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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, 2025

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.)

12850vSpurling 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. $2,023,504 based upon a total of 697,760 shares held as of June 30, 2025, 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	6,598,303
(Class)	(Outstanding at April 15, 2026)

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 five states including: Texas, Oklahoma, New Mexico, Louisiana, and Alabama. We operate the 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 analyzes 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 5 of those states which include Alabama, Louisiana, Oklahoma, New Mexico and Texas.

The Company holds approximately 50,633 gross acres (10,211 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)		3,470		3,221		5,516		228		8,986		3,449		17.74	%		33.77	%
East Texas		3,904		2,832		5,082		323		8,986		3,155		17.75	%		30.90	%
Gulf Coast Texas		40		35		80		12		120		47		0.24	%		0.46	%
West Texas		80		53		2,280		155		2,360		208		4.66	%		2.04	%
Texas Panhandle		1,280		873		640		46		1,920		919		3.79	%		9.00	%
Alabama		1,160		719		3,139		61		4,299		780		8.49	%		7.64	%
Arkansas		—		—		1,043		55		1,043		55		2.06	%		0.54	%
Louisiana		—		—		1,328		115		1,328		115		2.62	%		1.13	%
New Mexico		956		816		40		3		996		819		1.97	%		8.02	%
Oklahoma		240		128		19,505		486		19,745		614		39.00	%		6.01	%
Montana		—		—		10		—		10		—		0.02	%		0.00	%
Wyoming		—		—		840		50		840		50		1.66	%		0.49	%

Total		11,130		8,677		39,503		1,534		50,633		10,211		100.00	%		100.00	%

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 & Bend Arch		234,627		44.78	%
East Texas		191,778		36.60	%
Panhandle Texas		23,698		4.52	%
West Texas		13,512		2.58	%
Gulf Coast Texas		1,520		0.29	%
Total Texas		465,135		88.77	%

Alabama		39,807		7.60	%
Oklahoma		18,202		3.47	%
New Mexico		893		0.17	%
Total Other States		58,902		11.23	%
Total		524,037		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

Oklahoma

During the first quarter of 2025, the Company participated in the drilling of a new horizontal well in Major County, OK, targeting the Mississippian Lime. The Fort 22.27-H well was spud on 2/28/2025 and was drilled to an approximate true vertical depth (TVD) of 9,250 ft and a measured depth of 14,444 ft. The well was cased on 4/01/2025, was completed in July 2025, and was placed into production on 7/28/2025. The well was producing at a rate of 227 bopd, 1,241 mcfgpd and 440 bswpd as of 10/31/2025. The production rates are expected to decrease with time. The Company owns a 0.0234375 non-operated working interest in the well.

During the second quarter of 2025, the Company participated in the drilling of a new horizontal well in Major County, OK, targeting the Mississippian Lime. The Reutlinger 22-27-1H well was spud on June 6, 2025, and was drilled to an approximate true vertical depth (TVD) of 9,000 ft and a measured depth of 14,575 ft and is currently awaiting casing and completion. The Company owns a 0.0234375 non-operated working interest in the well. The well is scheduled to be completed by the operator in 2026.

Subsequent to year end of 12/31/2025, the Company participated in the drilling of a new horizontal well in Custer County, OK targeting the Cherokee Formation. The well was spudded on 1/4/2026 and drilled to a total depth of 21,570’. The well was cased and cemented, and the drilling rig was released on 3/4/2026. The well is awaiting completion. The Company owns an estimated 0.01725466 non-operated working interest in the well.

Subsequent to the year end of 12/31/2025, the Company participated in the drilling of a horizontal well in Custer County, OK targeting the Des Moines Formation. The estimated total depth is 20,000 ft. and the well should spud in the second quarter of 2026. The Company owns an estimated 0.015674 non-operated working interest in the well.

West Texas

During the third quarter of 2025, the Company participated in the drilling of a new horizontal well in Martin & Dawson Counties, Texas targeting the Dean Sands. The Sterling C 3H well was spud on September 3, 2025, and was drilled to an approximate true vertical depth (TVD) of 9,000 ft and a total measured depth of 19,730 ft. The well was cased and is currently awaiting completion. The company owns a 0.0784909 non-operated working interest in the well. The well was placed into production on 12/19/2025 at a rate of 14 bopd, 28 mcfgpd and 1,927 bwpd. Production has increased from the initial production as the frac fluids are being pumped back. As of 12/31/2025, production had increased to 458 bopd, 192 mcfgpd, 5,005 bwpd. The average daily production for the first quarter of 2026 is 786 bopd, 332 mcfgpd, 4,317 bwpd.

For all the above wells, the Company cautions that the initial production rates of a newly completed well or newly recompleted well can have steep decline rates and the initial production rates reported above may not be an indicator of the ultimate oil and gas recoveries obtained from the well. Additionally, production rates of well(s) acquired by the Company at the effective date may not be an indicator of the ultimate oil and gas recoveries to be obtained from the well.

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, 2025, based on SEC guidelines, were classified as follows:

	Barrels of Oil		BCF Gas
Proved Developed Producing		121,466		2,415
Proved Developed Non-Producing		—		—
Proved Undeveloped		—		—
Total Proved Reserves		121,466		2,415

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		402,571	77	%
Oil Reserves		121,466	23	%
Total Reserves		524,037	100	%

Proved Developed Producing		524,037	100	%
Proved Developed Non-Producing		—	—
Proved Undeveloped		—	—
Total Proved Reserves		524,037	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		401,382	77	%
Non-Operated Wells		122,655	23	%
Total		524,037	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 percentage of total oil and natural gas sales) from oil and natural gas produced by the Company for the three-year period ended December 31, 2025. The Company made sales of oil and natural gas to approximately 89 different purchasers / operators during 2025.

Dependence on Purchasers and Operators

Purchaser / Operator	2025			2024			2023
Energy Transfer Crude		14	%		18	%		17	%
Merit Energy Company		13	%		1	%		—
Enlink Gas Marketing, LTD.		12	%		9	%		11	%
Bedrock Energy Partners		7	%		6	%		7	%

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 six percent (6.0%) of the Company's oil and natural gas revenues during the three years ended December 31, 2025.

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, 2025, the Company employed or contracted for the services of a total of approximately 42 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.

Competition

We compete with other oil and natural gas companies for leases, equipment, personnel and markets for the sale of oil and natural gas, The oil and natural gas industry is intensely competitive, and it is becoming more difficult for smaller companies such as ours to compete with larger oil and gas companies. See “Item 1A. Risk Factors” for additional discussion of competition in the oil and natural gas industry.

Oil and natural gas compete with other forms of energy available to customers, including alternate forms of energy such as wind, solar, and nuclear generated electricity, coal and biofuels. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

Seasonal Nature of Business

Generally, demand for natural gas decreases during the summer months and increases during the winter months and demand for oil peaks during the summer months. Certain natural gas purchasers utilize natural gas storage facilities and acquire some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for meeting our well drilling objectives, delay the installation of production facilities, and increase competition for equipment, supplies and personnel during certain times of the year, which could lead to shortages and increase costs or delay operations.

Compliance with Environmental, Health and Safety Regulations

General

Our oil and natural gas development operations are subject to stringent and complex federal, state, tribal, regional and local laws and regulations governing, among other factors, worker safety and health, the discharge and disposal of substances into the environment, and the protection of the environment and natural resources. Numerous governmental entities, including the EPA and analogous state and local agencies, (and, under certain laws, private individuals) have the power to enforce compliance with these laws and regulations and any permits issued under them. These laws and regulations may, among other things: (i) require permits to conduct exploration, drilling, water withdrawal, wastewater disposal and other production related activities; (ii) govern the types, quantities and concentrations of substances that may be disposed or released into the environment or injected into formations in connection with drilling or production activities, and the manner of any such disposal, release, or injection; (iii) limit or prohibit construction or drilling activities or require formal mitigation measures in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; (iv) require investigatory and remedial actions to mitigate pollution conditions arising from the Company’s operations or attributable to former operations; (v) impose safety and health restrictions designed to protect employees and others from exposure to hazardous or dangerous substances; and (vi) impose obligations to reclaim and abandon well sites and pits. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial or corrective action obligations, the occurrence of delays or restrictions in permitting or performance of projects and the issuance of orders enjoining operations in affected areas.

The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect human health or the environment. Any issuance of new environmental laws or regulations or changes in or more stringent enforcement of existing environmental laws and regulations that result in delays or restrictions in permitting or development of projects or more stringent or costly compliance or cleanup obligations related to construction, drilling, water management, or well-completion activities or waste handling, storage, transport, remediation, disposal or discharge requirements could have a material adverse effect on the Company. Further, we may be unable to pass on increased environmental compliance costs to our customers. Moreover, accidental releases, including spills, may occur in the course of our operations, and there can be no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property and natural resources or personal injury. The cost of compliance with existing environmental laws and regulations and compliance with existing environmental permitting requirements could have an adverse material effect on the Company. The Company could incur substantial costs in the future related to revised or additional environmental laws and regulations or permitting requirements that could have a material adverse effect on our business, financial condition, and results of operations.

