UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

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

THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED September 30, 2015

or

[ ] 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)

(972-644-2581)

(Registrant’s telephone number, including area code)

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 (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 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 (§ 232.405 of this chapter) during the preceding 12 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 is a large accelerated filer, an accelerated filer, a

non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act).

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the

Exchange Act. Yes [ ] No [ X ]

APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY

PROCEEDINGS DURING THE PRECEEDING FIVE YEARS:

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of 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 ISSUERS:

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

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES

FORM 10-Q

For the quarter ended September 30, 2015

Index to Consolidated Financial Statements and Schedules

Part I - Financial Information

Item 1. - Financial Statements

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS - (Continued)

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

SPINDLETOP OIL & GAS CO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. BASIS OF PRESENTATION AND ORGANIZATION

The accompanying financial statements are presented in accordance with the requirements of Form 10-Q and consequently do not include all of the disclosures normally required by generally accepted accounting principles or those normally made in the Company's annual Form 10-K filing. Accordingly, the reader of this Form 10-Q may wish to refer to the Company's Form 10-K for the year ended December 31, 2014 for further information.

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

In the opinion of management, the accompanying unaudited interim financial statements contain all material adjustments, consisting only of normal recurring adjustments necessary to present fairly the financial condition, the results of operations and changes in cash flows of the Company and its consolidated subsidiaries for the interim periods presented. Although the Company believes that the disclosures are adequate to make the information presented not misleading, certain information and footnote disclosures, including a description of significant accounting policies normally included in financial statements prepared in accordance with generally accepted accounting principles generally accepted in the United States of America, have been condensed or omitted pursuant to such rules and regulations.

Subsequent Events

Management has evaluated subsequent events through November 16, 2015, the date on which the financial statements were available to be issued.

Item 2. - Management's Discussion and Analysis of Financial Condition and

Results of Operations

WARNING CONCERNING FORWARD LOOKING STATEMENTS

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-Q 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, which investors should review. There have been no changes from the risk factors previously described in the Company’s Form 10-K for the fiscal year ended December 31, 2014 (the “Form 10-K”).

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

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

Oil and Gas Properties

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

a)     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

b)    The cost of properties not being amortized; plus

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

d)    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 of 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 will prepare its annual Reserve Report as of December 31, 2015.

Reserve estimates are prepared in accordance with standard Security and Exchange Commission guidelines. The estimated net future net cash flows for 2014, 2013, and 2012, 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, or general corporate overhead. The annual discount of estimated future cash flows is defined, for use herein, as future cash flows discounted at 10% per year, over the expected period of realization. No impairment of oil and gas properties charge was recorded for 2014, 2013 or 2012.

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 third quarter of 2014, oil and gas prices started to decline worldwide. The Company has experienced a similar decline in the selling prices of its products as follows: Average quarterly crude oil prices per bbl for the year ended December 31, 2014 were $113.76, $100.55, $98.05, and $83.03 respectively. Average quarterly natural gas prices per Mcf for the year ended December 31, 2014 were $4.64, $4.71, $4.45, and $4.06. During the first three quarters of 2015, average quarterly crude oil prices per bbl were $46.33, $54.48, and $45.68, respectively. Average quarterly natural gas prices per Mcf for the same periods were $2.67, $2.46, and $2.31, respectively.

The 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 2015 if prices do not increase. The possibility and amount of any future impairment is difficult to predict, and will depend, in part, upon future crude oil and natural gas prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs. We cannot assure you that we will not experience write-downs in the future. If commodity prices decline or if any of our proved reserves are revised downward, a write-down of the carrying value of our oil and gas properties may be required.

Results of Operations

Nine months ended September 30, 2015 compared to nine months ended September 30, 2014

Oil and gas revenues for the first nine months of 2015 were $3,712,000, as compared to $9,385,000 for the same period in 2014, a decrease of approximately $5,673,000 or 60.5%.

Natural gas revenue for the first nine months of 2015 was $1,289,000 compared to $2,597,000 for the same period in 2014, a decrease of approximately $1,308,000, or 50.4%. Natural gas sales volumes for the first nine months of 2015 were approximately 508,000 mcf compared to approximately 558,000 mcf during the first nine months of 2014, a decrease of approximately 50,000 mcf or 9.0%.

