10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the Fiscal Year Ended December 31, 2017

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

Commission File Number 0-8157

THE RESERVE PETROLEUM COMPANY

(Exact Name of Registrant as Specified in Its Charter)

DELAWARE	73-0237060
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)
6801 Broadway ext., Suite 300 Oklahoma City, Oklahoma 73116-9037 (405) 848-7551
(Address and telephone number, including area code, of registrant’s principal executive offices)

Securities registered under Section 12(b) of the Exchange Act: NONE

Securities registered under Section 12(g) of the Exchange Act:

COMMON STOCK ($0.50 PAR VALUE)

(Title of Class)

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.     ☐     Yes     ☑     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 registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     ☑     Yes     ☐     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     ☐     No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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 this Form 10-K or any amendment to this Form 10-K.     ☑

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

Large accelerated filer	☐		Accelerated filer	☐
Non-accelerated filer	☐	(Do not check if a smaller reporting company)
			Smaller reporting company	☑
			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 accounting standards provided pursuant to Section 13(a) 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

As of June 30, 2017 (the last business day of the registrant’s most recently completed second fiscal quarter), the aggregate market value of the voting and non-voting common stock of the registrant held by non-affiliates of the registrant was $25,095,004, as computed by reference to the last reported sale which was on June 28, 2017.

As of March 23, 2018, there were 157,599 shares of the registrant’s common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement (the “Proxy Statement”) relating to the registrant’s Annual Meeting of Shareholders to be held on May 22, 2018, which will be filed within 120 days of the end of the registrant’s year ended December 31, 2017, are incorporated by reference into Part III of this Form 10-K to the extent described therein.

TABLE OF CONTENTS

		Page
Forward-Looking Statements		3
PART I
Item 1.	Business	3
Item 1A.	Risk Factors	5
Item 1B.	Unresolved Staff Comments	5
Item 2.	Properties	5
Item 3.	Legal Proceedings	6
Item 4.	Mine Safety Disclosures	6
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	6
Item 6.	Selected Financial Data	7
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	7
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	13
Item 8.	Financial Statements and Supplementary Data	13
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	33
Item 9A.	Controls and Procedures	33
Item 9B.	Other Information	34
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	34
Item 11.	Executive Compensation	34
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	34
Item 13.	Certain Relationships and Related Transactions and Director Independence	34
Item 14.	Principal Accountant Fees and Services	34
PART IV
Item 15.	Exhibits and Financial Statement Schedules	35
Item 16.	Form 10-K Summary	35

2

Forward-Looking Statements

This Report on Form 10-K contains forward-looking statements. Actual events and/or future results of operations may differ materially from those contemplated by such forward-looking statements. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a summation of some of the risks and uncertainties inherent in forward-looking statements. Readers should consider the risks and uncertainties described in connection with any forward-looking statements that may be made in this Form 10-K. Readers should carefully review this Form 10-K in its entirety including, but not limited to, the Company's financial statements and the notes thereto and the risks and uncertainties described herein. Forward-looking statements contained in this Form 10-K speak only as of the date of this Form 10-K. The Company does not undertake to update its forward-looking statements.

PART I

Item 1. Business

Overview

The Reserve Petroleum Company (the “Company,” “we,” “our” or “us”) is engaged principally in managing its owned mineral properties and the exploration for and the development of oil and natural gas properties. Other business segments are not significant factors in our operations. The Company is a corporation organized under the laws of the State of Delaware in 1931.

Oil and Natural Gas Properties

For a summary of certain data relating to the Company’s oil and gas properties including production, undeveloped acreage, producing and dry wells drilled and recent activity, see Item 2, “Properties.” For a discussion and analysis of current and prior years’ revenue and related costs of oil and gas operations and a discussion of liquidity and capital resource requirements, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Owned Mineral Property Management

The Company owns non-producing mineral interests in 256,133 gross acres equivalent to 88,248 net acres. These mineral interests are located in nine different states in the north and south central United States. A total of 81,115 (92%) net acres are located in the states of Arkansas, Kansas, Oklahoma, South Dakota and Texas, the areas of concentration for the Company in our exploration and development programs.

The Company has several options relating to the exploration and/or development of our owned mineral interests. Management continually reviews various industry reports and other sources for activity (leasing, drilling, significant discoveries, etc.) in areas where the Company has mineral ownership. Based on our analysis of any activity and assessment of the potential risk relative to the particular area, management may negotiate a lease or farmout agreement and accept a royalty interest, or we may choose to participate as a working interest owner and pay our proportionate share of any exploration or development drilling costs.

A substantial amount of the Company’s oil and gas revenue has resulted from our owned mineral property management. In 2017, $1,737,841 (28%) of oil and gas sales was from royalty interests versus $1,487,173 (27%) in 2016. As a result of our mineral ownership, the Company had royalty interests in 15 gross (0.10 net) wells, which were drilled and completed as producing wells in 2017. This resulted in an average royalty interest of about 0.7% for these 15 new wells. The Company has very little control over the timing or extent of the operations conducted on our royalty interest properties. See the following paragraphs for a discussion of mineral interests in which the Company chooses to participate as a working interest owner.

Development Program

Development drilling by the Company is usually initiated in one of three ways. The Company may participate as a working interest owner with a third party operator in the development of non-producing mineral interests, which it owns; with a joint interest operator, we may participate in drilling additional wells on our producing leaseholds; or if our exploration program, discussed below, results in a successful exploratory well, we may participate in the drilling of additional wells on the exploratory prospect. In 2017, the Company participated in the drilling of 3 development wells with all 3 wells (0.35 net), including 2 wells in progress at year-end 2016, completed as producers.

Exploration Program

The Company’s exploration program is normally conducted by purchasing interests in prospects developed by independent third parties; participating in third party exploration of Company-owned non-producing minerals; developing our own exploratory prospects; or a combination of the above.

The Company normally acquires interests in exploratory prospects from someone in the industry with whom management has conducted business in the past and/or if management has confidence in the quality of the geological and geophysical information presented for evaluation to Company personnel. If evaluation indicates the prospect is within our risk limits, we may negotiate to acquire an interest in the prospect and participate in a non-operating capacity.

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The Company develops exploratory drilling prospects by identification of an area of interest, development of geological and geophysical information and purchase of leaseholds in the area. The Company may then attempt to sell an interest in the prospect to one or more companies in the petroleum industry with one of the purchasing companies functioning as operator. In 2017, we participated in the drilling of 14 exploratory wells with 4 wells (0.5 net) completed as producers, 3 wells in progress at the end of 2017 and 7 wells (0.95 net) completed as dry holes.

For a summation of exploratory and development wells drilled in 2017 or planned for in 2018, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” subheading “Update of Oil and Gas Exploration and Development Activity from December 31, 2016.”

Customers

In 2017, the Company had two customers whose total purchases were greater than 10% of revenues from oil and gas sales. Redland Resources, LLC purchases were $1,417,568 or 23% of total oil and gas sales and Luff Exploration Company purchases were $762,624 or 12% of total oil and gas sales. The Company sells most of its oil and gas under short-term sales contracts that are based on the spot market price.

Competition

The oil and gas industry is highly competitive in all of its phases. There are numerous circumstances within the industry and related market place that are out of the Company’s control such as cost and availability of alternative fuels, the level of consumer demand, the extent of other domestic production of oil and gas, the price and extent of importation of foreign oil and gas, the cost of and proximity of pipelines and other transportation facilities, the cost and availability of drilling rigs, regulation by state and federal authorities, and the cost of complying with applicable environmental regulations.

The Company does not operate any of the wells in which we have an interest; rather, we partner with companies that have the resources, staff, and experience to operate wells both in the drilling and production phases. The Company uses its strong financial base and its mineral and leasehold acreage ownership, along with its own geologic and economic evaluations, to participate in drilling operations with these companies. This methodology allows us to participate in exploration and development activities we could not undertake on our own due to financial and personnel limits and allows us to maintain low overhead costs.

Regulation

The Company’s operations are affected in varying degrees by political developments and federal and state laws and regulations. Although released from federal price controls, interstate sales of natural gas are subject to regulation by the Federal Energy Regulatory Commission (FERC). Oil and gas operations are affected by environmental laws and other laws relating to the petroleum industry, and both are affected by constantly changing administrative regulations. Rates of production of oil and gas have, for many years, been subject to a variety of conservation laws and regulations, and the petroleum industry is frequently affected by changes in the federal tax laws.

Generally, the respective state regulatory agencies supervise various aspects of oil and gas operations within their states and the transportation of oil and gas sold intrastate.

Environmental Protection and Climate Change

The operation of the various producing properties, in which the Company has an interest, is subject to federal, state, and local provisions regulating discharge of materials into the environment, the storage of oil and gas products, and the contamination of subsurface formations. The Company’s lease operations and exploratory activity have been and will continue to be affected by existing regulations in future periods. However, the known effect to date has not been material as to capital expenditures, earnings, or industry competitive position. Environmental compliance expenditures produce no increase in productive capacity or revenue and require more of management’s time and attention at a cost which cannot be estimated with any assurance of certainty.