Hazardous Substances and Wastes

We currently own, lease, or operate, and in the past have owned, leased, or operated, sold or transferred properties that have been used in the exploration and production of oil and natural gas. We believe we have

utilized operating and disposal practices that were standard in the industry at the applicable time, but hazardous substances, hydrocarbons, and wastes may have been disposed or released on, from or under the properties owned, leased, or operated by us or on or under other locations where these substances and wastes have been taken for treatment, storage, or disposal. In addition, certain of these properties have been operated by third parties whose storage, treatment and disposal or release of hazardous substances, hydrocarbons, and wastes were not under our control. These properties and the substances or wastes that may have been generated, stored, transported, treated, disposed or released on them may be subject to various federal and/or state environmental laws. Under applicable laws, we could be required to investigate, monitor, remove or remediate previously disposed or released substances or wastes (including substances or wastes disposed of or released by prior owners or operators or third parties whose waste was commingled with ours), to investigate and clean up contaminated property, to perform corrective actions, to prevent future contamination, or to pay some or all of the costs of any such action.

State and Other Regulation

The states in which we operate, along with some municipalities, regulate some or all of the following activities: the drilling for, and the production and gathering of, oil and natural gas, including requirements relating to drilling permits, the location, spacing and density of wells, unitization and pooling of interests, the method of drilling, casing and equipping of wells, the protection of fresh water sources, the orderly development of common sources of supply of oil and natural gas, the operation of wells, allowable rates of production, the use of fresh water in oil and natural gas operations, saltwater injection and disposal operations, the plugging and abandonment of wells and the restoration of surface properties, the prevention of waste of oil and natural gas resources, the protection of the correlative rights of oil and natural gas owners and, where necessary to avoid unfair, unjust or discriminatory service, the fees, terms and conditions for the gathering of natural gas. These regulations may affect the number and location of our wells and the amounts of oil and natural gas that may be produced from our wells and increase the costs of our operations. Moreover, obtaining or renewing permits and other approvals for operating on Native American lands can take substantial amounts of time and could result in increased costs or delays to our operations.

Hydraulic Fracturing

Hydraulic fracturing is a practice in the oil and natural gas industry used to stimulate production of natural gas and/or oil from low permeability subsurface rock formations. Oil and natural gas may be recovered from certain of our oil and natural gas properties through the use of hydraulic fracturing, combined with sophisticated drilling. Hydraulic fracturing, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted federal regulatory authority over certain aspects of the hydraulic fracturing process.

Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process but, at this time, federal legislation related to hydraulic fracturing appears uncertain. At the state level, some states, including Oklahoma and Kansas, have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, disclosure, operational or well construction requirements on hydraulic fracturing activities, or that prohibit hydraulic fracturing altogether. Local governments may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the local, state or federal level, our fracturing activities could become subject to additional permit and financial assurance requirements, more stringent construction requirements, increased reporting or plugging and abandoning requirements or operational restrictions and associated permitting delays and potential increases in costs. These delays or additional costs could adversely affect the determination of whether a well is commercially viable and could cause us to incur substantial compliance costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities.

Other Regulation of The Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state, local, and regional authorities, as well as Native American tribes. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, and Native American tribes are authorized by statute to issue rules and regulations affecting the oil and natural gas industry and its individual members, some of which carry substantial penalties for noncompliance. Although the regulatory burden on the oil and natural gas industry increases the Company’s cost of doing business and, consequently, affects its profitability, these burdens generally do not affect the Company any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The price of oil, natural gas and NGLs is not currently regulated and are made at market prices. Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas prices might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations.

Drilling and Production

Our operations are subject to various types of regulation at federal, state, local and Native American tribal levels that include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties, municipalities and Native American tribal areas where we operate regulate one or more of the following activities:

•

the location of wells;

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the method of drilling and casing wells;

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the timing of construction or drilling activities;

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the rates of production, or “allowables”;

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the use of surface or subsurface waters;

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the surface use and restoration of properties upon which wells are drilled;

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the plugging and abandoning of wells; and

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the notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. Pooling orders can alter the timing and manner of development. Regulatory changes to pooling standards could further increase the difficulty, cost or timing of obtaining pooling orders and could impede development plans. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas, and NGLs within its jurisdiction.

Various federal and state agencies impose significant financial assurance requirements on operators. The costs of bonding and financing assurance requirements are increasing significantly in some states, and these increased costs will likely make it more difficult to divest oil and gas properties in these states. Many state and local authorities also have extensive requirements and regulations for plugging and abandonment, decommissioning and site restoration, and compliance with these requirements could have a material adverse effect on our business, financial condition, and results of operations.

Natural Gas Sales and Transportation

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The transportation and sale for resale of oil and natural gas may be subject to federal and state regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters.

Other 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 several 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 “Acreage” or “Leasehold Acreage” means lands that are covered by an existing oil and gas lease.

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.

“Acreage” or “Leasehold Acreage” means lands that are covered by an existing oil and gas lease.

"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.

“Held by Production” or “HBP” means Acreage or Leasehold Acreage that is perpetuated beyond the expiration of the primary lease term by oil and gas production

"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.

“Shut-In Well” is a well that has been closed off and not currently producing oil or gas which could be due to numerous different reasons from operations issues to surface or downhole mechanical issues to economic reasons.

“TCF” means trillion cubic feet.

“TD” means total depth.

“TVD” means true vertical depth,

“Temporarily Abandoned Well” is a well that has been Shut-In and taken out of service for an extended period of time greater than 1 year.

“Undeveloped Acreage” is Leasehold Acreage that is subject to expire if a well is not drilled and commercial oil and gas production is not established prior to the expiration date of the oil and gas lease.

“Undrilled Acreage” is surplus HBP Leasehold Acreage outside the boundaries of a drilling, spacing or production unit.

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

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

Item 1A. Risk Factors

Risks Related Directly to Our Company.

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

We are exposed to global health, political, economic and market risks that are beyond our control, which could adversely and significantly affect our financial results, financial condition, results of operations, and capital requirements.

Prices for oil and natural gas fluctuate widely due to a number of factors that are beyond our control. Declines in oil and natural gas prices significantly affect our financial condition and results of operations. Our revenues, profitability and cash flow are highly dependent upon the prices we realize from the sale of oil, natural gas and NGLs. Historically, the markets for these commodities are very volatile. Prices for oil, natural gas and NGLs can move quickly and fluctuate widely in response to a variety of factors that are beyond our control. These factors include, among others:

the duration and economic and financial impact of epidemics, pandemics or other public health issues;

changes in regional, domestic and foreign supplies of, and consumer and industrial/commercial demand for oil and natural gas., as well as perceptions of supply of, and demand for, oil and natural gas generally;

domestic and international drilling activity;

the price and quantity of foreign imports;

anticipated future prices of oil and natural gas, alternative fuels and other commodities;

the amount of exports from the U.S.;

the level of global and U.S. inventories and reserves;

weather conditions and seasonal trends;

natural disasters and other extraordinary events;

U.S. and worldwide political and economic conditions, including but not limited to, the imposition of tariffs or trade or other economic sanctions, including political instability or armed conflict and related sanctions including, but not limited to, the conflicts in the Middle East, Ukraine and Iran, and political instability in Venezuela;

technological advances affecting energy consumption and energy supply;

domestic and foreign governmental regulations and taxation;

the strength or weakness of the U.S. dollar to other currencies;

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

the availability, proximity, cost, and capacity of appropriate pipeline infrastructure, treating, 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, regulations and laws, and regulations with respect to the import and export of oil, and natural gas and related commodities

inflation and ability to acquire critical material, equipment or services in a timely or cost effective manner;

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

the availability of capital or level of hedging across the energy industry in the U.S. and internationally.

The above-described factors and the volatility of commodity prices make it difficult to predict oil and natural gas prices in 2026 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 2025, 2024, and 2023. 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 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, 2025, approximately 23% 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 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 currently not 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 currently 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. In addition, several seasoned employees as well as outside contractors have recently indicated that they plan to retire in the very near future which could result in a knowledge and experience gap that may be extremely difficult to replace. 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, significantly 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, including impairing our ability to prepare and file required financial and other reports. 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, 2025, hold approximately 89.42% 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.

Our common stock was downgraded to the Over-the-Counter Pink Limited market and is currently quoted on the OTC Pink Limited market, symbol "SPND". Recent Changes to OTC Markets could adversely affect trading of the Company’s stock:

Effective July 1, 2025, the Company’s stock was downgraded to the OTC Markets Pink Limited market. Now when someone goes to the OTC Markets website to get a quotation on the Company’s stock, the following is under the Company’s name and trading symbol with the term “Warning!” in bold and red print:

Warning! Limited Information

The Pink Limited Market is for broker-dealers to publicly quote securities with limited to no issuer involvement. Pink Limited companies do not certify their compliance with established reporting standards, have limited availability of disclosure or financial information and may not support their U.S. market. These securities are identified with a yield sign to warn investors to proceed with caution.

The downgrade of the Company’s stock to the OTC Markets Pink Limited market with the above Warning section and the cautionary Yield symbol will likely impact an investor’s ability to trade the Company’s stock.