Average natural gas prices received were $2.50 per mcf in the first nine months of 2015 as compared to $4.67 per mcf in the same time period in 2014, a decrease of approximately $2.17 per mcf or 46.5%.

Oil sales for the first nine months of 2015 were approximately $2,423,000 compared to approximately $6,788,000 for the first nine months of 2014, a decrease of approximately $4,365,000 or 64.3%. Oil sales volumes for the first nine months of 2015 were approximately 49,700, compared to approximately 69,000 bbls during the same period in 2014, a decrease of approximately 19,300 bbls, or 28.0%.

Average oil prices received were $46.74 per bbl in the first nine months of 2015 compared to $94.40 per bbl in the first nine months of 2014, a decrease of approximately $47.66 per bbl or 50.5%.

See the discussion of crude oil and natural gas prices under the topic “Oil and Gas Properties” on page 10 above.

Revenues from lease operations were $383,000 in the first nine months of 2015 compared to $382,000 in the first nine months of 2014, an increase of approximately $1,000 or 0.3%.

Revenues from gas gathering, compression and equipment rental for the first nine months of 2015 were $106,000 compared to $112,000 for the same period in 2014, a decrease of $6,000 or 5.4%. This decrease is due to the reduction in volumes of gas processed during the period.

Real estate revenue was approximately $168,000 during the first nine months of 2015 compared to $181,000 for the first nine months of 2014, a decrease of approximately $13,000, or 7.2%. The decrease is due to some tenant vacancies during 2015 compared to 2014.

Interest income was $66,000 during the first nine months of 2015 as compared to $89,000 during the same period in 2014, a decrease of approximately $23,000 or 25.8%. This decrease is due to changes in interest rates paid by financial institutions between the two periods.

Other revenues for the first nine months of 2015 were $68,000 as compared to $486,000 for the same time period in 2014, a decrease of $418,000 or 86.0%. This decrease was primarily due to farmout arrangements of some of the Company’s acreage during 2014. There were no farmout arrangements during the first nine months of 2015. From time to time, the Company farms out some of its leasehold acreage to non-affiliated third parties for exploration and development drilling. Generally, the Company receives a one-time payment for the agreement. The revenues from these farm-out agreements vary in size and frequency and should not be considered as regularly recurring revenues that the Company receives.

Lease operating expenses in the first nine months of 2015 were $1,769,000 as compared to $1,401,000 in the first nine months of 2014, a net increase of $368,000, or 26.3%. The prior period balance contains certain non-recurring expenses including approximately $96,000 from non-operated leases and approximately $84,000 in prior year credits for material transfers to inventory. Between periods, there were approximately $144,000 in increased workover expenses on operated properties, and $69,000 in additional expenses for wells that were plugged and abandoned. Workover expenses on non-operated properties decreased by approximately $16,000. Expenses for new operated and new non-operated properties increased approximately $35,000 and $8,000 respectively. The remaining $52,000 of the change represents net increases and decreases on various properties due to general price fluctuations and levels of operation activity.

Production taxes, gathering and marketing expenses in the first nine months of 2015 were approximately $443,000 as compared to $777,000 for the first nine months of 2014, a decrease of approximately $334,000, or 43.0%. These decreases related directly to the decline in oil and gas revenues as described in the above paragraphs.

Pipeline and rental expenses for the first nine months of 2015 were $28,000 compared to $35,000 for the same time period in 2014, a decrease of $7,000, or 20.0%. This decrease is primarily due to a decrease in repairs and maintenance expenses between the two periods.

Real estate expenses in the first nine months of 2015 were approximately $119,000 compared to $139,000 during the same period in 2014, a decrease of approximately $20,000 or 14.4%. This decrease is due primarily to lower utilities and maintenance and repair expenses.