In 2009, the EPA officially published its findings that greenhouse gas emissions present an endangerment to human health and the environment. According to the EPA, these emissions are contributing to global warming and climate change. These findings allowed the EPA to adopt and implement regulations in recent years to restrict these emissions under existing provisions of the Federal Clean Air Act.

The Company may be, directly and indirectly, subject to the effects of climate change and may, directly or indirectly, be affected by government laws and regulations related to climate change. We cannot predict with any degree of certainty what effect, if any, climate change and government laws and regulations related to climate change will have on the Company and our business, whether directly or indirectly. While we believe that it is difficult to assess the timing and effect of climate change and pending legislation and regulation related to climate change on our business, we believe that those laws and regulations may affect, directly or indirectly, (i) the costs associated with drilling and production operations in which we participate; (ii) the demand for oil and natural gas; (iii) insurance premiums, deductibles and the availability of coverage; and (iv) the cost of utilities paid by the Company. In addition, climate change may increase the likelihood of property damage and the disruption of operations of wells in which we participate. As a result, our financial condition could be negatively impacted, but we are unable to determine at this time whether that impact would be material.

Other Business

See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” subheading “Equity and Other Investments” and Item 8, Notes 2 and 7 to the accompanying financial statements for a discussion of other business including guarantees.

4

Employees

At December 31, 2017, the Company had nine employees, including officers. See the Proxy Statement for additional information. During 2017, all of our employees devoted a portion of their time to duties with affiliated companies, and we were reimbursed for the affiliates’ share of compensation directly from those companies. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” subheading “Certain Relationships and Related Transactions” and Item 8, Note 12 to the accompanying financial statements for additional information.

ITEM 1A. RISK FACTORS

Not applicable.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2. PropertIES

The Company’s principal properties are oil and natural gas properties. We have interests in approximately 900 producing properties with 39% of them being working interest properties and the remaining 61% being royalty interest properties. About 81% of all properties are located in Oklahoma and Texas and account for approximately 69% of our annual oil and gas sales. About 15% of the properties are located in Arkansas, Kansas and South Dakota and account for approximately 29% of our annual oil and gas sales. The remaining 4% of these properties are located in Colorado, Montana, and Nebraska and account for about 2% of our annual oil and gas sales. No individual property provides more than 10% of our annual oil and gas sales. See discussion of revenues from Robertson County, Texas, royalty interest properties in Item 7, “Operating Revenues” for additional information about significant properties.

OIL AND NATURAL GAS OPERATIONS

Oil and Gas Reserves

Reference is made to the Unaudited Supplemental Financial Information beginning on Page 28 for working interest reserve quantity information.

Since January 1, 2017, the Company has not filed any reports with any federal authority or agency, which included estimates of total proved net oil or gas reserves, except for its 2016 Annual Report on Form 10-K and federal income tax return for the year ended December 31, 2016. Those reserve estimates were identical.

Production

The average sales price of oil and gas production for the Company’s royalty and working interests, as well as the average working interest production cost (lifting cost) per equivalent thousand cubic feet (MCF) of gas, are presented in the table below for the years ended December 31, 2017, 2016 and 2015. Equivalent MCF was calculated using approximate relative energy content.

	Royalties				Working Interests
	Sales Price				Sales Price				Average Production
	Oil		Gas		Oil		Gas		Cost per
	Per Bbl		Per MCF		Per Bbl		Per MCF		Equivalent MCF
2017	$	47.95	$	2.91	$	46.00	$	2.91	$	2.25
2016	$	38.53	$	2.21	$	36.49	$	2.16	$	1.85
2015	$	47.57	$	2.46	$	43.09	$	2.53	$	1.93

At December 31, 2017, the Company had working interests in 200 gross (24.93 net) wells producing primarily gas and 234 gross (23.28 net) wells producing primarily oil. These interests were in 85,255 gross (9,779 net) producing acres. These wells include 49 gross (1.53 net) wells associated with secondary recovery projects.

Undeveloped Acreage

The Company’s undeveloped acreage consists of non-producing mineral interests and undeveloped leaseholds. The following table summarizes the Company’s gross and net acres in each at December 31, 2017.

	Acreage
	Gross	Net
Non-producing Mineral Interests	256,137	88,248
Undeveloped Leaseholds	86,717	14,490

5

Net Productive and Dry Wells Drilled

The following table summarizes the net wells drilled in which the Company had a working interest for the years ended December 31, 2015 and thereafter, as to net productive and dry exploratory wells drilled and net productive and dry development wells drilled. Net exploratory and development totals for 2017 include the 2 wells still drilling at the end of 2016. As indicated in the “Exploration Program” on Page 4, 3 exploratory wells were still in process at the time of this Form 10-K.

	Number of Net Working Interest Wells Drilled
	Exploratory				Development
	Productive		Dry		Productive		Dry
2017		0.50		0.95		0.35		---
2016		0.16		1.41		0.47		---
2015		0.61		0.78		0.68		---

Recent Activities

See Item 7, under the subheading “Update of Oil and Gas Exploration and Development Activity from December 31, 2016” for a summary of recent activities related to oil and natural gas operations.

ITEM 3. Legal Proceedings

There are no material legal proceedings pending affecting the Company or any of its properties.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

Item 5. Market for REGISTRANT’S Common Equity, Related Stockholder Matters AND ISSUER PURCHASES OF EQUITY SECURITIES

The Company’s stock is dually traded in the Pink Sheet Electronic Quotation Service and the OTC Bulletin Board under the symbol “RSRV.” The following high and low bid information was quoted on the Pink Sheets OTC Market Report. Prices reflect inter-dealer prices without retail markup, markdown, or commission and may not reflect actual transactions.

	Quarterly Ranges
Quarter Ending	High Bid		Low Bid
03/31/16	$	220	$	151
06/30/16	$	199	$	178
09/30/16	$	190	$	182
12/31/16	$	200	$	183
03/31/17	$	245	$	197
06/30/17	$	246	$	211
09/30/17	$	230	$	205
12/31/17	$	226	$	195

There was limited public trading in the Company’s common stock in 2017 and 2016. There were 5 brokered trades appearing in the Company’s transfer ledger for 2017 and 9 in 2016.

6

At March 23, 2018, the Company had approximately 1,847 record holders of its common stock. The Company paid dividends on its common stock in the amount of $5.00 per share in the second quarter of 2017 and in the second quarter of 2016. See the “Financing Activities” section of Item 7 below for more information about dividends paid. Management will review the amount of the annual dividend to be paid in 2018, if any, with the Board of Directors for its approval.

ISSUER PURCHASES OF EQUITY SECURITIES

Period	Total Number of Shares Purchased	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs1	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs1
October 1 to October 31, 2017	36	$	150	---	---
November 1 to November 30, 2017	7	$	150	---	---
December 1 to December 31, 2017	43	$	150	---	---
Total	86	$	150	---	---

¹The Company has no formal equity security purchase program or plan. The Company acts as its own transfer agent, and most purchases result from requests made by shareholders receiving small, odd lot share quantities as the result of probate transfers.

ITEM 6. SELECTED FINANCIAL DATA

Not applicable.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Please refer to the financial statements and related notes in Item 8 of this Form 10-K to supplement this discussion and analysis.

Forward-Looking Statements

In addition to historical information, from time to time the Company may publish forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements provide the reader with management’s current expectations of future events. They include statements relating to such matters as anticipated financial performance, business prospects such as drilling of oil and gas wells, technological development, and similar matters.

Although management believes that the expectations reflected in forward-looking statements are based on reasonable assumptions, a variety of factors could cause the Company’s actual results and experience to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance, development, and results of our business include, but are not limited to, the following:

● The Company’s future operating results will depend upon management’s ability to employ and retain quality employees, generate revenues, and control expenses. Any decline in operating revenues, without corresponding reduction in operating expenses, could have a material adverse effect on our business, results of operations, and financial condition.

● The Company has no significant long-term sales contracts for either oil or gas. For the most part, the price we receive for our product is based upon the spot market price, which in the past has experienced significant fluctuations. Management anticipates price fluctuations will continue in the future, making any attempt at estimating future prices subject to significant uncertainty.

● Exploration costs have been a significant component of the Company’s capital expenditures in the past and are expected to remain so in the near term. Under the successful efforts method of accounting for oil and gas properties which the Company uses, these costs are capitalized if drilling is successful or charged to operating costs and expenses if unsuccessful. Estimating the amount of future costs which may relate to successful or unsuccessful drilling is extremely imprecise at best.

The Company does not undertake any obligation to publicly revise forward-looking statements to reflect events or circumstances that arise after the filing date of this Form 10-K. Readers should carefully review the information described in other documents the Company files from time to time with the Securities and Exchange Commission, including the Quarterly Reports on Form 10-Q to be filed by the Company in 2018 and any Current Reports on Form 8-K filed by the Company.