The liquidity of our common stock will likely be affected, and purchasers of our common stock could have difficulty selling our common stock since our common stock has been transferred to the OTC Markets Pink Limited 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 ever develop.

It is likely that any market for our common stock will be highly volatile and that the trading volume in such market will be limited and controlled by broker-dealers setting what could be an arbitrary price for the Company’s stock.

Due to factors beyond our control, our stock price may be volatile:

Trading in our common stock is very limited and sporadic. Also, the OTC Pink Limited market is generally illiquid.

The trading price of our common stock also could be subject to fluctuations in response to quarter-to-quarter variations in our operating results, announcements of our drilling results, fluctuations in oil and natural gas prices, 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, 2025, 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. Any loss of leasehold interests, whether due to title defects, failure to maintain production, or the operation of the lease provisions, could have a material adverse effect on the Company’s business, financial condition and results of operations.

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, 2025, we had negative working capital of $404,000. 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, 2025, our oil and natural gas production is currently sold to approximately 89 purchasers/operators on a month-to-month basis at prevailing spot market prices. Oil prices remained subject to unpredictable political and economic forces during 2025, 2024, and 2023, and experienced fluctuations similar to those seen in natural gas prices for the year. We believe that oil prices will continue to fluctuate in response to changes in the policies of the Organization of Petroleum Exporting Countries ("OPEC"), changes in demand from many Asian countries, current events in the Middle East and Eastern Europe, security threats to the United States, and other factors associated with the world political and economic environment. As a result of the many uncertainties associated with levels of production maintained by OPEC and other oil producing countries, the availabilities of worldwide energy supplies and competitive relationships and consumer perceptions of various energy sources, we are unable to predict what changes will occur in crude oil and natural gas prices.

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

Our natural gas pipeline business involves 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 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.

Recently, the Company has experienced significant increases in costs and regulatory requirements of certain regulatory agencies relating to plugging and surface reclamation requirements. Regulatory agencies are significantly increasing plugging and surface reclamation requirements as well as placing greater pressure on operators to accelerate the plugging, abandonment, and surface site reclamation of shut-in wells compared to prior years.

Some regulatory agencies are significantly increasing the amounts of required plugging bonds, letters of credit, and other deposits. Based on the above, in 2025, the Company adjusted upwards the amount of estimated plugging, abandonment, and surface site reclamation costs. Based on our experience, we anticipate that in most cases, the costs of plugging such properties will range from $60,000 to $250,000 or more per well. This may not include land reclamation requirements that could cost as much or more than the plugging costs. In addition, abandonment costs and their timing may change due to many factors, including actual production results, inflation rates and changes in environmental laws and regulations.

Risks that Involve the Oil 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 against many, but not all, such losses and liabilities in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable. However, the occurrence of any of these events and any losses or liabilities incurred as a result of such events, if uninsured or in excess of our insurance coverage, would reduce the funds available to us for our operations and could, in turn, have a material and adverse effect on our business, financial condition and results of operations. 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 could be materially and adversely affected by security threats, including cybersecurity threats, and other disruptions. As an oil and gas producer, we face various security threats, including (i) cybersecurity threats to gain unauthorized access to, or control of, our sensitive information or to render our data or systems corrupted or unusable; (ii) threats to the security of our facilities and infrastructure or to the security of third-party facilities and infrastructure, such as gathering, transportation, and processing facilities; and (iii) threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material and adverse effect on our business. We rely extensively on information technology systems, including internally developed databases, data hosting platforms, real-time data acquisition systems, third-party software, cloud services and other internally or externally hosted hardware and software platforms, to (i) estimate our oil and gas reserves, (ii) process and record financial and operating data, (iii) process and analyze all stages of our business operations, including drilling, completion, production, gathering and processing, transportation, pipelines and other related activities and (iv) communicate with our employees and vendors, suppliers and other third parties. Further, our reliance on technology has increased due to the increased use of personal devices and remote communications. Although we have implemented and will continue to implement controls and procedures that are designed to protect our systems, identify and remediate vulnerabilities in our systems and related infrastructure and monitor and mitigate the risk of data loss and other cybersecurity threats, such measures cannot entirely eliminate cybersecurity threats and the controls and procedures we have implemented may prove to be ineffective. Our systems and networks, and those of our business associates, may become the target of cybersecurity attacks, including, without limitation, denial-of-service attacks; malicious software; data privacy breaches by employees, insiders or others with authorized access; cyber or phishing-attacks; ransomware; attempts to gain unauthorized access to our data and systems; and other electronic security breaches. If any of these security breaches were to occur, we could suffer disruptions to our normal operations, including our drilling, completion, production and corporate functions, which could materially and adversely affect us in a variety of ways, including, but not 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.

As cyber threats become more sophisticated and continue to evolve, including through the use of artificial intelligence (“AI”), we may be required to dedicate additional capital and technical resources to continue to modify or enhance our security measures, or to investigate and remediate any vulnerabilities to cyberattacks that are discovered, and these additional capital and technical resources needed may be difficult for our small company to handle. We may not have sufficient resources available to timely discover and remediate cybersecurity vulnerabilities. In addition, laws and regulations relating to cybersecurity, data privacy and protection and the unauthorized disclosure of confidential or protected information, including legislation in the United States and international jurisdictions, pose increasingly complex compliance challenges and potentially increase our costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability. Additionally, new regulations or legislation may affect our current uses of protected information and require us to modify how we collect, protect, process or disclose such information.

We are looking at the potential to utilize AI, machine learning, and automated decision making to improve our internal processes. Issues in the development and use of AI, combined with an uncertain regulatory environment, may result in new or enhanced governmental or regulatory scrutiny, litigation, confidentiality or security risks, reputational harm, liability or other adverse consequences to our business operations, all of which could adversely affect our business, financial condition and results of operations. The use of AI can lead to unintended consequences, including the unauthorized use or disclosure of confidential and proprietary information, or generating content that appears correct but is factually inaccurate, misleading, or otherwise flawed, which could expose us to risks related to inaccuracies or errors in the output of such technologies. It is not possible to predict all of the risks related to the use of AI, machine learning and automated decision making, and developments in the regulatory frameworks governing the use of such technologies and in related stakeholder expectations may adversely affect our ability to develop and use such technologies or subject us to liability.

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

Our insurance coverage may not be adequate to cover office costs associated with certain activities and events, and there can be no assurance that insurance coverage will continue to be available in the future on terms that we can afford or that can justify its purchase.

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. We maintain insurance against certain but not all of the risks and hazards that could occur with our operations. The Company maintains liability insurance and property insurance, but not all types of claims are covered by the insurance. In addition, our policies have deductibles and limits on the amounts of coverage in place. The occurrence of an event that is not insured or not fully insured could have a material adverse effect on the Company’s financial condition and results of operations in the future.

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.

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 which are operated by third parties over whom we have limited control. Notwithstanding our lack of control over properties operated by others, the failure of the previous owners or operators to comply with applicable environmental regulations may, in certain circumstances, adversely impact us.

Item 1B. Unresolved Staff Comments

None

Item 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 help 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 provided in conjunction with its cybersecurity insurance 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. The Company provides cybersecurity training for its employees through a third party.

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,
	2025		2024		2023
Gas and Oil Properties, net (1)
Proved developed gas reserves-Mcf (2)
Proved developed producing		2,415,000		1,664,000		1,648,000
Proved developed non-producing		—		—		—
Proved undeveloped gas reserves-Mcf (3)		—		—		—
Total proved gas reserves-Mcf		2,415,000		1,664,000		1,648,000

Proved Developed Crude Oil and
Condensate reserves-Bbls (2)
Proved developed producing		121,000		129,000		140,000
Proved developed non-producing		—		—		—
Proved Undeveloped crude oil and		—		—		—
Condensate reserves-Bbls (3)		—		—		—
		121,000		129,000		140,000

(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 2023 through 2025.

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

Producing Wells, Shut-In and Temporarily Abandoned Wells

The following table sets forth our domestic producing wells, shut-in and temporarily abandoned wells, and includes both operated and non-operated wells at December 31, 2025.

Producing		Producing
Gas Wells		Oil Wells		SI and TA Wells		Total Wells
Gross	Net	Gross	Net	Gross	Net	Gross	Net

107	30.54	87	13.77	103	62.74	297	107.05

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, 2025. 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 an oil and gas lease is included in the Developed Acreage category total shown below.

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

50,633	10,211	-	-	50,633	10,211

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. Therefore, the Company’s oil and gas properties and associated acreage are subject to customary risks associated with title defects and lease maintenance. Accordingly, there may be defects in title, competing claims, or other issues that could adversely affect the Company’s ownership interests in certain properties. In addition, a significant portion of our acreage is held by leases that are beyond their primary term and are maintained by production or other lease-saving provisions. These leases require ongoing compliance with specific terms and conditions, including the maintenance of production in paying quantities or satisfaction of continuous development or other contractual obligations. If production ceases or if we fail to meet these requirements, such leases may terminate, and we could lose the associated acreage. Further, certain provisions in our leases, including depth severances, retained acreage clauses, and continuous development requirements, may limit the extent of acreage that is held by production. These provisions may have already reduced, and may in the future further reduce, the amount of acreage we control. As a result, our effective acreage position may be smaller than our gross leasehold position, and additional acreage may expire over time if not properly maintained. Any loss of leasehold interests due to title defects, failure to comply with lease terms, or the operation of contractual provisions could have a material adverse effect on our business, financial condition, and results of operations.

