS

SPINDLETOP OIL & GAS Co. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

		December 31,			December 31,
		2023			2022
LIABILITIES AND SHAREHOLDERS' EQUITY

Current Liabilities
Accounts payable and accrued liabilities	$	6,542,000		$	6,859,000
Total Current Liabilities		6,542,000			6,859,000

Noncurrent Liabilities
Deferred Income Tax Payable		—			81,000
Asset retirement obligation		4,414,000			3,654,000
Total Noncurrent Liabilities		4,414,000			3,735,000

Total Liabilities		10,956,000			10,594,000

Shareholders' Equity
Common stock, $.01 par value, 100,000,000 shares authorized; 7,677,471 shares issued and 6,739,943 outstanding at December 31, 2023 and 6,750,318 outstanding at December 31, 2022.		77,000			77,000
Additional paid-in capital		943,000			943,000
Treasury stock, at cost		(1,919,000	)		(1,889,000	)
Retained earnings		18,089,000			18,082,000
Total Shareholders' Equity		17,190,000			17,213,000
Total Liabilities and Shareholders' Equity	$	28,146,000		$	27,807,000



The accompanying notes are an integral part of these statements.

	December 31,			December 31,
	2022			2021
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities	$	6,859,000		$	7,601,000
Total Current Liabilities		6,859,000			7,601,000
Noncurrent Liabilities
Deferred Income Tax Payable		81,000			—
Asset retirement obligation		3,654,000			1,925,000
Total Noncurrent Liabilities		3,735,000			1,925,000
Total Liabilities		10,594,000			9,526,000
Shareholders' Equity
Common stock, $.01 par value, 100,000,000 shares authorized; 7,677,471 shares issued and 6,750,318 outstanding at December 31, 2022 and 6,755,318 outstanding at December 31, 2021.		77,000			77,000
Additional paid-in capital		943,000			943,000
Treasury stock, at cost		(1,889,000	)		(1,874,000	)
Retained earnings		18,082,000			17,413,000
Total Shareholders' Equity		17,213,000			16,559,000
Total Liabilities and Shareholders' Equity	$	27,807,000		$	26,085,000
The accompanying notes are an integral part of these statements.

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

Years Ended December 31,

2022

2021

2020

2023

2022

2021

Revenues

Oil and gas revenues

74,~~775~~502,000

57,~~466~~775,000

25,~~924~~466,000

Revenue from lease operations

~~183~~156,000

~~219~~183,000

~~233~~219,000

Gas gathering, compression, equipment rental

89120,000

9989,000

8999,000

Real estate rental income

~~245~~270,000

~~240~~245,000

~~272~~240,000

Other revenue

62,000

44,000

42,000

Miscellaneous revenue

57,000

62,000

44,000

Total Revenues

85,~~354~~105,000

68,~~068~~354,000

36,~~560~~068,000

Expenses

Lease operations

21,~~120~~469,000

12,~~207~~120,000

1,~~324~~207,000

Production taxes, gathering and marketing

~~867~~701,000

~~896~~867,000

~~675~~896,000

Pipeline and rental operations

2154,000

1721,000

917,000

Real estate operations

~~174~~161,000

~~167~~174,000

~~174~~167,000

Depreciation and amortization

74229,000

~~121~~74,000

~~452~~121,000

ARO accretion expense

2509,~~014,~~000

~~572~~2,014,000

~~139~~572,000

General and administrative

32,~~126~~970,000

23,~~685~~126,000

2,~~640~~685,000

Total Expenses

86,~~396~~093,000

58,~~665~~396,000

5,~~413~~665,000

Income (Loss) from operations

(42988,000

)

~~403~~(42,000

)

(1403,~~853,~~000

)

Other Revenue and Expense

Interest income

~~142~~761,000

~~149~~142,000

~~216~~149,000

Debt forgiveness income

—

~~403,000~~—

403,000

Gain on sale of properties

1104,~~531,~~000

—1,531,000

—

Income (loss) before income tax

1(123,~~631,~~000

)

~~955~~1,631,000

(1955,~~234,~~000

)

Current income tax provision (benefit)

~~570~~(9,000

)

24570,000

~~(191~~24,000

)

Deferred income tax provision (benefit)

~~392~~(121,000

)

~~(106~~392,000

)

(~~149~~106,000

)

Total income tax provision (benefit)

~~962~~(130,000

)

~~(82~~962,000

)

(~~340~~82,000

)

Net Income (Loss)

~~669~~7,000

1669,~~037,~~000

~~(894~~1,037,000

)

Earnings (Loss) per Share of Common Stock

Earnings (Loss) per Share of Common Stock Basic and Diluted

~~0.10~~—

0.1510

(0.1315

)

Weighted Average Shares Outstanding

Weighted Average Shares Outstanding Basic and Diluted

6,~~753~~745,~~386~~059

6,~~755~~753,~~318~~386

6,~~771~~755,~~094~~318

The accompanying notes are an integral part of these statements.