Critical Accounting Estimates

● Estimates of future revenues from oil and gas sales are derived from a combination of factors which are subject to significant fluctuation over any given period of time. Reserve estimates, by their nature, are subject to revision in the short-term. The evaluating engineer considers production performance data, reservoir data, and geological data available to the Company, as well as makes estimates of production costs, sale prices, and the time period the property can be produced at a profit. A change in any of the above factors can significantly change the timing and amount of net revenues from a property. The Company’s producing properties are composed of many small working interest and royalty interest properties. As a non-operating owner, we have limited access to the underlying data from which working interest reserve estimates are calculated, and estimates of royalty interest reserves are not made because the information required for the estimation is not available to the Company. While reserve estimates are not accounting estimates, they are the basis for impairment, depreciation, depletion, and amortization described below. Additionally, the estimated economic life for each producing property from the reserve estimates is used in the calculation of asset retirement obligations.

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● The provisions for depreciation, depletion, and amortization of oil and gas properties all constitute critical accounting estimates. Non-producing leaseholds are amortized over the life of the leases using a straight line method; however, when leases are impaired or condemned, an appropriate adjustment to the provision is made at that time.

● The provision for impairment of long-lived assets is determined by review of the estimated future cash flows from the individual properties. A significant, unforeseen downward adjustment in future prices and/or potential reserves could result in a material change in estimated long-lived assets impairment.

● Depletion and depreciation of oil and gas properties are computed using the units-of-production method. A significant, unanticipated change in volume of production or estimated reserves would result in a material, unexpected change in the estimated depletion and depreciation provisions.

● The Company has significant obligations to remove tangible equipment and facilities associated with oil and gas wells and to restore land at the end of oil and gas production operations. Removal and restoration obligations are most often associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires estimates and judgments because most of the removal obligations will take effect in the future. Additionally, these operations are subject to private contracts and government regulations that often have vague descriptions of what is required. Asset removal technologies and costs are constantly changing as are regulatory, political, environmental, and safety considerations. Inherent in the present value calculations are numerous assumptions and judgments including the ultimate removal cost amounts, inflation factors, and discount rate.

● Oil and natural gas sales revenue accrual is another critical accounting estimate. The Company does not operate any of its oil and natural gas properties. Obtaining timely production data on all wells from the operators is not feasible; therefore, the Company utilizes past production receipts and estimated sales price information to estimate its accrual of revenue on all wells each quarter. The oil and natural gas sales revenue accrual can be impacted by many variables, including rapid production decline rates, production curtailments by operators, and rapidly changing market prices for oil and natural gas. These variables could lead to an over or under accrual of oil and natural gas sales at the end of any particular quarter. Based on past history, our estimated accrual has been materially accurate.

● The estimation of the amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations as well as the completion of complex calculations, including the determination of the Company’s percentage depletion deduction, if any. To calculate the exact excess percentage depletion allowance, a well-by-well calculation is, and can only be, performed at the end of each year. During interim periods, a high-level estimate is made taking into account historical data and current pricing. Although our management believes its income tax accruals are adequate, differences may occur in the future depending on the resolution of pending and new tax matters.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The Company is affiliated by common management and ownership with Mesquite Minerals, Inc. (Mesquite), Mid-American Oil Company (Mid-American) and Lochbuie Limited Liability Company (LLTD). The Company also owns interests in certain producing and non-producing oil and gas properties as tenants in common with Mesquite, Mid-American and LLTD.

Jerry Crow, a director of the Company, is a director of Mesquite and Mid-American. Kyle McLain and Cameron McLain are brothers and directors of the Company. Kyle McLain and Cameron McLain each own more than 7% of the common stock of the Company and are officers. Kyle McLain and Cameron McLain are officers and directors of Mesquite and Mid-American. Kyle McLain and Cameron McLain each own an approximate 11% interest in LLTD.

The above named officers, directors, and employees as a group beneficially own approximately 19% of the common stock of the Company, approximately 13% of the common stock of Mesquite, and approximately 10% of the common stock of Mid-American. Each of these three corporations have only one class of stock outstanding. See Item 8, Note 12 to the accompanying financial statements for additional disclosures regarding these relationships.

EQUITY AND OTHER INVESTMENTS

The Company has a 33% partnership interest in Broadway Sixty-Eight, Ltd. (the “Partnership”), which it accounts for on the equity method. In using the equity method, the Company records the original investment in an entity as an asset and adjusts the asset balance for the Company’s share of any income or loss, as well as any additional contributions to or distributions from the entity. The Company does not have actual or effective control of the Partnership. The management of the Partnership could, at any time, make decisions in their own best interests that could affect the Company’s net income or the value of the Company’s investment. The Company’s investment in the Partnership totaled $171,243 and $187,380 at December 31, 2017 and 2016, respectively.

The Partnership has an indemnity agreement under which the Company is contingently liable. See Item 8, Note 7 to the accompanying financial statements for related disclosures and additional information regarding Broadway Sixty-Eight, Ltd.

8

The Company’s Equity Investments also include a 47% ownership in Grand Woods Development, LLC (the “LLC”) an Oklahoma limited liability company acquired in November 2015. The LLC owns approximately 26.3 acres of undeveloped real estate in northeast Oklahoma City. The Company has guaranteed a loan for which the proceeds were used to purchase a portion of the undeveloped real estate acreage. The Company’s investment in the LLC totaled $544,603 and $635,190 at December 31, 2017 and 2016, respectively.

The Company’s Equity Investments also include a 20% ownership in QSN Office Park (“QSN”), an Oklahoma limited liability company acquired in March 2016. QSN is constructing and selling office buildings in a new office park. The Company’s investment in QSN totaled $275,248 and $280,000 at December 31, 2017 and 2016, respectively.

Other Investments are mostly investments in limited liability companies (“LLC’s”) with smaller ownership interests that do not allow the Company to significantly influence the operations or management of the LLC’s. These investments are recorded at cost and cash distributions from the investment are recognized as income when received. The names of these investments, including ownership interest, investment amounts, the year acquired and a brief description of each, follows.

OKC Industrial Properties (“OKC”), 10%, $56,164, acquired in 1992. OKC originally owned approximately 260 acres of undeveloped land in north Oklahoma City and over time has sold all but approximately 46 acres.

Bailey Hilltop Pipeline (“Bailey”), 10%, $80,377, acquired in 2008. Bailey is a gas gathering system pipeline for the Bailey Hilltop Prospect oil and gas properties in Grady County, Oklahoma.

Cloudburst Solutions (“Solutions”), 8.125%, $1,250,000 total, with an initial investment of $500,000 in 2014 and an additional investment of $750,000 in 2016. Solutions owns exclusive rights to a water purification process technology that is being developed and currently tested.

Ocean’s NG (“Ocean”), 12.44%, $206,444, acquired in 2015. Ocean is developing an underground Compressed Natural Gas (“CNG”) storage and delivery system for retail sales of CNG.

LIQUIDITY AND CAPITAL RESOURCES

To supplement the following discussion, please refer to the Balance Sheets and the Statements of Cash Flows included in this Form 10-K.

In 2017, as in prior years, the Company funded its business activity through the use of internal sources of capital. For the most part, these internal sources are cash flows from operations, cash, cash equivalents and available-for-sale securities. When cash flows from operating activities are in excess of those needed for other business activities, the remaining balance is used to increase cash, cash equivalents and/or available-for-sale securities. When cash flows from operating activities are not adequate to fund other business activities, withdrawals are made from cash, cash equivalents and/or available-for-sale securities. Cash equivalents are highly liquid debt instruments purchased with a maturity of three months or less. All of the available-for-sale securities are U.S. Treasury Bills.

In 2017, net cash provided by operating activities was $2,771,452. Sales (including lease bonuses), net of production costs, general and administrative costs and income taxes paid were $2,394,688, which accounted for 86% of net cash provided by operations. The remaining components provided 14% of cash flow. In 2017, net cash applied to investing activities was $5,202,162. In 2017, dividend payments and treasury stock purchases totaled $873,334 and accounted for all of the cash applied to financing activities.

Other than cash and cash equivalents, other significant changes in working capital include the following:

Trading securities increased $86,229 (18%) to $559,936 in 2017 from $473,707 in 2016. The net increase is due to $48,738 in unrealized gains, which represent the change in the fair value of the securities from their original cost, plus $37,491 of 2017 income.

Refundable income taxes decreased $209,968 (39%) to $326,830 in 2017 from $536,798 in 2016.

Accounts receivable increased $65,183 (9%) to $829,824 in 2017 from $764,641 in 2016. The increase was due primarily to the use of higher product prices for oil and gas sales accrual estimates for year-end 2017 compared to 2016. Additional information about oil and gas sales for 2017 is included in the “Results of Operations” section that follows.

In 2017, the Company added a note receivable in the amount of $175,000 to provide funding to a cost method investee.