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:

	2025				2024				2023
	Gross		Net		Gross		Net		Gross		Net

Exploratory Wells (1):
Productive		—		—		—		—		4.000		0.278
Non-Productive		—		—		—		—		—		—
Total		—		—		—		—		4.000		0.278

Developed Wells (2):
Productive		3.000		0.125		—		—		—		—
Non-Productive		—		—		—		—		—		—
Total		3.000		0.125		—		—		—		—

Total Exploration & Development Wells:
Productive		3.000		0.125		—		—		4.000		0.278
Non-Productive		—		—		—		—		—		—
Total		3.000		0.125		—		—		4.000		0.278

(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,
	2025		2024		2023		2022		2021

Oil and Gas Production, net:
Natural Gas (Mcf)		597,299		538,803		608,499		652,786		778,462
Crude Oil & Condensate (Bbl)		27,445		28,336		33,522		35,698		33,604

Average Sales Price per Unit Produced
Natural Gas (Mcf)	$	3.22	$	2.44	$	2.94	$	6.42	$	4.23
Crude Oil & Condensate (Bbl)	$	62.99	$	74.13	$	74.79	$	92.49	$	56.87

Average Production Cost per Equivalent Barrel (1) (2)	$	22.35		20.94	$	16.08	$	20.67	$	12.87

(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, 2025.

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 rental inquiries for its office building since the onset of the COVID pandemic in 2020. The Company believes that interest in rentals for space in the building has decreased due in part to remote work policies and in part due to the age and condition of the building.

The building is 43 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 Claiborne Parish, 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. This litigation was dismissed without prejudice as to the Company’s subsidiary on the plaintiff’s motion, by Order of Dismissal dated February 20, 2025.

On December 11, 2024, a subsidiary of the Company received notice of a new lawsuit filed in LaFourche Parish, Louisiana against one of the Company’s subsidiaries and numerous other oil and gas companies alleging pollution claims for properties operated by defendants in Louisiana and the Company’s subsidiary filed an answer. The litigation is in the early stages. Management is assessing the lawsuit, and it will have 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 plans to defend its subsidiary vigorously in this matter.

Item 4. Mine Safety Disclosures

Not Applicable

PART II

Item 5. Market for the Company's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

The Company's common stock is currently quoted and traded on the OTC Markets Pink market under the symbol "SPND".

Spindletop Oil & Gas Co. (SPND)

Warning! Limited Information

	Price Per Share
	High		Low

2026
First Quarter		6.00		2.75

2025
First Quarter	$	2.69	$	1.87
Second Quarter	$	3.05	$	2.01
Third Quarter	$	3.18	$	2.87
Fourth Quarter	$	5.80	$	2.27

2024
First Quarter	$	3.00	$	2.81
Second Quarter	$	3.10	$	2.71
Third Quarter	$	4.44	$	3.01
Fourth Quarter	$	4.00	$	1.60

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

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 reflects high and low trading prices for each quarter in 2025, 2024, and 2023 as aggregated by Yahoo!.com from various OTC sources.

The Company’s stock is no longer traded on OTC Markets Pink Current market, as it has been downgraded by OTC Markets to the OTC Pink Limited market. See Item 1A. Risk Factors above.

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

The 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, 2025, 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 $100.00 was invested on December 31, 2020, 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, however, from time to time, the Company has repurchased shares of its common stock including odd-lot holdings.

During the three-year period ending December 31, 2025, the Company made the following repurchases of its common stock:

Effective June 30, 2023, the Company repurchased 10,375 shares of its common stock from a non-controlling, unaffiliated shareholder of the Company for a negotiated purchase price of $30,000 or $2.89 per share. The repurchased shares are held as Treasury Stock.

Effective June 10, 2025, the Company repurchased 141,573 shares of its common stock from a non-controlling, unaffiliated shareholder of the Company for a negotiated purchase price of $351,101 or $2.48 per share. The repurchased shares are held as Treasury Stock.

Item 6. Selected Financial Data

[Reserved]

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, 2025.

Reserve estimates are prepared in accordance with standard Security and Exchange Commission guidelines. The estimated net future net cash flows for 2025, 2024, and 2023, 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, 2025, average quarterly crude oil prices per bbl for the Company were $72.85, $63.22, $63.02, and $58.77. During the year ended December 31, 2024, average quarterly crude oil prices per bbl for the Company were $72.96, $79.26, $74.56, and $68.22 respectively. During the year ended December 31, 2023, average quarterly crude oil prices per bbl for the Company were $73.44, $71.89, $72.66, and $77.73 respectively.

During the year ended December 31, 2025, average quarterly natural gas prices per mcf for the Company were $3.58, $2.94, $2.87, and $3.28. `During the year ended December 31, 2024, average quarterly natural gas prices per mcf for the Company were $2.73, $2.07, $2.24, and $2.45 respectively. During the year ended December 31, 2023, average quarterly natural gas prices per mcf for the Company were $3.70, $2.53, $2.49, and $2.63.

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 affect any acquisition.

Results of Operations

2025 Compared to 2024

Oil and natural gas revenues for the year ended December 31, 2025, were $3,829,000 compared to $3,659,000 for the year ended December 31, 2024, an increase of $170,000 or 4.65%.

Oil revenue for 2025 was approximately $1,908,000 compared to $2,346,000 for 2024, a decrease of approximately $438,000 or 18.67%. Oil sales decreased to approximately 27,400 barrels from approximately 28,300 barrels in 2024, a decrease of approximately 900 barrels or 3.18%. Oil prices decreased to an average of $62.99 per barrel in 2025 from an average of $74.13 per barrel in 2024, a decrease of $11.14 per barrel or 15.03%.

Natural gas revenue for 2025 was approximately $1,921,000 compared to $1,313,000 for 2024, an increase of approximately $608,000 or 46.31%. Natural gas sales were approximately 597,300 mcf in 2025, up from approximately 539,000 mcf in 2024, an increase of approximately 58,300 mcf or 10.82%. Natural gas prices increased to an average of $3.22 per mcf in 2025, an increase of $0.78 or 32.0% from an average of $2.44 per mcf in 2024.

Revenue from lease operations was approximately $175,000 for 2025, compared to approximately $168,000 in 2024, an increase of approximately $7,000 or 4.17%. 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 2025 were approximately $71,000, a decrease of approximately $51,000 or 41.80% from approximately $122,000 in 2024.

Real estate rental revenue for 2025 was approximately $288,000, an increase of approximately $33,000 or 12.94% from approximately $255,000 in 2024.

Interest income for 2025 was approximately $825,000, a decrease of $132,000 or 13.79% from $957,000 in 2024. Interest income is derived from investments in both short-term and long-term certificates of deposit as well as money market accounts at banks.

Miscellaneous Revenue for 2025 was $79,000, as compared to $51,000 in 2024, an increase of $28,000 or 54.90%.

Lease operating expenses in 2025 were $1,485,000 as compared to $1,841,000 in 2024, a net decrease of approximately $356,000, or 19.34%. 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 29% of the 2025 amount and 26% of the total 2024 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 2025 were approximately $574,000 compared to $633,000 in 2024, a decrease of approximately $59,000, or 9.32%.

Pipeline and rental expenses for 2025 were approximately $46,000 compared to approximately $19,000 for 2024, an increase of approximately $27,000, or 142.11%. Approximately $2,000 of this increase was for an increase of pipeline maintenance in 2024, and approximately $25,000 is due to increased compressor maintenance for the same period.

Real estate expenses in 2025 were approximately $194,000 compared to $135,000 during the same period in 2024, an increase of approximately $59,000 or 43.70%.

Depreciation and amortization expense for 2025 was $397,000 compared to $358,000 for 2024, an increase of approximately $39,000 or 10.89%. Amortization of the full cost pool for crude oil and natural gas assets for 2025 was $284,000, as compared to $240,000 for the year 2024, an increase of $44,000 or 18.33%. The Company re-evaluated its proved oil and gas reserves as of December 31, 2025, and increased its estimated total proved reserves by approximately 118,000 BOE to 524,000 BOE at the end of 2025 compared to 406,000 BOE at the end of 2024, an increase of approximately 29.06%

Asset Retirement Obligation (“ARO”) accretion expense for 2025 was $1,544,000 up from $100,000 in 2024, an increase of $1,444,000. 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 an 8.75% 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. The large increase in the 2025 provision is made in view of significant increases of plugging costs observed during 2025. In addition, regulatory agencies are increasing pressure on operators to plug and abandon wells faster than in prior years, as well as increasing the amounts of required plugging bonds, letters of credit, and other deposits. Based on the above management has determined that a significant increase in the amount of estimated plugging costs is required for the 2025 ARO estimate. Management will continue to review each year’s provision and estimate whether or not the liability to plug and abandon its wells in the future should be increased.