Depreciation, depletion, and amortization expenses for first nine months of 2015 were $1,288,000 as compared to $1,482,000 for the same period in 2014, a decrease of $194,000, or 13.1%. $1,240,000 of the amount for the first nine months of 2015 was for amortization of the full cost pool of capitalized costs compared to $1,429,000 for the same period of 2014, a decrease of $189,000 or 13.2%. The Company re-evaluates its proved oil and natural gas reserve quantities on an annual basis as of December 31 of each year. This re-evaluated reserve base as of December 31, 2014 was adjusted for the first nine months as of September 30, 2015 by estimating variances in average prices of oil and natural gas that occurred during the period, adding estimated quantities of oil and natural gas reserves acquired during the period, and deducting oil and natural gas reserves that were produced or sold during the period. A depletion rate of 2.929% for the first quarter of 2015 a depletion rate of 2.795% for the second quarter of 2015, and a depletion rate of 2.975% for the third quarter of 2015 was calculated and applied to the Company’s full cost pool of capitalized oil and natural gas properties compared to rates of 3.270%, 3.804%, and 3.175% for the first three quarters of 2014 respectively.

Asset Retirement Obligation (“ARO”) expense for the first nine months of 2015 was approximately $31,000 as compared to approximately $88,000 for the same time period in 2014, a decrease of approximately $57,000 or 64.8%. This decrease is due to a recalculation of the estimated present value to plug producing properties compared to the estimate made in the previous year. This recalculation was made after the Company re-evaluated its proved oil and natural gas reserves at the end of 2014.

General and administrative expenses for the first nine months of 2015 were approximately $2,424,000 as compared to approximately $2,639,000 for the same time period of 2014, a decrease of approximately $215,000 or 8.2%. This decrease is primarily due to a reduction in spending for general office expenditures of approximately $51,000, with a reduction in direct personnel costs, salaries, and benefits of approximately $164,000.

Three months ended September 30, 2015 compared to three months ended September 30, 2014

Oil and natural gas revenues for the three months ended September 30, 2015 were $1,278,000, compared to $2,528,000 for the same time period in 2014, a decrease of $1,250,000, or 49.5%.

Natural gas revenue for the third quarter of 2015 was $403,000 compared to $849,000 for the same period in 2014, a decrease of $446,000 or 52.5%. Natural gas volumes sold for the third quarter of 2015 were approximately 163,000 mcf compared to approximately 178,000 mcf during the same period of 2014, an decrease of approximately 15,000 mcf, or 8.4%.

Average natural gas prices received were approximately $2.31 per mcf in the third quarter of 2015 as compared to approximately $4.45 per mcf during the same period in 2014, a decrease of approximately $2.14 or 48.1%.

Oil sales for the third quarter of 2015 were approximately $875,000 compared to approximately $1,679,000 for the same period of 2014, a decrease of approximately $804,000 or 47.9%. Oil volumes sold for the third quarter of 2015 were approximately 18,800 bbls compared to approximately 25,500 bbls during the same period of 2014, a decrease of 6,700 bbl or 26.3%.

Average oil prices received were approximately $45.68 per bbl in the third quarter of 2015 compared to $98.05 per bbl during the same period of 2014, a decrease of approximately $52.37 per bbl, or 53.41%.

See the discussion of crude oil and natural gas prices under the topic “Oil and Gas Properties” on page 10 above.

Revenues from lease operations for the third quarter of 2015 was approximately $139,000 compared to approximately $133,000 for the third quarter of 2014, an increase of approximately $6,000 or 4.5%. This increase is due primarily to increases in charges to field supervision. Operator overhead charged to the leases remained substantially the same.

Revenues from gas gathering, compression and equipment rental for the third quarter of 2015 were approximately $36,000, compared to approximately $40,000, a decrease of approximately $4,000 or 10.0% for the same period in 2014. This decrease is due to the reduction in volumes of gas processed during the period.

Real estate revenue was approximately $54,000 during the third quarter of 2015 compared to $60,000 for the same time period of 2014, a decrease of approximately $6,000 or 10.0%. The decrease is due to some tenant vacancies during 2015 compared to 2014.

Interest income for the third quarter of 2015 was approximately $14,000 as compared with approximately $36,000 for the same period in 2014, a decrease of approximately $22,000 or 61.11%. This decrease is due to changes in interest rates paid by financial institutions between the two periods.