Accounts payable increased $73,258 (45%) to $235,007 in 2017 from $161,749 in 2016. This increase was primarily due to increased drilling activity.

Discussion of Selected Material Line Items in Cash Flows.

The following is a discussion of material changes in cash flow by activity between the years ended December 31, 2017 and 2016. Also, see the discussion of changes in operating results under “Results of Operations” below in this Item 7.

Operating Activities

As noted above, net cash flows provided by operating activities in 2017 were $2,771,452, which, when compared to the $2,776,128 provided in 2016, represents a net decrease of $4,676. The decrease was mostly due to a decrease in lease bonus cash flows of $688,692 that was offset by an increase in oil and gas sales of $682,866. Additional discussion of the significant items follows.

9

The $682,866 (13%) increase in cash received from oil and gas sales to $6,029,703 in 2017 from $5,346,837 in 2016 was the result of an increase in oil and gas sales prices partially offset by a decrease in sales volumes. See “Results of Operations” below for a price/volume analysis and the related discussion of oil and gas sales.

Cash received for lease bonuses decreased $688,692 (79%) to $184,282 in 2017 from $872,974 in 2016.

The 2017 cash distribution from our equity investment in Broadway Sixty-Eight, Ltd. of $49,500 was primarily for our share of operating profits. The 2016 cash distribution of $165,000 included our share of operating profits plus the profits from the sale of the last small office building on some land adjacent to our current office building. See Item 8, Note 7 to the accompanying financial statements for additional information regarding Broadway Sixty-Eight, Ltd.

Investing Activities

Net cash applied to investing activities decreased $2,428,826 (32%) to $5,202,162 in 2017 from $7,630,988 in 2016. This $2,428,826 decrease was due primarily to a $1,873,676 decrease in net cash applied to the purchase of available-for-sale securities, a $1,023,556 decrease in purchases of equity and other investments and a $290,000 increase in cash distributions from other investments offset by a $710,580 increase in purchase of property, plant and equipment. See “Equity and Other Investments” discussion on pages 8 and 9 for additional information regarding the investments purchased in 2017 and 2016.

Financing Activities

Cash applied to financing activities decreased $137,167 (14%) to $873,334 in 2017 from $1,010,501 in 2016. Cash applied to financing activities consist of cash dividends on common stock and cash used for the purchase of treasury stock. In 2017, cash dividends paid on common stock amounted to $837,505 as compared to $921,667 in 2016. Dividends of $5.00 per share were paid in 2017 and 2016. Cash applied to purchase treasury stock decreased $53,005 to $35,829 in 2017 from $88,834 in 2016.

Forward-Looking Summary

The Company’s latest estimate of business to be done in 2018 and beyond indicates the projected activity can be funded from cash flow from operations and other internal sources, including net working capital. The Company is engaged in exploratory drilling. If this drilling is successful, substantial development drilling may result. Also, should other exploration projects which fit the Company’s risk parameters become available or other investment opportunities become known, capital requirements may be more than the Company has available. If so, external sources of financing could be required.

RESULTS OF OPERATIONS

As disclosed in the Statements of Operations in Item 8 of this Form 10-K, in 2017 the Company had net income of $685,687 as compared to net loss of $(84,225) in 2016. Net income/(loss) per share, basic and diluted, was $4.35 in 2017, an increase of $4.88 per share from $(0.53) in 2016. Material line item changes in the Statements of Operations will be discussed in the following paragraphs.

Operating Revenues

Operating revenues increased $18,452 to $6,309,590 in 2017 from $6,291,138 in 2016. Oil and gas sales increased $707,144 (13%) to $6,125,308 in 2017 from $5,418,164 in 2016. Lease bonuses and other revenues decreased $688,692 (79%) to $184,282 in 2017 from $872,974 in 2016. The increase in oil and gas sales is discussed in the following paragraphs.

The $707,144 increase in oil and gas sales was the result of a $234,193 increase in gas sales, a $426,328 increase in oil sales and a $46,623 increase in miscellaneous oil and gas product sales. The following price and volume analysis is presented to explain the changes in oil and gas sales from 2016 to 2017. Miscellaneous oil and gas product sales of $206,593 in 2017 and $159,970 in 2016 are not included in the analysis.

			Variance
Production	2017		Price		Volume		2016
Gas –
MCF (000 omitted)		806				(165)		971
$ (000 omitted)	$	2,346	$	592	$	(358)	$	2,112
Unit Price	$	2.91	$	.74			$	2.17
Oil –
Bbls (000 omitted)		77				(8)		85
$ (000 omitted)	$	3,572	$	732	$	(306)	$	3,146
Unit Price	$	46.42	$	9.52			$	36.90

10

The $234,193 (11%) increase in natural gas sales to $2,346,272 in 2017 from $2,112,079 in 2016 was the result of a decrease in gas sales volumes offset by an increase in the average price received per thousand cubic feet (MCF). The average price per MCF of natural gas sales increased $0.74 per MCF to $2.91 per MCF in 2017 from $2.17 per MCF in 2016, resulting in a positive gas price variance of $591,953. A negative volume variance of $357,759 was the result of a decrease in natural gas volumes sold of 164,866 MCF to 806,575 MCF in 2017 from 971,441 MCF in 2016. The decrease in the volume of gas production was the net result of new 2017 production of about 30,000 MCF, offset by a decline of about 194,000 MCF in production from previous wells. About 29,000 MCF (19%) of this decline is from working interest wells in Robertson County, Texas, and another decline of about 43,000 MCF (28%) occurred in working interest wells in Woods County, Oklahoma. As disclosed in Supplemental Schedule 1 of the Unaudited Supplemental Financial Information included in Item 8 below, working interests in natural gas extensions and discoveries were not adequate to replace working interest reserves produced in 2017 or 2016.

The gas production for 2017 and 2016 includes production from about 100 royalty interest properties drilled by various operators in Robertson County, Texas. These properties accounted for approximately 187,000 MCF and $544,000 of the 2017 gas sales and approximately 216,000 MCF and $468,000 of the 2016 gas sales. These properties accounted for about 23% of the Company’s gas revenues in 2017 and 2016. The Company has no control over the timing of future drilling on the acreage in which we hold mineral interests.

The $426,328 (14%) increase in crude oil sales to $3,572,443 in 2017 from $3,146,115 in 2016 was the net result of an increase in the average price per barrel (Bbl) offset by a decrease in oil sales volumes. The average price received per Bbl of oil increased $9.52 to $46.42 in 2017 from $36.90 in 2016, resulting in a positive oil price variance of $732,088. A decline in oil sales volumes of 8,286 Bbls to 76,965 Bbls in 2017 from 85,251 Bbls in 2016 resulted in a negative volume variance of $305,760. The decrease in the oil volume production was the net result of new 2017 production of about 4,000 Bbls, offset by a 13,000 Bbl decline in production from previous wells. Of the new 2017 production, approximately 1,200 Bbls (30%) was from new working interest wells in Woods County, Oklahoma. As disclosed in Supplemental Schedule 1 of the Unaudited Supplemental Financial Information included below in Item 8, working interests in oil extensions and discoveries were not adequate to replace working interest reserves produced in 2017 or 2016.

For both oil and gas sales, the price change was mostly the result of a change in the spot market prices upon which most of the Company’s oil and gas sales are based. These spot market prices have had significant fluctuations in the past and these fluctuations are expected to continue.

Operating Costs and Expenses

Operating costs and expenses decreased $42,735 (1%) to $6,827,906 in 2017 from $6,870,641 in 2016, primarily due to a decrease in depreciation, depletion and amortization expense. The material components of operating costs and expenses are discussed below.

Production Costs. Production costs increased $49,264 (2%) to $2,190,020 in 2017 from $2,140,756 in 2016. The net increase was primarily the result of a $69,642 (32%) increase in gross production tax to $285,688 in 2017 from $216,046 in 2016, offset by a decrease in other production costs of $29,195 (7%) to $396,238 in 2017 from $425,433 in 2016. Of the decrease in other production costs, $46,995 was the result of decreased expenses for existing wells offset by $17,800 of expenses for new wells. Gross production taxes are state taxes, which are calculated as a percentage of gross proceeds from the sale of products from each producing oil and gas property; therefore, they fluctuate with the change in the dollar amount of revenues from oil and gas sales.

Exploration and Development Costs. Under the successful efforts method of accounting used by the Company, geological and geophysical costs are expensed as incurred as are the costs of unsuccessful exploratory drilling. The costs of successful exploratory drilling and all development costs are capitalized. Total costs of exploration and development, excluding asset retirement obligations but inclusive of geological and geophysical costs, were $2,251,662 in 2017 and $1,110,426 in 2016. See Item 8, Note 8 to the accompanying financial statements for a breakdown of these costs. Exploration costs charged to operations were $883,593 in 2017 and $429,210 in 2016, inclusive of unsuccessful exploratory well costs of $630,219 in 2017 and $253,460 in 2016, and geological and geophysical costs of $243,251 in 2017 and $175,749 in 2016.