3354

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY For the Years Ended December 31, ~~2022~~2023, ~~2021~~2022, and ~~2020~~2021

	Common Stock Shares	~~Common Stock Shares~~	Common Stock Amount	~~Common Stock Amount~~	Additional Paid-In Capital	~~Additional Paid-In Capital~~	Treasury Stock Shares	~~Treasury Stock Shares~~	Treasury Stock Amount	~~Treasury Stock Amount~~		Retained Earnings	~~Retained Earnings~~
Balance December 31, 2019		7,677,471		77,000		943,000		867,869		(1,806,000	)	$	17,271,000
Purchase of 54,284 shares of Common Stock as Treasury Stock		—		—		—		54,284		(68,000	)		—
Net (Loss)		—		—		—		—		—			(894,000	)
Balance December 31, 2020		7,677,471		77,000		943,000		922,153		(1,874,000	)		16,376,000
Purchase of 5,000 shares of Common Stock as Treasury Stock
Purchase of 5,000 shares of Common Stock as Treasury Stock,shares
Net Income		—		—		—		—		—			1,037,000
Balance December 31, 2021		7,677,471	$	77,000	$	943,000		922,153	($	1,874,000	)		17,413,000
Purchase of 5,000 shares of Common Stock as Treasury Stock		—		—		—		5,000		(15,000	)		—
Net Income		—		—		—		—		—			669,000
Balance December 31, 2022		7,677,471	$	77,000	$	943,000		927,153	($	1,889,000	)	$	18,082,000
Purchase of 10,375 shares of Common Stock as Treasury Stock		—		—		—		10,375		(30,000	)		—
Net Income		—		—		—		—		—			7,000
Balance December 31, 2023		7,677,471	$	77,000	$	943,000		937,528	($	1,919,000	)	$	18,089,000
The accompanying notes are an integral part of these statements.

3455

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

	Twelve Months Ended
	December 31,			December 31,			December 31,
	2022			2021			2020
	2023			2022			2021
Cash Flows from Operating Activities
Net Income (loss)	$	669,000		$	1,037,000		$	(894,000	)
Net Income	$	7,000		$	669,000		$	1,037,000
Reconciliation of net Income (loss) to net cash
Reconciliation of net Income to net cash
Reconciliation of net Income to net cash provided (used) by operating activities
Reconciliation of net Income to net cash provided by operating activities
Depreciation and amortization		74229,000			~~121~~74,000			~~452~~121,000
Accretion of asset retirement obligation		2509,~~014,~~000			~~572~~2,014,000			~~139~~572,000
Gain on sale of oil and gas properties		(1,531,000	)		—			—
Proceeds from sale of oil and gas properties		(104,000	)		(1,531,000	)		—
Changes in accounts receivable		~~904~~110,000			~~(491~~904,000	)		~~577~~(491,000	)
Changes in income tax receivable		~~(180~~540,000	)		(~~176~~180,000	)		(~~191~~176,000	)
Changes in accounts payable and accrued liabilities		(~~742~~317,000	)		1(742,~~887,~~000	)		~~(291~~1,887,000	)
Forgiveness of SBA paycheck Protection Loan		—			~~(403,000~~—	)		(403,000	)
Changes in deferred Income tax asset		~~311~~(40,000	)		~~(106~~311,000	)		(~~149~~106,000	)
Changes in deferred Income tax payable		(81,000	)		—81,000			—
Changes in other assets		—			—			(1,000	)
Net cash provided for operating activities		853,000			1,600,000			2,441,000
Net cash provided (used) for operating activities		1,600,000			2,441,000			(761,000	)
Cash Flows from Investing Activities
Capitalized acquisition, exploration and development		~~703~~(573,000	)		~~542~~703,000			~~(104~~542,000	)
Purchase of other property and equipment		(8283,000	)		(182,000	)		—(1,000	)
Changes in other long-term investments		(~~634~~7,000,000	)		(~~116~~634,000	)		(7116,~~675,~~000	)
Proceeds from sale of oil and gas properties		1104,~~531,~~000			—1,531,000			—
Capitalized tenant improvements and broker fees		~~(279,000~~—	)		(1279,000	)		(441,000	)
Net cash provided (used) for investing activities		1,239,000			424,000			(7,823,000	)
Net cash (used) for investing activities		(7,552,000	)		1,239,000			424,000
Cash Flows from Financing Activities
Purchase of 5,000 shares of treasury stock		(15,000	)		—			(68,000	)
Purchase of 10,375 and 5,000 shares of treasury stock		(30,000	)		(15,000	)		—
Proceeds from SBA Paycheck Protection Loan Program		—			~~403,000~~—			403,000
Net cash provided (used) for financing activities		(15,000	)		403,000			335,000
Net cash used for financing activities		(30,000	)		(15,000	)		403,000
Increase (decrease) in cash, cash equivalents, and restricted cash		2,824,000			3,268,000			(8,249,000	)
Increase (Decrease) in cash, cash equivalents, and restricted cash		(6,729,000	)		2,824,000			3,268,000
Cash, cash equivalents, and restricted cash at beginning of period		1113,~~043~~867,000			711,~~775~~043,000			167,~~024~~775,000
Cash, cash equivalents, and restricted cash at end of period	$	137,~~867~~138,000		$	1113,~~043~~867,000		$	711,~~775~~043,000
The accompanying notes are an integral part of these statements.

3556

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 rentable square feet, of which the Company occupies approximately 10,273 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.