Other revenues for third quarter of 2015 were approximately $30,000 as compared with approximately $377,000 for the same period in 2014, a decrease of approximately $347,000 or 92.0%. There were no farmout arrangements during the third quarter of 2015 compared to the third quarter of 2014. From time to time, the Company farms out some of its leasehold acreage to non-affiliated third parties for exploration and development drilling. Generally, the Company receives a one-time payment for the agreement. The revenues from these farm-out agreements vary in size and frequency and should not be considered as regularly recurring revenues that the Company receives.

Lease operating expenses in the third quarter of 2015 were $659,000 as compared to $341,000 in the third quarter of 2014, a net increase of approximately $318,000, or 93.2%.  This increase is due primarily to approximately $135,000 in increased workover expenses on operated properties and $95,000 for wells that were plugged and abandoned. There were approximately $23,000 in prior year credits for material transfers to inventory. Expenses for new operated properties increased approximately $6,000. The remaining $59,000 represents net increases and decreases on various properties due to general price fluctuations and levels of operation activity.

Production taxes, gathering, transportation and marketing expenses for the third quarter of 2015 were approximately $155,000 as compared to $238,000 during the third quarter of 2014, a net decrease of approximately $83,000 or 34.9%. This net decrease is directly related to the decline in oil and gas revenues as described in the above paragraphs.

Pipeline and rental expenses for the third quarter of 2015 were $9,000 compared to $8,000 for the same time period in 2014, an increase of $1,000 or 12.5%. This change is primarily due to the timing of repairs and maintenance expense.

Real estate expenses during the third quarter 2015 were approximately $38,000 compared to approximately $44,000 for the same period in 2014, a decrease of approximately $6,000 or 13.6%. This decrease is due primarily to a decrease in utilities and repairs.

Depreciation, depletion, and amortization expenses for the third quarter of 2015 were $451,000 as compared to $444,000 for the same period in 2014, an increase of $7,000, or 1.6%. $437,000 of the amount for the third quarter of 2015 was for amortization of the full cost pool of capitalized costs compared to $426,000 for the third quarter of 2014, an increase of $11,000 or 2.6%. The Company re-evaluates its proved oil and natural gas reserve quantities on an annual basis as of December 31 of each year. This re-evaluated reserve base as of December 31, 2014 was adjusted for the first nine months as of September 30, 2015 by estimating variances in average prices of oil and natural gas that occurred during the period, adding estimated quantities of oil and natural gas reserves acquired during the period, and deducting oil and natural gas reserves that were produced or sold during the period. A depletion rate of 2.929% for the first quarter of 2015, a depletion rate of 2.795% for the second quarter of 2015, and a depletion rate of 2.975% for the third quarter of 2015 was calculated and applied to the Company’s full cost pool of capitalized oil and natural gas properties compared to rates of 3.270%, 3.804%, and 3.175% for the first three quarters of 2014 respectively.

Asset Retirement Obligation (“ARO”) expense for the third quarter of 2015 was approximately $10,000 as compared to approximately $29,000 for the same time period in 2014, a decrease of approximately $19,000 or 65.5%. This decrease is due to a recalculation of the estimated present value to plug producing properties compared to the estimate made in the previous year. This recalculation was made after the Company re-evaluated its proved oil and natural gas reserves at the end of 2014.

General and administrative expenses for the third quarter of 2015 were $775,000 compared to $897,000 for the same period in 2014, a decrease of approximately $122,000 or 13.6%. The decrease is primarily due to lower salaries and benefits and contract labor, offset by higher franchise tax expense, in the third quarter of 2015 compared to the third quarter of 2014. This decrease is primarily due to a reduction in spending for general office expenditures of approximately $31,000, and a reduction in direct personnel costs, salaries, and benefits of approximately $91,000.

Financial Condition and Liquidity

The Company's operating capital needs, as well as its capital spending program are generally funded from cash flow generated by operations. Because future cash flow is subject to a number of variables, such as the level of production and the sales price of oil and natural gas, the Company can provide no assurance that its operations will provide cash sufficient to maintain current levels of capital spending. Accordingly, the Company may be required to seek additional financing from third parties in order to fund its exploration and development programs.