Update of Oil and Gas Exploration and Development Activity from December 31, 2016. For the year ended December 31, 2017, the Company participated in the drilling of 14 gross exploratory working interest wells and 3 gross development working interest wells, including 2 in progress at the end of 2016, with working interests ranging from a high of 16% to a low of 8%. Of the 14 exploratory wells, 4 were completed as producing wells, 7 as dry holes and 3 were in progress. The 3 development wells were completed as producing wells.

The following is a summary as of March 7, 2018, updating both exploration and development activity from December 31, 2016, for the period ended December 31, 2017.

The Company participated with 8% and 16% working interests in the completion of two development wells that were drilled in 2016 on a Woods County, Oklahoma prospect. Both wells are commercial oil and gas producers. Capitalized costs for the period were $50,195.

The Company participated with an 11.1% working interest in the drilling of a development well on a Woods County, Oklahoma prospect. The well was completed as a commercial oil and gas producer. Capitalized costs for the period were $60,927.

The Company participated with its 8.4% working interest in the drilling of an exploratory well on a Thomas County, Kansas prospect. The well was completed as a marginal oil producer. An additional exploratory well will be drilled on the prospect starting in March 2018. Capitalized costs for the period were $27,214.

11

The Company participated with its 10.5% working interest in the drilling of an exploratory well on a Thomas County, Kansas prospect. The well was completed as a dry hole. An additional exploratory well will be drilled on the prospect starting in March 2018. Dry hole costs for the period were $24,292.

The Company participated with its 18% working interest in the drilling of two step-out wells (one a re-entry) on a Kiowa County, Kansas prospect. A completion is in progress on one well and the other is awaiting completion. Prepaid drilling costs for the period were $131,400.

The Company is participating with its 14% interest in the development of a Hansford County, Texas prospect for waterflooding. Of five planned injection wells, three have been drilled, completed and are injecting water, one has been drilled and completed with water injection to commence shortly and one missed the reservoir and was plugged. There are two producing wells. A water supply well has been drilled and completed and facilities construction is complete. Capitalized costs for the period were $563,458.

The Company participated with its 14% working interest in the drilling of two exploratory wells and a salt water disposal well on a Creek County, Oklahoma prospect. One exploratory well was completed as a marginal oil producer and the other as a commercial oil producer. Capitalized costs for the period were $67,473.

The Company participated with its 16% working interest in the drilling of an exploratory well on a Chase County, Nebraska prospect. The well was completed as a dry hole. Dry hole costs for the period were $64,402.

The Company owns a 35% interest in 16,472.55 net acres of leasehold on a Crockett and Val Verde Counties, Texas prospect. The Company is participating in the development of the prospect and is currently engaged in efforts to sell a portion of its interest.

The Company participated with its 14% working interest in the drilling of an exploratory well on a Lavaca County, Texas prospect. The well was completed as a dry hole. Dry hole costs for the period were $245,212.

The Company participated with a 35% interest in the development of a Crockett County, Texas prospect on which 4,882.5 net acres of leasehold have been acquired. A geologic study of the prospect area has been completed and the Company has sold a portion of its leasehold rights, leaving it with a 12.25% interest. An exploratory well has been drilled on the prospect and a completion is in progress. Capitalized costs for the period, excluding leasehold, were $22,221. Total leasehold and geologic costs to date for the prospect are $22,856.

The Company participated with its 14% interest in a 3-D seismic survey and in the drilling of an exploratory well on a Hodgeman County, Kansas prospect. The well was completed as a dry hole. Dry hole costs for the period were $46,768.

In January 2017, the Company purchased a 14% interest in 2,443.84 net acres of leasehold on a Leflore County, Oklahoma prospect for $119,748. The Company participated in the drilling of an exploratory well on the prospect that was completed as a dry hole. Dry hole costs for the period were $123,515.

In March 2017, the Company purchased a 16% interest in 587.6 net acres of leasehold on a Harvey County, Kansas prospect for $7,521. A 3-D seismic survey of the prospect area was conducted and an exploratory well was drilled. It was completed as a dry hole. Seismic costs for the period were $8,625 and dry hole costs were $24,879.

In March 2017, the Company agreed to purchase a 13% interest in a 3-D seismic prospect covering approximately 35,000 acres in San Patricio County, Texas. The Company’s share of land and seismic costs is estimated to be $646,000 over a two-year period. A 3-D seismic survey of the prospect area has been conducted and the data set is being processed. Exploratory drilling should start sometime in 2018. Capitalized costs for the period were $299,549 and seismic costs were $215,504.

In March 2017, the Company paid $8,800 for a 16% interest in 429.36 net acres of leasehold and a producing well on a Comanche County, Kansas prospect. A re-completion attempt of the producing well has been unsuccessful and it is under evaluation. Additional capitalized costs for the period were $26,012.

In May 2017, the Company purchased a 10.5% interest in 460.27 net acres of leasehold on a Lea County, New Mexico prospect for $26,580. An exploratory well has been drilled on the prospect and a completion is in progress. Capitalized costs for the period were $259,022.

Starting in June 2017, the Company purchased a 10.5% interest in 3,088.44 net acres of leasehold on a Coke County, Texas prospect for $96,003. An exploratory well was drilled on the prospect. A completion attempt was unsuccessful and the well will be plugged. Dry hole costs for the period were $92,815.

In September 2017, the Company agreed to take a 7% interest in a Summit County, Utah prospect and to participate in the drilling of an exploratory well on the prospect. The well is in progress. Capitalized costs for the period were $67,956.

In December 2017, the Company purchased an 11.2% interest in eleven wells and associated leasehold on a Tyler County, Texas prospect for $56,560 and paid $19,694 in prepaid workover costs. Workovers are in progress on several of the wells and others are planned in an effort to increase production.

12

Depreciation, Depletion, Amortization and Valuation Provisions (DD&A). Major DD&A components are the provision for impairment of undeveloped leaseholds, provision for impairment of long-lived assets, depletion of producing leaseholds and depreciation of tangible and intangible lease and well costs. Undeveloped leaseholds are amortized over the life of the leasehold (most are 3 years) using a straight line method, except when the leasehold is impaired or condemned by drilling and/or geological interpretation of seismic data; if so, an adjustment to the provision is made at the time of impairment. The provision for impairment of undeveloped leaseholds was $363,431 in 2017 and $390,584 in 2016. The 2017 provision was due to the annual amortization of undeveloped leaseholds. The 2016 provision was due to the annual amortization of undeveloped leaseholds of $334,831 and specific leasehold impairments of $55,753.

As discussed in Item 8, Note 10 to the accompanying financial statements, accounting principles require the recognition of an impairment loss on long-lived assets used in operations when indicators of impairment are present. Impairment evaluation is a two-step process. The first step is to measure when the undiscounted cash flows estimated to be generated by those assets, determined on a well basis, is less than the assets’ carrying amounts. Those assets meeting the first criterion are adjusted to estimated fair value. Evaluation for impairment was performed in both 2017 and 2016. The 2017 impairment loss was $426,823 and the 2016 impairment loss was $727,845. The $301,022 decrease in impairments in 2017 was mainly due to fairly stable oil and natural gas prices.

The depletion and depreciation of oil and gas properties are computed by the units-of-production method. The amount expensed in any year will fluctuate with the change in estimated reserves of oil and gas, a change in the rate of production or a change in the basis of the assets. The Company did not participate in any horizontal working interest wells in 2016 or 2017. A horizontal well may cost five to eight times as much as a vertically drilled well. In addition, horizontal wells’ initial production rates tend to be greater and their production decline rates are usually higher than in vertical wells. The larger investment in the costlier horizontal wells and the increased production rates result in an increase in depreciation expense. The provision for depletion and depreciation declined $258,914 (16%) to $1,312,058 in 2017 from $1,570,972 in 2016. This decrease is due to the reasons discussed above. The provision also includes $81,035 for 2017 and $113,578 for 2016 for the amortization of the Asset Retirement Costs. See Item 8, Note 2 to the accompanying financial statements for additional information regarding the Asset Retirement Obligation.

Other Income, Net. See Item 8, Note 11 to the accompanying financial statements for an analysis of the components of this line item for 2017 and 2016. Other income, net increased $383,805 (128%) to $683,397 in 2017 from $299,592 in 2016. The line items responsible for this net increase are described below.

Net realized and unrealized gain (loss) on trading securities increased $21,893 to a net gain of $83,622 in 2017 from a net gain of $61,729 in 2016. Realized gains or losses result when a trading security is sold. Unrealized gains or losses result from adjusting the Company’s carrying amount in trading securities owned at the reporting date to estimated fair value. In 2017, the Company had realized gains of $34,884 and unrealized gains of $48,738. In 2016, the Company had realized losses of $20,430 and unrealized gains of $82,159.

Income from investments increased $290,000 to $445,000 in 2017 from $155,000 in 2016.

Gains on asset sales increased $37,560 to $59,683 in 2017 from $22,123 in 2016.