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 unless such adjustment would significantly alter the relationship between capitalized costs and proved oil and gas reserves attributed to a cost center. For instance, a significant alteration would not ordinarily be expected to occur for sales involving less than 25% of the reserve quantities of a given cost center. Although expected to occur infrequently, a significant alteration of ~~the~~ the relationship between capitalized costs and proved reserves also could occur for sales of less than 25 % of the reserve quantities if there were substantial economic differences between properties sold and those retained. Significant judgment is required to determine ~~whether~~ whether an adjustment to capitalized costs would result in a significant alteration. When it is determined that a gain or loss should be recognized on such a sale, total capitalized costs within the cost center are allocated between reserves sold and reserves retained. The allocation of capitalized costs should be made on the same basis used to compute amortization, unless there are substantial economic ~~differences~~ differences between properties sold and those retained, in which case capitalized costs should be allocated on the basis of the relative fair values of the properties. Such asales ~~sale~~ occurred during the ~~year~~years ended December 31, ~~2022~~2023, ~~when~~and December 31, 2022, the Company sold a property for which there were no reserves included in the proved oil and gas reserves for approximately $104,000 and $1,531,000. respectively. At the recognition of the ~~sale~~sales, the net unamortized full cost pool was approximately $545.000 and $319,000 respectively. Therefore, an adjustment to the capitalized costs would result in a significant alteration between the properties sold and those retained. As a result, the Company recognized a gain on this sale.

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 building 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 ~~2022~~2023, ~~2021~~2022, or ~~2020~~2021 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 periods ending December 31.

	2022			2021
	2023			2022
Carrying amount of asset retirement obligation	$	13,~~925~~654,000		$	1,~~434~~925,000
Liabilities added		—565,000			~~20,000~~—
Liabilities divested or settled		(~~285~~314,000	)		(~~101~~285,000	)
Current period accretion expenses		2509,~~014,~~000			~~572~~2,014,000
Carrying amount as of December 31,	$	34,~~654~~414,000		$	13,~~925~~654,000

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~~ for Uncertainty in Income Taxes” was issued. The interpretation creates a single model to address accounting for uncertainty in ~~tax~~ 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 been 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~~ 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 is returned to the Company at the outlet of the plant. The midstream processing entity gathers and processes the natural gas and remits ~~proceeds~~ 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 ~~2022~~2023 or subsequent thereto that would have a material impact on the Company’s financial reporting.

Reclassifications

Certain prior year amounts have been reclassified to conform to the current year presentation on the consolidated balance sheet, consolidated statement of operations, and consolidated statements of cash flows.

Subsequent Events

The Company has evaluated subsequent events through the issuance date of April 1716, ~~2023~~2024.

3961

3. ACCOUNTS RECEIVABLE

	December 31,
	2022			2021
	2023			2022
Trade	$	~~151~~18,000		$	65151,000
Accrued receivable		2,~~064~~087,000			32,~~054~~064,000
		2,215,000			3,119,000
		2,105,000			2,215,000
Less: Allowance for losses		(15,000	)		(15,000	)
	$	2,~~200~~090,000		$	32,~~104~~200,000

Accrued receivables are receivables from purchasers of oil and gas. These revenues are booked from check stub detail after receipt of the check for sales of oil and 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,
	2022		2021
	2023		2022
Trade payables	$	1,~~983~~834,000	$	21,~~929~~983,000
Production proceeds payable		3,~~541~~371,000		3,~~316~~541,000
Prepaid drilling costs		1,~~335~~337,000		1,~~356~~335,000
	$	6,~~859~~542,000	$	76,~~601~~859,000

5. RELATED PARTY TRANSACTIONS

Certain officers, directors, and related parties including entities controlled by officers of the Company, engage in business transactions with the Company which were not the result of arms-length negotiations between independent parties. Accounts receivable and accounts payable contain $78,000 and $215,000, respectively, for the year ended December 31, 2022, relating to these transactions. Amounts for the ~~year~~years ended December 31, 2023, and 2021, were not material.

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; this agreement was terminated in 2021. On October 1, 2008, the Company entered into a similar agreement with Giant NRG Co., LP (“NRG”) a limited partnership with Chris Mazzini and Michelle Mazzini as limited partners. Under this agreement NRG pays a monthly fee of $1,500.00 to the Company in exchange for the Company providing certain administrative services to NRG. The Company has entered into a similar ~~arrangement~~ arrangement with Peveler Pipeline, LP ("Peveler"), whereby Peveler pays the Company a monthly charge of $250.00 in exchange for the Company providing administrative services to Peveler. Chris and Michelle Mazzini are the owners of Peveler Pipeline, LP, a limited ~~partnership~~ 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 $500.00 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 $350.00 for certain administrative services that the Company provides to Reserve. ~~See also Footnote 5 to the Financial Statements.~~

During the year ended December 31, 2022, the Company sold ~~four~~five wells to a related party for a sales price of $563,000 with the offset being an adjustment to the full cost pool. No gain or loss was recognized related to this transaction.

During the fourth quarter of 2021, the Company participated in the completion of the Howe #1H well located in the Normangee East block of Madison County, Texas, operated by Giant NRG Co., LP, a related entity.

During the fourth quarter of 2022, the Company participated in the drilling of the Smead Heirs #2 well located in Gregg County, Texas, operated by Giant NRG Co. LP, a related entity.

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, ~~2022~~2023, 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 three-year period ending December 31, ~~2022~~2023, the Company made the following repurchase of its common stock:

Effective ~~April~~July 67, ~~2020~~2022, ~~and June 20, 2020,~~ the Company repurchased 455,~~036~~000 shares ~~and 9,248 shares~~ of its common stock from a non-controlling, unaffiliated shareholder of the Company for a negotiated purchase price of $5615,~~295~~500 ~~and $11,560 respectively,~~ or $13.2510 per share. The repurchased shares are held as Treasury Stock.