General and administrative expenses for 2025 were approximately $3,483,000 as compared to approximately $2,944,000 for 2024, an increase of approximately $539,000 or 18.31%. The increase is due primarily to a contribution of $500,000 to a non-qualified deferred compensation plan.

2024 Compared to 2023

Oil and natural gas revenues for the year ended December 31, 2024, were $3,659,000 compared to $4,502,000 for the year ended December 31, 2023, a decrease of $843,000 or 18.7%.

Oil revenue for 2024 was approximately $2,346,000 compared to $2,711,000 for 2023, a decrease of approximately $365,000 or 13.5%. Oil sales decreased to approximately 28,300 barrels from approximately 33,500 barrels in 2023, a decrease of approximately 5,200 barrels or 15.5%. Oil prices decreased to an average of $74.13 per barrel in 2024 from an average of $74.79 per barrel in 2023, a decrease of $0.66 per barrel or 0.89%.

Natural gas revenue for 2024 was approximately $1,313,000 compared to $1,791,000 for 2023, a decrease of approximately $478,000 or 26.7%. Natural gas sales were approximately 539,000 mcf in 2024 from approximately 608,500 mcf in 2023, a decrease of approximately 69,500 mcf or 11.4%. Natural gas prices decreased to an average of $2.44 per mcf in 2024, a decrease of $0.50 or 17.0% from an average of $2.94 per mcf in 2023.

In general, revenues from oil and natural gas producing operations experienced a decrease for the year ending December 31, 2024, as compared to the same period in 2023. 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 $168,000 for 2024, compared to approximately $156,000 in 2023, an increase of approximately $12,000 or 7.7%. 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 2024 were approximately $122,000, an increase of approximately $2,000 or 1.7% from approximately $120,000 in 2023.

Real estate rental revenue for 2024 was approximately $255,000, a decrease of approximately $15,000 or 5.6% from approximately $270,000 in 2023.

Interest income for 2024 was approximately $957,000, an increase of $196,000 or 25.8% from $761,000 in 2023. Interest income is derived from investments in both short-term and long-term certificates of deposit as well as money market accounts at banks.

Miscellaneous revenue for 2024 was $51,000, as compared to $57,000 in 2023, a decrease of $6,000 or 10.5%.

Lease operating expenses in 2024 were $1,841,000 as compared to $1,469,000 in 2023, a net increase of approximately $372,000, or 25.3%. 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 26% of the total 2024 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 2024 were approximately $633,000 compared to $701,000 in 2023, a decrease of approximately $68,000, or 9.7%. These expenses relate directly to the overall decrease in crude oil and natural gas production and revenues.

Pipeline and rental expenses for 2024 were approximately $19,000 compared to approximately $54,000 for 2023, a decrease of approximately $35,000, or 64.8%. Approximately $19,000 of this decrease was for an increase of pipeline maintenance in 2023, and approximately $14,000 is due to increased compressor maintenance for the same period.

Real estate expenses in 2024 were approximately $135,000 compared to $161,000 during the same period in 2023, a decrease of approximately $26,000 or 16.2%.

Depreciation and amortization expense for 2024 was $358,000 compared to $229,000 for 2023, an increase of approximately $129,000 or 56.3%. Amortization of the full cost pool for crude oil and natural gas assets for 2024 was $240,000, as compared to $134,000 for the year 2023, an increase of $106,000 or 79.1%. The Company re-evaluated its proved oil and gas reserves as of December 31, 2024, and decreased its estimated total proved reserves by approximately 9,000 BOE to 406,000 BOE at the end of 2024 compared to 415,000 BOE at the end of 2023, a decrease of approximately 2.2% 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 18 to the Financial Statements).

Asset Retirement Obligation (“ARO”) accretion expense for 2024 was $100,000 down from $509,000 in 2023, a decrease of $409,000. 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 will continue to review each year’s provision and estimate whether or not the liability to plug and abandon its wells in the future should be increased.

General and administrative expenses for 2024 were approximately $2,944,000 as compared to approximately $2,970,000 for 2023, a decrease of approximately $26,000 or 0.9%.

Item 8. Consolidated Financial Statements and

Schedules Index at Page 48

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

Management’s Report on Internal Control over Financial Reporting

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

Management assessed the effectiveness of the Company’s internal controls over financial reporting as of April 15, 2026. 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 April 15, 2026.

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

Changes in Internal Control over Financial Reporting

In preparation for management’s report on internal control over financial reporting, we documented and tested the design and operating effectiveness of our internal control over financial reporting. There were no changes in our internal controls over financial reporting (as such term is defined in Exchange Act Rule 13a-15(f)) that occurred during the quarter ended December 31, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

Not Applicable

PART III

Item 10. Directors, 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	68	Chairman of the Board, Director, and President

Michelle H. Mazzini	64	Director, Vice President, Secretary, and Treasurer

Ted R. Munselle	70	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.

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 once in 2025. 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 2025, 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 $496,551, $512,259, and $517,396, were paid to Mr. Mazzini in 2025, 2024, and 2023 respectively. Cash compensation including salaries and bonuses of $403,849, $407,377, and $416,223 were paid to Ms. Mazzini in 2025, 2024, and 2023 respectively.

The Company has no stock option plan and does not grant any stock-based awards or awards of equity securities. The Company recently created two nonqualified retention plans for some of its employees: a Nonqualified Deferred Compensation (“NQDC”) Plan for some of the executives and a Long-term Incentive Bonus (“LTIB”) Plan for some of its long-term employees. Both plans were created as retention incentives. See Note 4.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 2025, $10,000 in 2024 and $10,000 in 2023 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 15, 2026 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	)		89.42	%
12850 Spurling Rd., Suite 200
Dallas, Texas 75230

All officers and directors as a group		5,900,543					89.42	%

* “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 6,598,370 shares of Common Stock outstanding on December 31, 2025.

(1) Chris Mazzini directly owns 39,654 shares (0.6010%). Giant Energy Corp. directly owns 5,860,889 shares (88.8233%). Chris Mazzini owns 100% of the common stock of Giant Energy Corp.

Changes in Control

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

Item 13. Certain Relationships and Related Transactions and Director Independence

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. Amounts for the years ended December 31, 2025 and 2024 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 an Administrative Services 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"), a limited partnership in which Chris and Michelle Mazzini are limited partners, whereby Peveler pays the Company a monthly charge of $250.00 in exchange for the Company providing administrative services to Peveler. Peveler owns a pipeline gathering system servicing wells owned by NRG. 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 Co., LLC (“Reserve”) a limited liability company that holds some royalty interests, and that is 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. The Company entered into a similar agreement with Prism Acquisitions, LP (“PAL”) a limited partnership that holds some non-operated oil and gas interests, and that is owned by Chris and Michelle Mazzini. Pursuant to this agreement, PAL pays the Company a monthly fee in the amount of $200.00 for certain administrative services that the Company provides to PAL See also Footnote 5 to the Financial Statements.

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 2025 and 2024 by accounting firm, Farmer, Fuqua, & Huff, P.C.

Type of Fees	2025		2024

Audit Fees	$	61,000	$	50,040
Audit Related Fees		1,063		1,290
Tax Fees		13,000		13,000

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 2025 and 2024 were pre-approved by the Board or were within the pre-approved guidelines for permitted non-audit services and fees established by the Board, and there were no instances of waiver of approved requirements or guidelines during the same periods.

PART IV

Item 15. Exhibits and Financial Statement Schedules

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			60-62
Consolidated Balance Sheets			63-64
Consolidated Statements of Operations			65
Consolidated Statements of Changes in Stockholders' Equity			66
Consolidated Statements of Cash Flows			67
Notes to Consolidated Financial Statements			68


(2) FINANCIAL STATEMENT SCHEDULES:

Schedule II - Valuation and Qualifying Accounts			88
Schedule III - Real Estate and Accumulated Depreciation			89


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.

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 15, 2026

	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 15, 2026
Chris Mazzini	(Chief Executive Officer


/s/ Michelle Mazzini
	Vice President, Secretary,	April 15, 2026
Michelle Mazzini	Treasurer, Director


/s/ Ted R. Munselle
	Director	April 15, 2026
Ted R. Munselle


/s/ Robert E. Corbin	Principal Financial Officer	April 15, 2026
	and Accounting Manager
Robert E. Corbin

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

			Page

Report of Independent Registered Public Accounting Firm			60-62

Consolidated Balance Sheets - December 31, 2025 and 2024			63-64

Consolidated Statements of Operations for the years ended
December 31, 2025, 2024 and 2023			65

Consolidated Statements of Changes in Shareholders' Equity
for the years ended December 31, 2025, 2024 and 2023			66

Consolidated Statements of Cash Flows
for the years ended December 31, 2025, 2024 and 2023			67

Notes to Consolidated Financial Statements			68

Schedules for the years ended December 31, 2025, 2024 and 2023
II - Valuation and Qualifying Accounts			88
III - Real Estate and Accumulated Depreciation			89


All other schedules have been omitted because they are not applicable, not required, or the information has been supplied in the consolidated financial statements or notes thereto.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and

Shareholders of Spindletop Oil & Gas Co.