Interest income increased $84,128 to $130,498 in 2017 from $46,370 in 2016. This increase was the result of a rise in the average interest rate and an increase in the average balance of cash equivalents and average balance of available-for-sale securities from which most of the interest income is derived. The average interest rate increased from 0.33% in 2016 to 0.43% in 2017. The average balance outstanding increased $1,566,628 to $15,412,046 in 2017 from $13,845,418 in 2016.

Provision for Income Taxes. In 2017, the Company had an estimated income tax benefit of $582,582 as the result of a deferred tax benefit of $593,111, offset by a current tax provision of $10,529. The deferred tax benefit of $593,111 includes a $577,797 deferred tax benefit adjustment due to a decrease in the federal income tax rate at the end of 2017. In 2016, the Company had an estimated income tax benefit of $172,886 as the result of a current tax benefit of $57,676, plus a deferred tax benefit of $115,210. See Item 8, Note 6 to the accompanying financial statements for an analysis of the various components of income taxes and a discussion of the federal tax rate change.

ITEM 7A. QUANTITATIVE AND QUALiTATIVE DISCLOSURES ABOUT MARKET RISKS

Not applicable.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Financial Statements

	Page
Report of Independent Registered Public Accounting Firm, HoganTaylor LLP	14
Balance Sheets – December 31, 2017 and 2016	15
Statements of Operations – Years Ended December 31, 2017 and 2016	17
Statements of Stockholders’ Equity – Years Ended December 31, 2017 and 2016	18
Statements of Cash Flows – Years Ended December 31, 2017 and 2016	19
Notes to Financial Statements	21
Unaudited Supplemental Financial Information	28

13

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and the Board of Directors

of The Reserve Petroleum Company

Opinion on the Financial Statements

We have audited the accompanying balance sheets of The Reserve Petroleum Company (the Company) as of December 31, 2017 and 2016, the related statements of operations, stockholders' equity and cash flows for the years then ended, and the related notes to the financial statements (collectively, the financial statements). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's 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 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 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 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 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 financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ HoganTaylor LLP

We have served as the Company's auditor since 2009.

Oklahoma City, Oklahoma

March 29, 2018

14

THE RESERVE PETROLEUM COMPANY

BALANCE SHEETS

ASSETS

	December 31,
	2017		2016
Current Assets:
Cash and Cash Equivalents (Note 2)	$	4,767,810	$	8,071,854
Available-for-Sale Securities (Notes 2, 5 & 9)		16,371,544		13,443,636
Trading Securities (Notes 2, 5 & 9)		559,936		473,707
Refundable Income Taxes		326,830		536,798
Accounts Receivable (Note 2)		829,824		764,641
Note Receivable (Note 7)		175,000		---
Total Current Assets		23,030,944		23,290,636
Investments:
Equity Investments (Notes 2 & 7)		991,094		822,570
Other, at Cost (Notes 2 & 7)		1,633,300		1,906,856
Total Investments		2,624,394		2,729,426
Property, Plant and Equipment (Notes 2, 8 & 10):
Oil and Gas Properties, at Cost, Based on the Successful Efforts Method of Accounting –
Unproved Properties		2,296,686		2,180,018
Proved Properties		53,536,453		53,030,034
Oil and Gas Properties, Gross		55,833,139		55,210,052
Less – Accumulated Depreciation, Depletion, Amortization and Valuation Allowance		45,335,894		44,456,113
Oil and Gas Properties, Net		10,497,245		10,753,939
Other Property and Equipment, at Cost		404,256		406,430
Less – Accumulated Depreciation		253,239		231,887
Other Property and Equipment, Net		151,017		174,543
Total Property, Plant and Equipment		10,648,262		10,928,482
Total Assets	$	36,303,600	$	36,948,544

See Accompanying Notes

15

THE RESERVE PETROLEUM COMPANY

BALANCE SHEETS

LIABILITIES AND STOCKHOLDERS’ EQUITY

	December 31,
	2017		2016
Current Liabilities:
Accounts Payable	$	235,007	$	161,749
Other Current Liabilities		25,243		25,590
Total Current Liabilities		260,250		187,339
Long-Term Liabilities:
Asset Retirement Obligation (Note 2)		1,774,634		1,710,677
Dividends Payable (Note 3)		1,228,648		1,278,266
Deferred Tax Liability, Net (Note 6)		918,050		1,511,160
Total Long-Term Liabilities		3,921,332		4,500,103
Total Liabilities		4,181,582		4,687,442
Commitments and Contingencies (Notes 2 & 7)
Stockholders’ Equity (Notes 3 & 4):
Common Stock		92,368		92,368
Additional Paid-in Capital		65,000		65,000
Retained Earnings		33,497,463		33,600,718
Stockholders’ Equity Before Treasury Stock		33,654,831		33,758,086
Less – Treasury Stock, at Cost		1,532,813		1,496,984
Total Stockholders’ Equity		32,122,018		32,261,102
Total Liabilities and Stockholders’ Equity	$	36,303,600	$	36,948,544

See Accompanying Notes

16

THE RESERVE PETROLEUM COMPANY

STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2017			2016
Operating Revenues:
Oil and Gas Sales	$	6,125,308		$	5,418,164
Lease Bonuses and Other		184,282			872,974
Total Operating Revenues		6,309,590			6,291,138
Operating Costs and Expenses:
Production		2,190,020			2,140,756
Exploration		883,593			429,210
Depreciation, Depletion, Amortization and Valuation Provisions (Note 10)		2,133,338			2,719,899
General, Administrative and Other		1,620,955			1,580,776
Total Operating Costs and Expenses		6,827,906			6,870,641
Loss from Operations		(518,316	)		(579,503	)
Equity Income/(Loss) in Investees (Note 7)		(61,976	)		22,800
Other Income, Net (Note 11)		683,397			299,592
Income/(Loss) Before Income Taxes		103,105			(257,111	)
Income Tax Benefit (Notes 2 & 6)		(582,582	)		(172,886	)
Net Income/(Loss)	$	685,687		$	(84,225	)
Per Share Data (Note 2):
Net Income/(Loss), Basic and Diluted	$	4.35		$	(0.53	)
Cash Dividends	$	5.00		$	5.00
Weighted Average Shares Outstanding, Basic and Diluted		157,788			158,107

See Accompanying Notes

17

THE RESERVE PETROLEUM COMPANY

STATEMENTS OF STOCKHOLDERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2017 AND 2016

			Additional
	Common		Paid-in		Retained			Treasury
	Stock		Capital		Earnings			Stock			Total
Balance at December 31, 2015	$	92,368	$	65,000	$	34,475,369		$	(1,408,149	)	$	33,224,588
Net Loss		---		---		(84,225	)		---			(84,225	)
Dividends Declared		---		---		(790,426	)		---			(790,426	)
Purchase of Treasury Stock		---		---		---			(88,835	)		(88,835	)
Balance at December 31, 2016		92,368		65,000		33,600,718			(1,496,984	)		32,261,102
Net Income		---		---		685,687			---			685,687
Dividends Declared		---		---		(788,942	)		---			(788,942	)
Purchase of Treasury Stock		---		---		---			(35,829	)		(35,829	)
Balance at December 31, 2017	$	92,368	$	65,000	$	33,497,463		$	(1,532,813	)	$	32,122,018

See Accompanying Notes

18

THE RESERVE PETROLEUM COMPANY

STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2017			2016
Cash from Operating Activities:
Cash Received –
Oil and Gas Sales	$	6,029,703		$	5,346,837
Lease Bonuses and Other		184,282			872,974
Sale of Trading Securities		3,483,394			858,921
Interest Received		119,265			42,228
Agricultural Rentals and Other		9,140			60,648
Dividends Received on Trading Securities		2,597			1,254
Cash Distributions from Equity Investments		49,500			165,000
Income Tax Refunds, Net of Income Taxes Paid		199,439			8,930
Cash Paid –
Production Costs		(2,195,844	)		(2,132,055	)
General Suppliers, Employees and Taxes, Other than Income Taxes		(1,623,453	)		(1,587,921	)
Purchase of Trading Securities		(3,486,002	)		(860,175	)
Farm Expense and Other		(569	)		(513	)
Net Cash Provided by Operating Activities		2,771,452			2,776,128
Cash Provided by/(Applied to) Investing Activities:
Maturity of Available-for-Sale Securities		29,841,639			17,283,067
Purchase of Available-for-Sale Securities		(32,769,546	)		(22,084,650	)
Proceeds from Disposal of Property, Plant and Equipment		150,948			23,774
Purchase of Property, Plant and Equipment		(2,688,759	)		(1,978,179	)
Cash Distributions from Other Investments		445,000			155,000
Purchase of Equity and Other Investments		(6,444	)		(1,030,000	)
Note Receivable		(175,000	)		---
Net Cash Applied to Investing Activities		(5,202,162	)		(7,630,988	)