Effective ~~July~~June 730, ~~2022~~2023, the Company repurchased 510,~~000~~ 375 shares of its common stock from a non-controlling, unaffiliated shareholder of the Company for a negotiated purchase price of $1530,~~500~~ 000 or $32.~~10 per~~89 per share. The repurchased shares are held as Treasury Stock.

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~~ United States federal income tax rate of 21% to pretax income in ~~2022~~2023, ~~2021~~2022, and ~~2020~~2021.

	2022			2021			2020
	2023			2022			2021
Computed expected tax expense (benefit)	$	21(48,000	)	$	~~201~~21,000		$	~~(259~~201,000	)
Miscellaneous timing differences
related to book and tax depletion differences
Miscellaneous timing differences related to book and tax depletion differences and the expensing of intangible drilling costs.		~~153~~17,000			~~(308~~153,000	)		68(308,000	)
NOL Carryforward		—			~~(148,000~~—	)		—(148,000	)
Gain on sale of oil and gas properties'		~~396~~22,000			~~279~~396,000			—279,000
Correction of prior year estimate		—			—			—
Expected Federal income tax expense (benefit)	$	~~570~~(9,000	)	$	24570,000		$	~~(191~~24,000	)
Income tax expense (benefit) for the years ended December 31, 2022, 2021 and 2020
		2022			2021			2020
Federal income taxes (benefit)	$	570,000		$	24,000		$	(191,000	)
State income taxes		—			—			—
Current income tax provision (benefit)	$	570,000		$	24,000		$	(191,000	)

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, 2022 and 2021 consisted of the following:63


Income tax expense (benefit) for the years ended December 31, 2023, 2022 and 2021


		2023			2022		2021
Federal income taxes (benefit)	$	(9,000	)	$	570,000	$	24,000
State income taxes		—			—		—
Current income tax provision (benefit)	$	(9,000	)	$	570,000	$	24,000

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'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.

	December 31,
	2022			2021
	2023			2022
Deferred tax assets
Depletion and amortization		—273,000			~~98,000~~—
Expired leasehold		—			155,000
Depreciation		33,000			—
Other, net		—			—
Total deferred tax assets		306,000			—
Net operating loss carryforward					37,000
Depreciation		—			21,000
Total deferred tax assets		—			311,000
Deferred tax liabilities
Intangible drilling costs		(56266,000	)		—(56,000	)
Installment sale income		—			—
Depreciation		—			(25,000	)
Depreciation		(25,000	)		—
Total deferred tax liability		(266,000	)		(81,000	)
Total deferred tax liability		(81,000	)		—
Net deferred income tax asset (payable)	$	40,000		$	(81,000	)
Net deferred income tax asset (payable)	$	(81,000	)	$	311,000

4164

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:

		2022			2021			2020
		2023			2022			2021
Net cash provided by operating activities includes cash payments for the following:
Income taxes	$	~~750,000~~—		$	—750,000		$	~~60,000~~—
Excluded from the Consolidated Statements of Cash Flows were the effects of certain non-cash investing and financing activities, as follows:
		2022			2021			2020
Addition (Reduction) of oil & gas
properties by recognitions of
Addition (Reduction) of oil & gas properties by recognitions of asset retirement obligation	$	(285,000	)	$	(113,000	)	$	(36,000	)
	$	(285,000	)	$	(113,000	)	$	(36,000	)
		2022			2021			2020
Proceeds from sales of oil and gas properties	$	1,531,000		$	—		$	1,168,000
Less:
Qualified Intermediary accounts receivable		—			—			(250,000	)
	$	1,531,000		$	—		$	918,000

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

		2023		2022			2021
Addition (Reduction) of oil & gas
properties by recognitions of
asset retirement obligation	$	251,000	$	(285,000	)	$	(113,000	)
	$	251,000	$	(285,000	)	$	(113,000	)


		2023		2022			2021
Proceeds from sales of oil and gas properties	$	104,000	$	1,531,000		$	—
Less:
Qualified Intermediary accounts receivable		—		—			—
	$	104,000	$	1,531,000		$	—

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, ~~2022~~2023, the Company had approximately $3,~~698~~461,000 in checking and money market accounts at one bank, $21,~~123~~624,000 at a second bank, $~~692~~1,354,000, ~~379~~877,000, and $64322,000 invested at three other banks. The Company also had approximately $916,575,000 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 $42,~~650~~826,000.

Most of the Company's business activity is located in Texas. Accounts receivable as of December 31, 2022, and 2021, 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.65

Most of the Company's business activity is located in Texas. Accounts receivable as of December 31, 2023, and 2022, 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, ~~2022~~2023 and ~~2021~~2022 follows:

2022

2021

2023

2022

Carrying Amount

Fair Value

Carrying Amount

Fair Value

Cash

136,~~597~~868,000

1013,~~673~~597,000

Restricted cash

270,000

~~370~~270,000

Long-term investments

916,575,000

89,~~941~~575,000

Accounts receivable

2,~~200~~090,000

32,~~104~~200,000

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.

AtAs of December 31, ~~2022~~2023, 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, 2025. The $10,000 bond is written for a one-year period and expired February 16, ~~2023~~2024. Subsequent to year-end, this bond has been extended through February 16, ~~2024~~2025.

The Company has ~~eight~~six letters of credit from a ~~bank~~ bank issued for the benefit of various state regulatory agencies in Texas, New Mexico, Oklahoma, the U.S. Department of the Interior Bureau of Indian Affairs, and Louisiana, ranging in amounts from $25,000 to $100,000 and totaling $270,000. These letters of credit are fully secured by funds on deposit with the bank in business money market accounts and automatically extend for a period of one year unless cancelled by the beneficiary.