Opinion of the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Spindletop Oil & Gas Co. (A Texas Corporation) and subsidiaries as of December 31, 2025 and 2024, 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, 2025, 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, 2025 and 2024, and the results of operations and its cash flows for each of the three years in the period ended December 31, 2025, 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.

Accounting for asset retirement obligations

At December 31, 2025, the asset retirement obligation (ARO) balance totaled $5,884,000. 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.

Estimated proved reserves of oil and natural gas

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.

At December 31, 2025, the Company’s capitalized costs in the full cost pool were $967,000 net of amortization. The Company recorded amortization of $284,000 and no full-cost ceiling impairment was necessary. The Company reported a reserve value of $6,347,000 and $4,339,000, gross and net, respectively, of oil and natural gas properties as of December 31, 2025. 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. 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 15, 2026

782

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.

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

		December 31,			December 31,
		2025			2024

ASSETS

Current Assets
Cash and cash equivalents	$	3,641,000		$	6,472,000
Restricted cash		270,000			270,000
Accounts receivable		2,041,000			1,854,000
Income tax receivable		132,000			26,000
Other short-term investments		252,000			—
Total Current Assets		6,336,000			8,622,000

Property and Equipment - at cost
Oil and gas properties (full cost method)		27,568,000			26,490,000
Rental equipment		465,000			465,000
Gas gathering system		115,000			115,000
Other property and equipment		479,000			479,000
		28,627,000			27,549,000
Accumulated depreciation and amortization		(26,916,000	)		(26,586,000	)
Total Property and Equipment		1,711,000			963,000

Real Estate Property - at cost
Land		688,000			688,000
Commercial office building		1,925,000			1,925,000
Accumulated depreciation		(1,371,000	)		(1,304,000	)
Total Real Estate Property		1,242,000			1,309,000

Other Assets
Deferred Income Tax Asset		569,000			102,000
Other long-term investments		17,590,000			16,575,000
Other		3,000			3,000
Total Other Assets		18,162,000			16,680,000
Total Assets	$	27,451,000		$	27,574,000

The accompanying notes are an integral part of these statements.

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

		December 31,			December 31,
		2025			2024

LIABILITIES AND SHAREHOLDERS' EQUITY

Current Liabilities
Accounts payable and accrued liabilities	$	6,740,000		$	6,699,000
Total Current Liabilities		6,740,000			6,699,000

Noncurrent Liabilities
Other long-term liabilities		500,000			—
Asset retirement obligation		5,883,000			4,314,000
Total Noncurrent Liabilities		6,383,000			4,314,000

Total Liabilities		13,123,000			11,013,000

Shareholders' Equity
Common stock, $.01 par value, 100,000,000 shares authorized; 7,677,471 shares issued and 6,598,370 outstanding at December 31, 2025, and 6,739,943 outstanding at December 31, 2024.		77,000			77,000
Additional paid-in capital		943,000			943,000
Treasury stock, at cost		(2,270,000	)		(1,919,000	)
Retained earnings		15,578,000			17,460,000
Total Shareholders' Equity		14,328,000			16,561,000
Total Liabilities and Shareholders' Equity	$	27,451,000		$	27,574,000


The accompanying notes are an integral part of these statements.

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS



	Years Ended December 31,
	2025			2024			2023
Revenues
Oil and gas revenues	$	3,829,000		$	3,659,000		$	4,502,000
Revenue from lease operations		175,000			168,000			156,000
Gas gathering, compression, equipment rental		71,000			122,000			120,000
Real estate rental income		288,000			255,000			270,000
Miscellaneous revenue		79,000			51,000			57,000
Total Revenues		4,442,000			4,255,000			5,105,000

Expenses
Lease operations		1,485,000			1,841,000			1,469,000
Production taxes, gathering and marketing		574,000			633,000			701,000
Pipeline and rental operations		46,000			19,000			54,000
Real estate operations		194,000			135,000			161,000
Depreciation and amortization		397,000			358,000			229,000
ARO accretion expense		1,544,000			100,000			509,000
General and administrative		3,483,000			2,944,000			2,970,000
Total Expenses		7,723,000			6,030,000			6,093,000
Income (Loss) from operations		(3,281,000	)		(1,775,000	)		(988,000	)

Other Revenue and Expense
Interest income		825,000			957,000			761,000
Gain on sale of properties		—			—			104,000
Total Other Revenue and Expense		825,000			957,000			865,000

Income (loss) before income tax		(2,456,000	)		(818,000	)		(123,000	)

Current income tax provision (benefit)		(107,000	)		(127,000	)		(9,000	)
Deferred income tax provision (benefit)		(467,000	)		(62,000	)		(121,000	)
Total income tax provision (benefit)		(574,000	)		(189,000	)		(130,000	)
Net Income (Loss)	$	(1,882,000	)	$	(629,000	)	$	7,000

Earnings (Loss) per Share of Common Stock
Basic and Diluted	$	(0.28	)	$	(0.09	)	$	—

Weighted Average Shares Outstanding
Weighted Average Shares Outstanding Basic and Diluted		6,656,939			6,739,943			6,745,059

The accompanying notes are an integral part of these statements.

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

Net (Loss)		—		—		—		—		—			(629,000	)
Balance December 31, 2024		7,677,471	$	77,000	$	943,000		937,528	$	(1,919,000	)	$	17,460,000

Purchase of 141,573 shares of Common Stock as Treasury Stock		—		—		—		141,573		(351,000	)		—

Net (Loss)		—		—		—		—		—			(1,882,000	)
Balance December 31, 2025		7,677,471	$	77,000	$	943,000		1,079,101	$	(2,270,000	)	$	15,578,000


The accompanying notes are an integral part of these statements.

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Twelve Months Ended
	December 31,			December 31,
	2025			2024
Cash Flows from Operating Activities
Net (Loss)	$	(1,882,000	)	$	(629,000	)
Reconciliation of net (Loss) to net cash
provided by operating activities
Depreciation and amortization		397,000			358,000
Changes in asset retirement obligation		1,569,000			100,000
Changes in accounts receivable		(187,000	)		236,000
Changes in income tax receivable		(106,000	)		64,000
Changes in accounts payable and accrued liabilities		41,000			157,000
Changes in other long-term liabilities		500,000			—
Changes in deferred Income tax asset		(467,000	)		(62,000	)

Net cash provided (used) for operating activities		(135,000	)		224,000

Cash Flows from Investing Activities
Capitalized acquisition, exploration and development		(1,078,000	)		(602,000	)
Purchase of other short-term investments		(252,000	)		—
Changes in other long-term investments		(763,000	)		—
Capitalized tenant improvements and broker fees		—			(18,000	)
Increase in other assets		(252,000	)		—

Net cash provided (used) for Investing activities		(2,345,000	)		(620,000	)

Cash Flows from Financing Activities
Purchase of treasury stock		(351,000	)		—

Net cash used for financing activities		(351,000	)		—
(Decrease) in cash, cash equivalents, and restricted cash		(2,831,000	)		(396,000	)

Cash, cash equivalents, and restricted cash at beginning of period		6,742,000			7,138,000
Cash, cash equivalents, and restricted cash at end of period	$	3,911,000		$	6,742,000

The accompanying notes are an integral part of these statements.

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION AND ORGANIZATION

Merger and Basis of Presentation

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

Organization and Nature of Operations

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

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

The Company owns land along with a commercial office building which contains approximately 46,286 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.

Investments

Short-term and long-term investments consist of treasury bonds at fair market value (Level 1 in the hierarchy), mutual funds at fair market value (see Note 4) and certificates of deposit with maturities of more than three months with carrying amounts approximating fair value (Level 2 in the hierarchy). See below in Note 2 under heading Fair Value Measurements.

Allowance for Credit Losses

The Company provides an allowance for credit losses 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 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 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 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 sales occurred during the year ended December 31, 2023, The Company sold a property for approximately $104,000 for which there were no reserves included in the proved oil and gas reserves. At the recognition of the sale, the net unamortized full cost pool was approximately $545.000. 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 2025, 2024, or 2023 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.

	2025			2024

Carrying amount of asset retirement obligation	$	4,314,000		$	4,414,000
Liabilities added		70,000			400,000
Liabilities divested or settled		(44,000	)		(600,000	)
Current period accretion expenses		1,544,000			100,000
Carrying amount as of December 31,	$	5,884,000		$	4,314,000

Revenue Recognition

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

Income Taxes

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

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

Use of Estimates

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

Share-Based Payments

Effective January 1, 2006, the Company adopted ASC Topic 718-10, “Share-Based Payment". ASC Topic 718-10 requires compensation costs related to share-based payments to be recognized in the income statement over the requisite service period. The amount of 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

There are no new accounting pronouncements that were issued to be effective in 2025 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.

Fair Value Measurements

The Company measures certain financial assets and liabilities at fair value on a recurring basis. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company uses a three-level hierarchy to classify fair value measurements based on the observability of inputs used in the valuation:

Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities.
Level 2 — Fair values are based on inputs other than quoted price included within level 1 that are observable for valuing the asset or liability, either directly or indirectly (i.e., interest rate and yield curves observable at commonly quoted intervals, default rates, etc.). Observable inputs include quoted price for similar assets or liabilities in active or non-active markets. Level 2 inputs may also include insignificant adjustments to market observable inputs.
Level 3 — Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.