See Accompanying Notes

19

THE RESERVE PETROLEUM COMPANY

STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2017			2016
Cash Applied to Financing Activities:
Dividends Paid to Stockholders	$	(837,505	)	$	(921,667	)
Purchase of Treasury Stock		(35,829	)		(88,834	)
Total Cash Applied to Financing Activities		(873,334	)		(1,010,501	)
Net Change in Cash and Cash Equivalents		(3,304,044	)		(5,865,361	)
Cash and Cash Equivalents at Beginning of Year		8,071,854			13,937,215
Cash and Cash Equivalents at End of Year	$	4,767,810		$	8,071,854
Reconciliation of Net Income/(Loss) to Net Cash Provided by Operating Activities:
Net Income/(Loss)	$	685,687		$	(84,225	)
Net Income/(Loss) Increased (Decreased) by Net Change in –
Net Unrealized Holding (Gains)/Losses on Trading Securities		(48,738	)		(82,159	)
Accounts Receivable		(95,259	)		(70,046	)
Interest and Dividends Receivable		(11,233	)		(4,142	)
Refundable Income Taxes		209,968			(48,746	)
Accounts Payable		(13,034	)		5,911
Trading Securities		(37,491	)		19,176
Deferred Taxes		(593,111	)		(115,210	)
Other Liabilities		46,228			46,602
Income from Equity and Other Investments		(383,024	)		(177,800	)
Cash Distribution from Equity Investments		49,500			165,000
Exploration Costs		838,145			377,112
Disposition of Property, Plant and Equipment		(9,524	)		24,756
Depreciation, Depletion, Amortization and Valuation Provisions		2,133,338			2,719,899
Net Cash Provided by Operating Activities	$	2,771,452		$	2,776,128

See Accompanying Notes

20

THE RESERVE PETROLEUM COMPANY

NOTES TO FINANCIAL STATEMENTS

Note 1 – NATURE OF OPERATIONS

The Company is engaged in oil and natural gas exploration and development and minerals management with areas of concentration in Texas, Oklahoma, Kansas, Arkansas and South Dakota, a single business segment.

Note 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash and Cash Equivalents

The Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents.

Investments

Marketable Securities:

The Company classifies its debt and marketable equity securities in one of two categories: trading or available-for-sale. Trading securities are bought and held principally for the purposes of selling them in the near term. All other securities are classified as available-for-sale.

Trading and available-for-sale securities are recorded at fair value. Unrealized gains and losses on trading securities, which consist primarily of equity securities, are reported in current earnings.

Unrealized gains and losses on available-for-sale securities, which consist entirely of U.S. Government securities, are reported as a component of other comprehensive income when significant to the financial statements. There are no significant cumulative unrealized gains or losses on available-for-sale securities as of December 31, 2017 or 2016.

Equity and Cost Method Investments:

The Company accounts for its non-marketable investment in partnerships on the equity method if ownership allows the Company to exercise significant influence, or the cost method, if not. See Note 7 for additional information on investments.

Management reviews our cost method investments and the underlying projects and activity periodically and assesses the need for any impairment. Management does not believe any investments need to be impaired at the present time.

Receivables and Revenue Recognition

Oil and gas sales and resulting receivables are recognized when the product is delivered to the purchaser and title has transferred. Sales are to credit-worthy major energy purchasers with payments generally received within 60 days of transportation from the well site. Historically, the Company has had little, if any, uncollectible receivables; therefore, an allowance for uncollectible accounts has not been provided.

Property, Plant and Equipment

Oil and gas properties are accounted for on the successful efforts method. The acquisition, exploration and development costs of producing properties are capitalized. The Company has not historically had any capitalized exploratory drilling costs that are pending determination of reserves for more than one year. All costs relating to unsuccessful exploratory wells, geological and geophysical costs, delay rentals, and abandoned properties are expensed. Lease costs related to unproved properties are amortized over the life of the lease and are assessed for impairment when indicators of impairment are present. Any impairment of value is charged to expense.

Depreciation, depletion and amortization of producing properties is computed on the units-of-production method on a property-by-property basis. The units-of-production method is based primarily on estimates of proved reserve quantities. Due to uncertainties inherent in this estimation process, it is at least reasonably possible that reserve quantities will be revised in the near term. Changes in estimated reserve quantities are applied to depreciation, depletion and amortization computations prospectively.

Other property and equipment are depreciated on the straight-line, declining-balance, or other accelerated methods as appropriate.

The following estimated useful lives are used for the different types of property:

Office furniture and fixtures (years)	5	to	10
Automotive equipment (years)	5	to	8

Impairment losses are recorded on long-lived assets used in operations when indicators of impairment are present. The Company uses its oil and gas reserve reports to test each producing property for impairment quarterly. See Note 10 for discussion of impairment losses.

Income Taxes

The Company utilizes an asset/liability approach to calculating deferred income taxes. Deferred income taxes are provided to reflect temporary differences in the basis of net assets and liabilities for income tax and financial reporting purposes. Deferred tax assets are reduced by a valuation allowance if a determination is made that it is more likely than not that some or all of the deferred assets will not be realized based on the weight of all available evidence.

21

The Company recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based upon the technical merits of the position. The Company will record the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement with taxing authorities.

The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense. There were no uncertain tax positions as of December 31, 2017 and 2016.  The federal income tax returns for 2014, 2015 and 2016 are subject to examination.

Earnings Per Share

Accounting guidance for Earnings Per Share (EPS) establishes the methodology of calculating basic earnings per share and diluted earnings per share. The calculations of basic earnings per share and diluted earnings per share differ in that instruments convertible to common stock (such as stock options, warrants, and convertible preferred stock) are added to weighted average shares outstanding when computing diluted earnings per share. For 2017 and 2016, the Company had no dilutive shares outstanding; therefore, basic and diluted earnings per share are the same.

Concentrations of Credit Risk and Major Customers

The Company’s receivables relate primarily to sales of oil and natural gas to purchasers with operations in Texas, Oklahoma, Kansas, and South Dakota. The Company had two purchasers in both 2017 and 2016 whose purchases were 35% of total oil and gas sales.

The Company maintains its cash in bank deposit accounts, which at times may exceed federally insured limits. The Company has not experienced any losses in such accounts, and believes that it is not exposed to any significant credit risk with respect to cash and cash equivalents.

Use of Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include oil and natural gas reserve quantities that form the basis for the calculation of amortization of oil and natural gas properties. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories. Actual results could differ from the estimates and assumptions used in the preparation of the Company’s financial statements.

Gas Balancing

Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability is recorded when the Company’s excess takes of natural gas volumes exceed our estimated remaining recoverable reserves (over-produced). No receivables are recorded for those wells where the Company has taken less than our ownership share of gas production (under-produced).

Guarantees

At the inception of a guarantee or subsequent modification, the Company records a liability for the fair value of the obligation undertaken in issuing the guarantee. The Company records a liability for its obligations when it becomes probable that the Company will have to perform under the guarantee. The Company has issued guarantees associated with the Company’s equity investments.

Asset Retirement Obligation

The Company records the fair value of its estimated liability to retire its oil and natural gas producing properties in the period in which it is incurred (typically the date of first sales). The estimated liability is calculated by obtaining current estimated plugging costs from the well operators, inflating it over the life of the property and discounting the estimated obligation to its present value. Current year inflation rate used is 4.08%. When the liability is first recorded, a corresponding increase in the carrying amount of the related long-lived asset is also recorded. Subsequently, the asset is amortized to expense over the life of the property and the liability is increased annually for the change in its present value, which is currently 3.25%.

The following table summarizes the asset retirement obligation for 2017 and 2016:

	2017			2016
Beginning balance at January 1	$	1,710,677		$	1,677,328
Liabilities incurred		31,627			18,321
Liabilities settled (wells sold or plugged)		(22,573	)		(20,542	)
Accretion expense		46,574			47,018
Revision to estimate		8,329			(11,448	)
Ending balance at December 31	$	1,774,634		$	1,710,677

22

New Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers. ASU 2014-09 is a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities-Oil and Gas-Revenue Recognition. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for two transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. In March, April, May and December 2016, the FASB issued new guidance in Topic 606, Revenue from Contracts with Customers, to address the following potential implementation issues of the new revenue standard: (a) to clarify the implementation guidance on principal versus agent considerations, (b) to clarify the identification of performance obligations and the licensing implementation guidance and (c) to address certain issues in the guidance on assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. This standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company follows the sales method of accounting for oil and natural gas production, which is generally consistent with the revenue recognition provision of the new standard. The Company has completed the process of evaluating the effect of the adoption and determined there were no changes required to our reported revenues as a result of the adoption. The majority of our revenue arrangements generally consist of a single performance obligation to transfer promised goods or services. Based on our evaluation process and review of our contracts with customers, the timing and amount of revenue recognized based on the standard is consistent with our revenue recognition policy under previous guidance. The Company adopted the new standard on January 1, 2018, using the modified retrospective method, and will expand our financial statement disclosures in order to comply with the standard. We have determined the adoption of the standard will not have a material impact on our results of operations, cash flows, or financial position.