The Company has ~~seven~~eight additional letters of credit from one bank issued for the benefit of various state agencies in Texas, New Mexico, and Oklahoma ranging from $25,000 to $300,000 totaling $~~575~~600,000. These letters of credit are secured by long-term certificates of deposit at the ~~two banks~~bank.

13. ADDITIONAL OPERATIONS AND BALANCE SHEET INFORMATION

Certain information about the Company's operations for the years ended December 31, ~~2022~~2023, ~~2021~~2022 and ~~2020~~2021 follows.

Dependence on Purchasers and Operators

Purchaser / Operator	~~2022~~2023			~~2021~~2022			~~2020~~2021
Energy Transfer Crude Marketing, LLC		1417	%		014	%		0	%
Giant NRG Co., LP		12	%		0	%		0	%
Enlink Gas Marketing, LTD.		11	%		9	%		14	%
Bedrock Energy Partners		10	%		9	%		0	%
Scissor Tail Exploration and Production		8	%		0	%		0	%
Enlink Gas Marketing, LTD.		9	%		14	%		12	%
Bedrock Energy Partners		7	%		10	%		9	%
Barnett Gathering, LP		7	%		6	%		5	%
Giant Energy Co., LP		6	%		12	%		0	%
Pruet Production Co.		5	%		45	%		34	%
ETC Texas Pipeline, LTD		4	%		4	%		2	%
BKV Midstream		4	%		4	%		0	%
Eastex Crude Company		4	%		4	%		3	%
Hunt Crude Oil Supply		4	%		3	%		2	%
BKV Midstream		4	%		0	%		0	%
Territory Resources, LLC		4	%		0	%		0	%
Hunt Crude Oil Supply		3	%		2	%		6	%
Trailblazer Energy, Formerly ETX Energy, LLC		4	%		2	%		1	%
Javelin Oil & Gas		3	%		0	%		0	%
Eastex Crude Company		4	%		4	%		4	%
Phillips 66		2	%		2	%		3	%
ETC Texas Pipeline, LTD		3	%		4	%		4	%
Bedrock Production LLC		2	%		2	%		10	%
Targa Midstream Services, LLC		3	%		0	%		11	%
Producer's Midstream		2	%		02	%		0	%
IACX Roswell LLC		2	%		3	%		0	%
Oasis Transportation & Marketing Group		2	%		2	%		1	%
Oasis Transportation & Marketing Group		2	%		1	%		1	%
Bedrock Production LLC		2	%		2	%		2	%
Trailblazer formerly ETX Energy, LLC		2	%		1	%		1	%
Javelin Oil & Gas		1	%		3	%		0	%
Empire Pipeline Corp.		2	%		2	%		1	%
Phillips 66		1	%		2	%		2	%
Webb Energy Resources, Inc.		1	%		1	%		1	%
Edinger Engineering Inc.		1	%		1	%		1	%
Midcoast Energy Partners LP		1	%		4	%		2	%
DCP Midstream, LP		1	%		1	%		0	%
Land and Natural Resource Development		1	%		1	%		1	%
Eagle Ridge Operating, Inc		1	%		1	%		1	%
Empire Pipeline Corp.		1	%		2	%		2	%
OXY USA, Inc.		1	%		1	%		1	%
Montare Operating, LTD		1	%		0	%		0	%
FDL Operating LLC		0	%		2	%		2	%
Edinger Engineering Inc.		1	%		1	%		1	%
Sunoco Partners Marketing		0	%		13	%		20	%
Callon Petroleum Operating		1	%		0	%		0	%
Targa Midstream Services, LLC		0	%		11	%		11	%
DCP Midstream, LP		1	%		1	%		1	%
Peveler Pipeline, LP		0	%		6	%		4	%
IACX Roswell LLC		0	%		2	%		3	%
Valero Energy Corporation		0	%		1	%		1	%
Webb Energy Resources, Inc.		0	%		1	%		1	%
ACE Gathering, Inc.		0	%		0	%		1	%
Barnett Gathering, LP		0	%		7	%		6	%
Lion Oil Trading & Transportation		0	%		0	%		1	%
Midcoast Energy Partners LP		0	%		1	%		4	%
Enterprise Crude Oil, LLC		0	%		0	%		1	%
Eagle Ridge Operating, Inc		0	%		1	%		1	%
OXY USA, Inc.		0	%		1	%		1	%
FDL Operating LLC		0	%		0	%		2	%
Sunoco Partners Marketing		0	%		0	%		13	%
Peveler Pipeline, LP		0	%		0	%		6	%
Valero Energy Corporation		0	%		0	%		1	%
Purchaser / Operator

Oil and natural gas production is sold to many different purchasers/operators under market sensitive, short-term contracts.