Subsequent Events

The Company has evaluated subsequent events through the issuance date of April 15, 2026.

3. ACCOUNTS RECEIVABLE

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.


	December 31,
	2025			2024

Trade	$	5,000		$	21,000
Accrued receivables		2,087,000			1,885,000
		2,092,000			1,906,000
Less: Allowance for losses		(51,000	)		(52,000	)
	$	2,041,000		$	1,854,000

4. NONQUALIFIED DEFERRED COMPENSATION PLAN – INVESTMENTS

In December 2025, the Company set up two retention plans for some long term employees and executives at the Company. A Nonqualified Deferred Compensation (“NQDC”) Plan was set up for its executives, and a Long-term Incentive Bonus (“LTIB”) Plan was set up for some long-term employees. Both plans were set up as retention incentives. In connection with the NQDC Plan and the LTIB Plan, (collectively, the NQDC Plan and the LTIB Plan are called the “NQ Plans”), The Company deposited $2,000,000 on December 22, 2025 with Principal Financial Group, to voluntarily fund these plans. These funds were invested through Principal Financial Group in a portfolio of mutual funds and are reflected on the consolidated balance sheet as Other Long-term Investments. The Company made an initial employer contribution to the NQDC Plan on December 25, 2025, and the Company will begin making awards under the LTIB Plan in 2026.

The investments are measured at fair value on a recurring basis. The following table presents the fair value of the NQ Plans investments by level within the fair value hierarchy as of December 31, 2025:

Description	Total Fair Value	Level 1	Level 2	Level 3
Mutual funds — equity	$1,371,600	$1,371,600	—	—
Mutual funds — fixed income	$ 628,400	$ 628,400	—	—
Stable value / collective investment fund	—	—	—	—

Total NQDC plan investments

Level 1 investments consist of publicly traded mutual funds for which quoted market prices are available in active markets. These are valued at the net asset value (NAV) per share as reported at the close of business on the measurement date.

Level 2 investments, if applicable, consist of [stable value or institutional collective investment funds] for which fair value is determined using observable inputs, including the fund's NAV as reported by the fund administrator, which is based on the fair value of the underlying assets.

There were no transfers between levels during the year ending December 31, 2025.

Related Balance Sheet Presentation

The Company's obligation to pay deferred compensation benefits to plan participants is recorded as a long-term liability titled Long-term Deferred Compensation Liability / Long-term Nonqualified Deferred Compensation Payable on the consolidated balance sheet totaling $500,000 as of December 31, 2025. The corresponding invested assets are classified separately and are not considered restricted, but are available to general creditors of the Company in the event of insolvency.

5. ACCOUNTS PAYABLE


	December 31,
	2025		2024

Trade payables	$	2,201,000	$	1,970,000
Production proceeds payable		3,456,000		3,392,000
Prepaid drilling costs		1,083,000		1,337,000
	$	6,740,000	$	6,699,000

6. RELATED PARTY TRANSACTIONS

7. COMMON STOCK

Effective January 1, 2006, the Company adopted ASC Topic 718-10, "Share-Based Payment". ASC Topic 718-10 requires compensation costs related to share-based payments to be recognized in the income statement over the requisite service period. The amount of 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, 2025, the Company did not issue any compensation related to share-based payments.

During the three-year period ending December 31, 2025, the Company made the following repurchases of its common stock:

8. INCOME TAXES

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

Income tax differed from the amounts computed by applying an effective United States federal income tax rate of 21% to pretax income in 2025, 2024, and 2023.

	2025			2024			2023
Computed expected tax expense (benefit)	$	(516,000	)	$	(172,000	)	$	(48,000	)

Miscellaneous timing differences
related to book and tax depletion differences
and the expensing of intangible drilling costs.		409,000			45,000			17,000
Gain on sale of oil and gas properties'		—			—			22,000

Expected Federal income tax expense (benefit)	$	(107,000	)	$	(127,000	)	$	(9,000	)

Income tax expense (benefit) for the years ended December 31, 2025, 2024 and 2023

		2025			2024			2023
Federal income taxes (benefit)	$	(107,000	)	$	(127,000	)	$	(9,000	)
State income taxes		—			—			—
Current income tax provision (benefit)	$	(107,000	)	$	(127,000	)	$	(9,000	)

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, 2025, and 2024 consisted of the following:

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,
	2025			2024
Deferred tax assets
Depletion and amortization		395,000			333,000
Depreciation		35,000			52,000
Expired leasehold		9,000			—
Net operating loss carryforward		136,000			—
Non-Qualified Deferred Compensation Plan		105,000			—
Total deferred tax assets		680,000			385,000

Deferred tax liabilities
Intangible drilling costs		(111,000	)		(283,000	)
Total deferred tax liability		(111,000	)		(283,000	)
Net deferred income tax asset (payable)	$	569,000		$	102,000

9. CASH FLOW INFORMATION

The Company does not consider any of its assets, other than cash and certificates of deposit shown as cash on the balance sheet, to meet the definition of a cash equivalent.

Net cash provided by operating activities includes cash payments for the following:

	2025		2024			2023

Income taxes	$-		$-			$-


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

		2025		2024			2023
Addition (Reduction) of oil & gas
properties by recognitions of
asset retirement obligation	$	25,000	$	(200,000	)	$	(251,000	)
	$	25,000	$	(200,000	)	$	(251,000	)



	2025		2024		2023
Proceeds from sales of oil and gas properties	$	—	$	—	$	104,000
Less:
Qualified Intermediary accounts receivable		—		—		—
	$	—	$	—	$	104,000

10. EARNINGS PER SHARE

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

11. CONCENTRATIONS OF CREDIT RISK

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, 2025, the Company had approximately $22,169,000 in checking, money market, certificates of deposit, treasury bonds, cash held by an investment company, and mutual funds. The Treasury Bond of approximately $252,000 is backed by the U.S. Government and is not insured. Mutual funds and cash held at an investment company of approximately $2,790,000 are not insured by the FDIC and are at risk as of December 31, 2025. Certificates of deposits held by various banks in excess of the $250,000 FDIC insured amount were approximately $1,500,00, and cash at banks in excess of the FDIC insured amount of $250,000 were approximately $1,528,000 at December 31, 2025.

Most of the Company's business activity is located in Texas. Accounts receivable as of December 31, 2025, and 2024, 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.

12. FINANCIAL INSTRUMENTS

The estimated fair value of the Company's financial instruments at December 31, 2025 and 2024 follows:


	2025				2024
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash	$	3,641,000	$	3,641,000	$	6,472,000	$	6,472,000
Restricted cash		270,000		270,000		270,000		270,000
Long-term investments		17,590,000		17,590,000		16,575,000		16,575,000
Accounts receivable		2,041,000		2,041,000		1,854,000		1,854,000
Short-term investments		252,000		252,000		—		—

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

13. COMMITMENTS AND CONTINGENCIES

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.

As of December 31, 2025, 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, 2028. The $10,000 bond is written for a one-year period and expired February 16, 2026. Subsequent to year-end, this bond has been extended through February 16, 2027.

The Company has six letters of credit from a bank issued for the benefit of various state regulatory agencies in New Mexico, Oklahoma, the U.S. Department of the Interior Bureau of Indian Affairs, and Louisiana, ranging in amounts from $20,000 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 eight additional letters of credit from one bank issued for the benefit of various state agencies in Texas and New Mexico ranging from $25,000 to $300,000 totaling $600,000. These letters of credit are secured by long-term certificates of deposit at the bank.

The Company received a notice letter from the Bureau of Land Management dated September 5, 2025 that their bonding requirement for a statewide bond in the state of New Mexico will increase to $500,000, effective June 22, 2026 and failure to comply may result in a shut down order, cancellation of leases and federal suspension or debarment. On December 18, 2025, the BLM announced that it had extended the requirement date to June 22, 2027.

14. ADDITIONAL OPERATIONS AND BALANCE SHEET INFORMATION

Certain information about the Company's operations for the years ended December 31, 2025, 2024 and 2023 follows.

Dependence on Purchasers and Operators

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 31,2025. The Company made sales of oil and natural gas to approximately 89 different purchasers / operators during 2025.