Item 4. - Controls and Procedures

(a) As of the end of the period covered by this report, Spindletop Oil & Gas Co. carried out an evaluation, under the supervision and with the participation of the Company's management, including the Company's Principal Executive Officer and Principal Financial and Accounting Officer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Exchange Act Rule 13a-15 and 15d-15. Based upon the evaluation, the Company's Principal Executive Officer and Principal Financial and Accounting Officer concluded that the Company's disclosure controls and procedures were effective as of the end of the period covered by the report.

(b) There have been no changes in the Company's internal controls over financial reporting during the quarter ended September 30, 2015 that have materially affected, or are reasonably likely to materially affect the Company's internal controls over financial reporting.

Part II – Other Information

Item 5. – Other Information

West Texas

The Company participated for a 2.62033% non-operated working interest with a 2.12903% net revenue interest in the drilling of the Moore Hooper #3H well located in the Phantom (Wolfcamp) field of Loving County, Texas. The well is a horizontal well targeting the Wolfcamp “A”. The well was spud on December 14, 2014, and surface casing was set and cemented at a depth of 4,215 ft. on December 23, 2014. The vertical and the curve portion of the well were then drilled and intermediate casing was set and cemented through the curve at a depth of 10,090 ft. on January 4, 2015 using a smaller rig. A larger rig was moved in and began drilling the lateral on April 29, 2015, and reached total measured depth of 16,160 ft. with a TVD of 10,800 ft. on May 16, 2015. On May 18, 2015, 4.5-inch casing was run to TMD of 16,099 ft. and cemented-in. The well was hydraulically fractured with 26 stages using the plug-n-perf method from June 11, 2015 through June 19, 2015, with 9,529,520 lbs of proppant, 3,345 bbls of acid, and 160,522 bbls of gel. The well had an initial potential of 1,620 bbls of oil, 4,255 mcf, and 4,420 bbls of water on July 16, 2015.

South Texas

Effective September 1, 2015, the Company divested its non-operated working interest of 7.599968% with a net revenue interest of 5.901747% in the Lehrer # 1 well. The well is a natural gas well that produces from the Wilcox in the Easter field in Colorado County, Texas.

Subsequent to the end of the third quarter, effective November 1, 2015, the Company sold eight (8) operated wells and one (1) salt water disposal well. The wells are located in Bee, Jackson & Victoria Counties, Texas.

For all of the above wells, the Company cautions that the initial production rates of a newly completed well or newly recompleted well or the production rates at the effective date of acquisition may not be an indicator of stabilized production rates or an indicator of the ultimate recoveries obtained.

Item 6. - Exhibits

The following exhibits are filed herewith or incorporated by reference as indicated.

Exhibit

Designation Exhibit Description

3.1 (a) Amended Articles of Incorporation of Spindletop Oil & Gas Co. (Incorporated by reference to Exhibit 3.1 to the 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. (Incorporated by reference to Exhibit 3.2 to the General Form for Registration of Securities on Form 10, filed with the Commission on August 14, 1990)

31.1 * Certification pursuant to Rules 13a-14 and 15d under the

Securities Exchange Act of 1934.

31.2 * Certification pursuant to Rules 13a-14 and 15d under the

Securities Exchange Act of 1934.

32.1 * Certification pursuant to 18 U.S.C. Section 1350.

____________________________

* filed herewith

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Exhibit 31.1

CERTIFICATION

I, Chris G. Mazzini, certify that:

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

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13-15(e) and 15d-15e) and have internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and have:

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

Exhibit 31.2

CERTIFICATION

I, Robert E. Corbin, certify that:

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

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13-15(e) and 15d-15e) and have internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and have:

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

Exhibit 32.1

Certification Pursuant to 18 U.S.C. Section 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Spindletop Oil & Gas Co. (the “Company”), on Form 10-Q for the quarter ended September 30, 2015 as filed with the Securities Exchange Commission on the date hereof (the “Report”), the undersigned Principal Executive Officer and Principal Financial and Accounting Officer of the Company, do hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.