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,
	2022			2021			2020
	2023			2022			2021
Capitalized costs relating to oil and gas producing activities:
producing activities:
Unproved properties	$	1,876,000		$	1,876,000		$	1,876,000
Proved properties		23,~~445~~973,000			2423,~~429~~445,000			2524,~~052~~429,000
Total capitalized costs		25,~~321~~849,000			2625,~~305~~321,000			26,~~928~~305,000
Accumulated amortization		(25,~~304~~438,000	)		(25,304,000	)		(25,~~241~~304,000	)
Total capitalized costs, net	$	17411,000			117,~~001,~~000			1,~~687~~001,000

	Year Ended December 31,
	2022		2021		2020
	2023		2022		2021
Costs incurred in oil and gas property acquisitions, exploration and development:
acquisitions, exploration and development:
Acquisition of properties	$	—	$	~~19,000~~—	$	2219,000
Development costs		~~214~~565,000		~~410~~214,000		97410,000
Total costs incurred	$	~~214~~565,000	$	~~429~~214,000	$	~~119~~429,000

Year Ended December 31,

2022

2021

2020

2023

2022

2021

Results of operations from producing activities:

Sales of oil and gas

74,~~775~~502,000

57,~~466~~775,000

25,~~923~~466,000

Production costs

2,~~987~~170,000

2,~~103~~987,000

2,~~000~~103,000

Amortization of oil and gas properties

—134,000

~~63,000~~—

~~393~~63,000

Total production costs

2,~~987~~304,000

2,~~166~~987,000

2,~~393~~166,000

Total net revenue

42,~~788~~198,000

34,~~300~~788,000

~~530~~3,300,000

	Year Ended December 31,
	2022		2021		2020
	2023		2022		2021
Sales price per equivalent Mcf	$	85.9756	$	58.5897	$	35.1558
Production costs per equivalent Mcf	$	32.4569	$	23.1545	$	2.2115
Amortization per equivalent Mcf	$	—0.20	$	~~0.06~~—	$	0.4206

	Year Ended December 31,
	2022		2021		2020
	2023		2022		2021
Results of operations from gas gathering and equipment rental activities:
and equipment rental activities:
Revenue	$	89120,000	$	9989,000	$	8999,000
Operating expenses		2154,000		1721,000		917,000
Depreciation		14,000		1,000		1,000
Total costs		2258,000		1822,000		1018,000
Total net revenue	$	6762,000	$	8167,000	$	7981,000

4468

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, ~~2022~~2023:

	Year Ended December 31,
	2022		2021		2020
	2023		2022		2021
Revenues: (1)
Oil and gas exploration, production and operations	$	74,~~958~~658,000	$	57,~~685~~958,000	$	35,~~157~~685,000
and operations
Gas gathering, compression and equipment rental		89120,000		9989,000		8999,000
equipment rental
Real estate rental		~~245~~270,000		~~240~~245,000		~~272~~240,000
Revenues	$	85,~~292~~048,000	$	68,~~024~~292,000	$	36,~~518~~024,000

	Year Ended December 31,
	2022		2021		2020
	2023		2022		2021
Depreciation, depletion, and
amortization expense:
Oil and gas exploration, production and operations	$	17155,000	$	6517,000	$	~~396~~65,000
and operations
Impairment of oil and gas assets		—		—		—
Gas gathering, compression and equipment rental		14,000		1,000		1,000
equipment rental
Real estate rental		5670,000		5556,000		55,000
Depreciation, depletion, and amortization expense	$	74229,000	$	~~121~~74,000	$	~~452~~121,000

	Year Ended December 31,
	2022			2021			2020
	2023			2022			2021
Income (loss) from operations:
Oil and gas exploration, production and operations	$	21,~~940~~824,000		$	2,~~945~~940,000		$	~~623~~2,945,000
and operations
Gas gathering, compression and equipment rental		6762,000			8167,000			7981,000
equipment rental
Real estate rental		1539,000			1815,000			4318,000
		3,022,000			3,044,000			745,000
		1,925,000			3,022,000			3,044,000
Corporate and other (2)		(21,~~353~~918,000	)		(2,~~007~~353,000	)		(12,~~639~~007,000	)
Consolidated net income (loss)	$	~~669~~7,000		$	1669,~~037,~~000		$	~~(894~~1,037,000	)

	Year Ended December 31,
	2022		2021		2020
Identifiable assets net of DDA:
Oil and gas exploration, production
Oil and gas exploration, production and operations	$	83,000	$	1,001,000	$	1,703,000
Gas gathering, compression and
Gas gathering, compression and equipment rental		4,000		5,000		6,000
Real estate rental		1,428,000		1,210,000		1,265,000
		1,515,000		2,216,000		2,974,000
Corporate and other (3)		26,292,000		23,869,000		19,696,000
Consolidated total assets	$	27,807,000	$	26,085,000	$	22,670,000


	Year Ended December 31,
	2023		2022		2021
Identifiable assets net of DDA:
Oil and gas exploration, production
Oil and gas exploration, production and operations	$	777,000	$	83,000	$	1,001,000
Gas gathering, compression and
Gas gathering, compression and equipment rental		53,000		4,000		5,000
Real estate rental		1,363,000		1,428,000		1,210,000
		2,193,000		1,515,000		2,216,000
Corporate and other (3)		25,953,000		26,292,000		23,869,000
Consolidated total assets	$	28,146,000	$	27,807,000	$	26,085,000

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,
	2022			2021			2020
	2023			2022			2021
Maintenance and repairs	$	1854,000		$	1218,000		$	612,000
Production taxes		~~451~~208,000			~~269~~451,000			~~116~~269,000
Taxes, other than payroll and income taxes		~~(45~~20,000	)		7(45,000	)		167,000

16. QUARTERLY DATA (UNAUDITED)

The table below reflects selected quarterly information for the years ended December 31, ~~2022~~2023, ~~2021~~2022 and ~~2020~~2021.