Purchaser / Operator	2025			2024			2023
Energy Transfer Crude		14	%		18	%		17	%
Merit Energy Company		13	%		1	%		—
Enlink Gas Marketing, LTD.		12	%		9	%		11	%
Bedrock Energy Partners		7	%		6	%		7	%

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,
	2025			2024			2023
Capitalized costs relating to oil and gas
producing activities:
Unproved properties	$	1,793,000		$	1,822,000		$	1,876,000
Proved properties		25,135,000			24,581,000			23,973,000
Total capitalized costs		26,928,000			26,403,000			25,849,000
Accumulated amortization		(25,961,000	)		(25,678,000	)		(25,438,000	)
Total capitalized costs, net	$	967,000			725,000		$	411,000


	Year Ended December 31,
	2025		2024		2023
Costs incurred in oil and gas property
Costs incurred in oil and gas property acquisitions, exploration and development:
Acquisition of properties	$	—	$	—	$	—
Development costs		478,000		298,000		565,000
Total costs incurred	$	478,000	$	298,000	$	565,000


	Year Ended December 31,
	2025		2024		2023
Results of operations from producing activities:
Sales of oil and gas	$	3,829,000	$	3,659,000	$	4,502,000

Production costs		2,059,000		2,473,000		2,170,000
Amortization of oil and gas properties		284,000		240,000		134,000
Total production costs		2,343,000		2,713,000		2,304,000
Total net revenue	$	1,486,000	$	946,000	$	2,198,000


	Year Ended December 31,
	2025		2024		2023
Sales price per equivalent Mcf	$	6.93	$	5.16	$	5.56
Production costs per equivalent Mcf	$	3.72	$	.49	$	.69
Amortization per equivalent Mcf	$	0.51	$	0.34	$	0.20

	Year Ended December 31,
	2025		2024		2023
Results of operations from gas gathering
and equipment rental activities:
Revenue	$	71,000	$	122,000	$	120,000
Operating expenses		46,000		19,000		54,000
Depreciation		3,000		3,000		4,000
Total costs		49,000		22,000		58,000
Total net revenue	$	22,000	$	100,000	$	62,000

15. 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 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, 2025:


	Year Ended December 31,
	2025		2024		2023
Revenues: (1)
Oil and gas exploration, production and operations	$	4,004,000	$	3,827,000	$	4,658,000
and operations
Gas gathering, compression and equipment rental		71,000		122,000		120,000
equipment rental
Real estate rental		288,000		255,000		270,000
Revenues	$	4,363,000	$	4,204,000	$	5,048,000

	Year Ended December 31,
	2025		2024		2023
Depreciation, depletion, and
amortization expense:
Oil and gas exploration, production and operations	$	327,000	$	283,000	$	155,000
and operations
Impairment of oil and gas assets		—		—		—
Gas gathering, compression and equipment rental		3,000		3,000		4,000
equipment rental
Real estate rental		67,000		72,000		70,000
	$	397,000	$	358,000	$	229,000

	Year Ended December 31,
	2025			2024			2023
Income (loss) from operations:
Oil and gas exploration, production and operations	$	74,000		$	970,000		$	1,824,000
and operations
Gas gathering, compression and equipment rental		22,000			100,000			62,000
equipment rental
Real estate rental		27,000			48,000			39,000
		123,000			1,118,000			1,925,000
Corporate and other (2)		(2,005,000	)		(1,747,000	)		(1,918,000	)
Consolidated net income (loss)	$	(1,822,000	)	$	(629,000	)	$	7,000


	Year Ended December 31,
	2025		2024		2023
Identifiable assets net of DDA:
Oil and gas exploration, production
Oil and gas exploration, production and operations	$	1,648,000	$	897,000	$	777,000
Gas gathering, compression and
Gas gathering, compression and equipment rental		47,000		50,000		53,000
Real estate rental		1,242,000		1,309,000		1,363,000
		2,937,000		2,256,000		2,193,000
Corporate and other (3)		24,514,000		25,318,000		25,953,000
Consolidated total assets	$	27,451,000	$	27,574,000	$	28,146,000

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.

16. SUPPLEMENTARY INCOME STATEMENT INFORMATION

The following items were charged directly to expense:


	Year Ended December 31,
	2025		2024		2023
Maintenance and repairs	$	46,000	$	19,000	$	54,000
Production taxes		157,000		154,000		208,000
Taxes, other than payroll and income taxes		20,000		22,000		20,000

17. QUARTERLY DATA (UNAUDITED)

The table below reflects selected quarterly information for the years ended December 31, 2025, 2024 and 2023.

QUARTERLY DATA (UNAUDITED)
	Year Ended December 31, 2025
		First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenue	$	1,195,000		$	1,040,000		$	958,000			1,249,000
Expense		(1,236,000	)		(1,308,000	)		(1,248,000	)		(3,931,000	)
Operating income (loss)		(41,000	)		(268,000	)		(290,000	)		(2,682,000	)
Other revenues		208,000			212,000			208,000			197,000
Net income (loss)		167,000			(56,000	)		(82,000	)		(2,485,000	)
Current tax (provision) benefit		(13,000	)		(1,000	)		14,000			107,000
Deferred tax (provision) benefit		(4,000	)		(13,000	)		277,000			207,000
Net income (loss)	$	150,000		$	(70,000	)	$	209,000		$	(2,171,000	)
Earnings (loss) per share of
common stock
Basic and diluted	$	0.02		$	(0.01	)	$	0.03		$	(0.32	)


	Year Ended December 31, 2024
		First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenue	$	1,021,000		$	1,116,000		$	888,000			1,230,000
Expense		(1,167,000	)		(1,561,000	)		(1,081,000	)		(2,221,000	)
Operating income (loss)		(146,000	)		(445,000	)		(193,000	)		(991,000	)
Other revenues		227,000			243,000			251,000			236,000
Net income (loss)		81,000			(202,000	)		58,000			(755,000	)
Current tax (provision) benefit		(4,000	)		60,000			9,000			62,000
Deferred tax (provision) benefit		1,000			2,000			79,000			(20,000	)
Net income (loss)	$	78,000		$	(140,000	)	$	146,000		$	(713,000	)
Earnings (loss) per share of
common stock
Basic and diluted	$	0.01		$	(0.02	)	$	0.02		$	(0.10	)


	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	)

18. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)

The Company’s net proved oil and natural gas reserves as of December 31, 2025, 2024, and 2023, 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 2025, 2024, and 2023 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, 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
Sales of reserves in place		—			—
Acquired properties		480			224,730
Extensions and discoveries		4,400			41,300
Revisions of previous estimates *		12,326			289,053
Production		(28,336	)		(538,803	)
Balance December 31, 2024		128,740			1,664,120
Sales of reserves in place		—			—
Acquired properties		—			—
Extensions and discoveries		1,677			3,799
Revisions of previous estimates *		18,498			1,344,800
Production		(27,445	)		(597,299	)
Balance December 31, 2025		121,470			2,415,420

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 2025, 2024, and 2023, was computed using a 12-month average price, calculated as the un-weighted arithmetic average of the first-day-of-the month price for each month of the year. Lease operating costs, compression, dehydration, transportation, ad valorem taxes, severance taxes, and federal income taxes were deducted. Costs and prices were held constant and were not escalated over the life of the properties. No deduction has been made for interest. The annual discount of estimated future cash flows is defined, for use herein, as future cash flows discounted at 10% per year, over the expected period of realization.

Proved Developed Reserves were calculated based on Decline Curve Analysis on operated wells and non-operated wells; however, non-operated wells that were materially insignificant 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,
	2025			2024			2023
Future production revenue	$	15,635,000		$	13,693,000		$	15,188,000
Future development costs		—			—			—
Future production costs		(9,288,000	)		(7,974,000	)		(8,294,000	)
Future net cash flow before Federal income taxes		6,347,000			5,719,000			6,894,000
Future income taxes		(952,000	)		(858,000	)		(1,034,000	)
Future net cash flows		5,395,000			4,861,000			5,860,000
Effect of 10% annual discounting		(1,056,000	)		(797,000	)		(1,041,000	)
Standardized measure of discounted cash flows	$	4,339,000		$	4,064,000		$	4,819,000

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

	Year Ended December 31,
	2025			2024			2023
Future production revenue	$	4,064,000		$	4,819,000		$	13,465,000

Sales of oil and gas, net of production costs		(1,684,000	)		(1,144,000	)		(2,219,000	)
Net changes in prices and production costs		789,000			(398,000	)		(6,996,000	)
Extensions, discoveries, additions less related costs		75,000			177,000			330,000
Development costs incurred		59,000			86,000			538,000
Revision of previos quantity estimates		449,000			307,000			(885,000	)
Net change in purchase and sales of minerals in place		(15,000	)		106,000			1,000
Net change in income taxes		(46,000	)		43,000			(76,000	)
Accretion of discount		406,000			482,000			1,347,000
Other		242,000			(414,000	)		(686,000	)
	$	4,339,000		$	4,064,000		$	4,819,000

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DECEMBER 31, 2025, 2024, AND 2023

SCHEDULE II

		Balance		Costs & Expenses		Deductions		Ending Balance
Allowance for credit losses

December 31, 2025	$	52,000	$	—	$	1,000	$	51,000

December 31, 2024	$	15,000	$	37,000	$	—	$	52,000

December 31, 2023	$	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	$ 628,000

Gross amounts at which carried at close of year

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

$ 688,000	$1,926,000	$ 2,614,000	$ 1,371,000	(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

Schedule IIIa

(c) The reconciliation for investments in real estate and accumulated depreciation for the years ended December 31, 2025 are as follows

	Investments in Real Estate		Accumulated Depreciation
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
Acquisitions		19,000
Depreciation expense				72,000
Balance, December 31, 2024		2,614,000		1,304,000
Acquisitions
Depreciation expense				67,000
Balance, December 31, 2025		2,614,000		1,371,000

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

For the Years Ended December 31, 2025, 2024, and 2023

SPINDLETOP OIL & GAS CO 10-K