QUARTERLY DATA (UNAUDITED)
	Year Ended December 31, 2023
		First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenue	$	1,167,000		$	1,054,000		$	1,674,000			1,210,000
Expense		(1,514,000	)		(1,125,000	)		(1,273,000	)		(2,181,000	)
Operating income (loss)		(347,000	)		(71,000	)		401,000			(971,000	)
Other revenues		229,000			199,000			209,000			228,000
Net income (loss)		(118,000	)		128,000			610,000			(743,000	)
Current tax (provision) benefit		—			(17,000	)		(44,000	)		70,000
Deferred tax (provision) benefit		21,000			14,000			11,000			75,000
Net income (loss)	$	(97,000	)	$	125,000		$	577,000		$	(598,000	)
Earnings (loss) per share of
common stock
Basic and diluted	$	(0.01	)	$	0.02		$	0.09		$	(0.10	)

	Year Ended December 31, 2022
		First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenue	$	1,824,000		$	2,675,000		$	2,012,000		$	1,843,000
Expense		(1,215,000	)		(1,330,000	)		(1,386,000	)		(4,465,000	)
Operating income (loss)		609,000			1,345,000			626,000			(2,622,000	)
Other revenues		—			—			1,531,000			142,000
Net income (loss)		609,000			1,345,000			2,157,000			(2,480,000	)
Current tax (provision) benefit		(60,000	)		(176,000	)		(416,000	)		82,000
Deferred tax (provision) benefit		(40,000	)		(77,000	)		(48,000	)		(227,000	)
Net income (loss)	$	509,000		$	1,092,000		$	1,693,000		$	(2,625,000	)
Earnings (loss) per share of
common stock
Basic and diluted	$	0.08		$	0.16		$	0.25		$	(0.39	)

	Year Ended December 31, 2021
		First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenue	$	1,099,000		$	1,227,000		$	1,806,000		$	1,936,000
Expense		(978,000	)		(1,230,000	)		(992,000	)	$	(2,465,000	)
Operating income (loss)		121,000			(3,000	)		814,000			(529,000	)
Other revenues		—			—			—			552,000
Net income (loss)		121,000			(3,000	)		814,000			23,000
Current tax (provision) benefit		(17,000	)		(5,000	)		(229,000	)		227,000
Deferred tax (provision) benefit		(7,000	)		2,000			(182,000	)		293,000
Net income (loss)	$	97,000		$	(6,000	)	$	403,000		$	543,000
Earnings (loss) per share of
common stock
Basic and diluted	$	(0.01	)	$	—		$	0.06		$	0.08

	Year Ended December 31, 2021
		First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenue	$	1,099,000		$	1,227,000		$	1,806,000		$	2,488,000
Expense		(978,000	)		(1,230,000	)		(992,000	)		(2,465,000	)
Operating income (loss)		121,000			(3,000	)		814,000			23,000
Current tax (provision) benefit		(17,000	)		(5,000	)		(229,000	)		227,000
Deferred tax (provision) benefit		(7,000	)		2,000			(182,000	)		293,000
Net income (loss)	$	97,000		$	(6,000	)	$	403,000		$	543,000
Earnings (loss) per share of
common stock
Earnings (loss) per share of common stock Basic and diluted	$	0.01		$	—		$	0.06		$	0.08

	Year Ended December 31, 2020
		First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenue	$	964,000		$	548,000		$	1,135,000		$	1,532,000
Expense		(1,320,000	)		(1,055,000	)		(1,006,000	)		(2,032,000	)
Operating income (loss)		(356,000	)		(507,000	)		129,000			(500,000	)
Current tax (provision) benefit		61,000			113,000			(43,000	)		60,000
Deferred tax (provision) benefit		23,000			(28,000	)		17,000			137,000
Net income (loss)	$	(272,000	)	$	(422,000	)	$	103,000		$	(303,000	)
Earnings (loss) per share of
common stock
Earnings (loss) per share of common stock Basic and diluted	$	(0.04	)	$	(0.06	)	$	0.02		$	(0.05	)

17. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)

The Company’s net proved oil and natural gas reserves as of December 31, ~~2022~~2023, ~~2021~~2022, and ~~2020~~2021, have been estimated by Company personnel.

All estimates are in accordance with 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 ensure 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 ~~2022~~2023, ~~2021~~2022, and ~~2020~~2021 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, 2019		228,747			4,519,681
Sales of reserves in place		—			—
Acquired properties		2,861			17,341
Extensions and discoveries		—			—
Revisions of previous estimates *		(56,008	)		(880,867	)
Production		(30,900	)		(743,465	)
Balance December 31, 2020		144,700			2,912,690
Sales of reserves in place		(1,733	)		(193,340	)
Acquired properties		1,603			546
Extensions and discoveries		16,202			833
Revisions of previous estimates *		59,522			3,241,463
Production		(33,604	)		(778,462	)
Balance December 31, 2021		186,690			5,183,730
Sales of reserves in place		—			(49,820	)
Acquired properties		702			—
Extensions and discoveries		1,041			1,231
Revisions of previous estimates *		5,105			(356,195	)
Production		(35,698	)		(652,786	)
Balance December 31, 2022		157,840			4,126,160
Sales of reserves in place		—			—
Acquired properties		554			—
Extensions and discoveries		6,920			37,550
Revisions of previous estimates *		8,078			(1,907,371	)
Production		(33,522	)		(608,499	)
Balance December 31, 2023		139,870			1,647,840
* May also include divestitures, not only changes in engineering.
Proved Developed Reserves:
Balance December 31, 2020		144,700			2,912,690
Balance December 31, 2021		186,690			5,183,730
Balance December 31, 2022		157,840			4,126,160
Balance December 31, 2023		139,870			1,647,830

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 ~~2022~~2023, ~~2021~~2022, and ~~2020~~2021, 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.

47Proved Developed Reserves were calculated based on Decline Curve Analysis on 18 operated wells and 56 non-operated wells. Materially insignificant operated and non-operated wells were excluded from the reserve estimate.

Proved Developed Reserves were calculated based on Decline Curve Analysis on 42 operated wells and 81 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,
	2022			2021			2020
	2023			2022			2021
Future production revenue	$	3815,~~697~~188,000		$	3238,~~392~~697,000		$	1032,~~020~~392,000
Future development costs		—			—			—
Future production costs		(188,~~293~~294,000	)		(1518,~~690~~293,000	)		(615,~~284~~690,000	)
Future net cash flow before Federal income taxes		206,~~404~~894,000			1620,~~702~~404,000			316,~~736~~702,000
Future income taxes		(31,~~061~~034,000	)		(23,~~505~~061,000	)		(~~560~~2,505,000	)
Future net cash flows		175,~~343~~860,000			1417,~~197~~343,000			314,~~176~~197,000
Effect of 10% annual discounting		(31,~~878~~041,000	)		(3,~~719~~878,000	)		(~~609~~3,719,000	)
Standardized measure of discounted cash flows	$	134,~~465~~819,000		$	1013,~~478~~465,000		$	210,~~567~~478,000

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

	Year Ended December 31,
	2022			2021			2020
	2023			2022			2021
Beginning of the year	$	1013,~~478~~465,000		$	210,~~567~~478,000		$	62,~~098~~567,000
Sales of oil and gas, net of production costs		(42,~~556~~219,000	)		(34,~~108~~556,000	)		(~~879~~3,108,000	)
Net changes in prices and production costs		5(6,~~983~~996,000	)		75,~~762~~983,000			~~(963~~7,762,000	)
Extensions, discoveries, additions less related costs		~~109~~330,000			~~574~~109,000			—574,000
Development costs incurred		~~153~~538,000			~~429~~153,000			92429,000
Revisions of previous quantity estimates		3(885,~~637,~~000	)		13,~~896~~637,000			~~(963~~1,~~200~~896,000	)
Net change in purchase and sales of minerals in place		~~(68~~1,000	)		(2468,000	)		28(24,~~664~~000	)
Accretion of discount		1,~~048~~347,000			~~257~~1,048,000			~~610~~257,000
Net change in income taxes		(~~577~~76,000	)		(~~549~~577,000	)		~~777~~(549,000	)
Other		(2686,~~742,~~000	)		~~674~~(2,742,000	)		(2674,~~233,464~~000	)
End of year	$	134,~~465~~819,000		$	1013,~~478~~465,000		$	210,~~567~~478,000

4873

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DECEMBER 31, ~~2022~~2023, ~~2021~~2022, AND ~~2020~~2021

SCHEDULE I I
		Balance		Costs & Expenses		Deductions		Ending Balance
Allowance for doubtful accounts
December 31, 2023	$	15,000	$	—	$	—	$	15,000
December 31, 2022	$	15,000	$	—	$	—	$	15,000
December 31, 2021	$	15,000	$	—	$	—	$	15,000
December 31, 2020	$	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	$ 605,000
Gross amounts at which carried at close of year
Land	Buildings	Total	Accumulated Depreciation	Life on which Depreciation Calculated	Date Acquired
$ 688,000	$1,903,000	$ 2,591,000	$ 1,163,000	(a)	12/27/2004
Notes to Schedule III
(a) See Footnote 2 to the Financial Statements outlining depreciation methods and lives.
(b) None

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	$ 609,000

Gross amounts at which carried at close of year

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

$ 688,000	$1,907,000	$ 2,595,000	$ 1,232,000	(a)	12/27/2004



Notes to Schedule III

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

(b) None

SCHEDULE III - REAL ESTATE AND ACCUMULATED DEPRECIATION
(c) The reconciliation for investments in real estate and accumulated depreciation for the years ended December 31, 2022 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
Acquisitions
Depreciation expense				47,000
Balance, December 31, 2019		2,268,000		992,000
Acquisitions		44,000
Depreciation expense				55,000
Balance, December 31, 2020		2,312,000		1,047,000
Acquisitions
Depreciation expense				55,000
Balance, December 31, 2021		2,312,000		1,102,000
Acquisitions		279,000
Depreciation expense				61,000
Balance, December 31, 2022		2,591,000		1,163,000

SCHEDULE III - REAL ESTATE AND ACCUMULATED DEPRECIATION

Schedule IIIa

(c) The reconciliation for investments in real estate and accumulated depreciation for the years ended December 31, 2023 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
Acquisitions
Depreciation expense		47,000
Balance, December 31, 2019	2,268,000	992,000
Acquisitions	44,000
Depreciation expense		55,000
Balance, December 31, 2020	2,312,000	1,047,000
Acquisitions
Depreciation expense		55,000
Balance, December 31, 2021	2,312,000	1,102,000
Acquisitions	279,000
Depreciation expense		61,000
Balance, December 31, 2022	2,591,000	1,163,000
Acquisitions	4,000
Depreciation expense		69,000
Balance, December 31, 2023	2,595,000	1,232,000

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