In January 2016, the FASB issued ASU No. 2016-01, Recognition and Measurement of Financial Assets and Liabilities. The update simplifies the accounting and disclosures related to equity investments. The amendments in ASU 2016-01 are effective for fiscal years beginning after December 15, 2017 and for interim periods therein. Adoption of this update will not have a material impact on the Company’s financial position, results of operations or cash flows.

In February 2016, the FASB issued ASU No. 2016-02, Leases with new lease accounting guidance. Under the new guidance, at the commencement date, lessees will be required to recognize a lease liability, which is a lessee‘s obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The new guidance is not applicable for leases with a term of 12 months or less. Lessor accounting is largely unchanged. ASU 2016-02 is effective for the Company for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company currently has no capital or operating leases. Accordingly, we do not expect this new guidance to have any impact on the Company’s financial position, results of operations or cash flows.

In August 2016, the FASB issued ASU No. 2016-15, Classification of Certain Cash Receipts and Cash Payments, which addresses certain issues where diversity in practice was identified and may change how an entity classifies certain cash receipts and cash payments on its statement of cash flows. The new guidance also clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. This guidance will generally be applied retrospectively and is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those years. Early adoption is permitted. All of the amendments in ASU 2016-15 are required to be adopted at the same time. The Company does not expect this new guidance to have a material impact on the Company’s statement of cash flows.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business, which clarifies the definition of a business to provide guidance in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 provides a screen to determine when a set of assets is not a business, requiring that when substantially all fair value of gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set of assets is not a business. A framework is provided to assist in evaluating whether both an input and a substantive process are present for the set to be a business. ASU 2017-01 is effective for periods beginning after December 15, 2017, including interim periods within those annual periods. No disclosures are required at transition and early adoption is permitted. The Company adopted this standard on January 1, 2018 and will apply this guidance to any future business combinations.

Reclassifications

Certain amounts in the 2016 financial statements have been reclassified to conform to the 2017 presentation. The amounts were not material to the financial statements and had no effect on previously reported net income.

Note 3 – DIVIDENDS PAYABLE

Dividends payable includes amounts that are due to stockholders whom the Company has been unable to locate, stockholders’ heirs pending ownership transfer documents, or uncashed dividend checks of other stockholders.

23

Note 4 – COMMON STOCK

The following table summarizes the changes in common stock issued and outstanding:

			Shares of
	Shares		Treasury		Shares
	Issued		Stock		Outstanding
January1, 2016, $.50 par value stock, 200,000 shares authorized		184,735		26,277		158,458
Purchase of stock		---		554		(554	)
December31, 2016, $.50 par value stock, 200,000 shares authorized		184,735		26,831		157,904
Purchase of stock		---		239		( 239	)
December31, 2017, $.50 par value stock, 200,000 shares authorized		184,735		27,070		157,665

Note 5 – MARKETABLE SECURITIES

At December31, 2017, available-for-sale securities, consisting entirely of U.S. government securities, are due within one year or less by contractual maturity.

For trading securities, in 2017 the Company recorded realized gains of $34,884 and unrealized gains of $48,738. In 2016 the Company recorded realized losses of $20,430 and unrealized gains of $82,159.

Note 6 – INCOME TAXES

On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act (“the Act”), which made significant changes that affect the Company. Among other provisions, the Act lowered the U.S. Federal corporate tax rate to 21%, effective January 1, 2018. Since the change in tax rate is not effective until 2018, the current income tax provision in 2017 is unaffected. The Company measures its deferred tax assets and liabilities using the enacted tax rates that will apply in the years in which the temporary differences are expected to be recovered or paid. Accordingly, the Company’s deferred tax assets and liabilities were re-measured to reflect the reduction in the corporate tax rate to 21%, which resulted in a $577,797 increase in income tax benefit and a corresponding decrease in net deferred tax liabilities during 2017.

The Act is a comprehensive tax reform bill containing a number of other provisions that either currently or in the future could impact the Company. The Company has completed the analysis of the Act and does not expect a material change due to the transition impacts. Any changes that do arise due to changes in interpretations of the Act, legislative action to address questions that arise because of the Act, changes in accounting standards for income taxes or related interpretations in response to the Act, or any updates or changes to estimates the Company has utilized to calculate the transition impacts will be disclosed in future periods as they arise. The effect of certain limitations effective for the tax year 2018 and forward, specifically related to the deductibility of executive compensation and interest expense, have been evaluated.

Components of deferred taxes are as follows:

	December 31,
	2017			2016
Assets:
Net Leasehold Impairment Reserves	$	189,867		$	290,167
Gas Balance Receivable		32,352			52,379
Long-Lived Asset Impairment		945,399			1,745,936
Deferred Geological and Geophysical Expense		47,539			62,720
Other		266,141			406,579
Total Assets		1,481,298			2,557,781
Liabilities:
Receivables		59,561			91,622
Intangible Drilling Costs		1,614,470			2,856,294
Depletion, Depreciation and Other		725,317			1,121,025
Total Liabilities		2,399,348			4,068,941
Net Deferred Tax Liability	$	(918,050	)	$	(1,511,160	)

The decrease in the deferred tax liability for 2017 reflected in the above table is primarily the result of the decrease in the corporate tax rate to 21% as noted above and a decline of intangible drilling costs.

The following table summarizes the current and deferred portions of income tax expense:

	Year Ended December 31,
	2017			2016
Current Tax Provision/(Benefit):
Federal	$	10,362		$	(57,494	)
State		167			(182	)
Total Current Provision/(Benefit)		10,529			(57,676	)
Deferred Tax Benefit		(593,111	)		(115,210	)
Total Benefit	$	(582,582	)	$	(172,886	)

24

The total income tax benefit expressed as a percentage of income/(loss) before income tax, excluding effect of change in federal income tax rate discussed below, was 5% for 2017 and 67% for 2016. These amounts differ from the amounts computed by applying the statutory U.S. federal enacted income tax rate for 2017 and 2016 as summarized in the following reconciliation:

	Year Ended December 31,
	2017			2016
Computed Federal Tax Provision/(Benefit)	$	35,035		$	(87,418	)
Increase (Decrease) in Tax From:
Allowable Depletion in Excess of Basis		(51,533	)		(83,460	)
Dividend Received Deduction		(618	)		(878	)
State Income Tax Benefit		(167	)		(182	)
Federal Income Tax Rate Change		(577,797	)		---
Other		12,498			(948	)
Income Tax Benefit	$	(582,582	)	$	(172,886	)
Effective Tax Rate		5%			67%

Excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, reduces estimated taxable income projected for any year. When a provision for income taxes is recorded, federal excess percentage depletion benefits decrease the effective tax rate. When a benefit for income taxes is recorded, federal excess percentage depletion benefits increase the effective tax rate. The benefit of federal excess percentage depletion is not directly related to the amount of pre-tax income recorded in a period. Accordingly, in periods where a recorded pre-tax income is relatively small or a pre-tax loss, the proportional effect of these items on the effective tax rate may be significant.

Note 7 – EQUITY AND COST METHOD INVESTMENTS AND RELATED COMMITMENTS AND CONTINGENT LIABILITIES INCLUDING GUARANTEES

The Company’s Equity Investments include:

Broadway Sixty-Eight, Ltd. (the “Partnership”), an Oklahoma limited partnership, with a 33% ownership. The Partnership owns and operates an office building in Oklahoma City, Oklahoma. Although the Company invested as a limited partner, it agreed, jointly and severally, with all other limited partners to reimburse the general partner for any losses suffered from operating the Partnership. The indemnity agreement provides no limitation to the maximum potential future payments. To date, no monies have been paid with respect to this agreement. The Company leases its corporate office from the Partnership. The operating lease, under which the space was rented, expired February 28, 1994, and the space is currently rented on a year-to-year basis under the terms of the expired lease. Rent expense for lease of the corporate office from the Partnership was approximately $30,000 for 2017 and 2016. The Company’s investment in the Partnership totaled $171,243 and $187,380 at December 31, 2017 and 2016, respectively.

Grand Woods Development, LLC (the “LLC”), an Oklahoma limited liability company, with a 47% ownership. The LLC owns approximately 26.3 acres of undeveloped real estate in northeast Oklahoma City. The Company has guaranteed a loan for which the proceeds were used to purchase a portion of the undeveloped real estate acreage. The Company’s investment in the LLC totaled $544,603 and $635,190 at December 31, 2017 and 2016, respectively.

QSN Office Park (“QSN”), an Oklahoma limited liability company acquired in March 2016, with a 20% ownership. QSN is constructing and selling office buildings in a new office park. The Company’s investment in QSN totaled $275,248 and $280,000 at December 31, 2017 and 2016, respectively.

The Company’s Cost Method Investments include:

OKC Industrial Properties (“OKC”), with a 10% ownership, was acquired in 1992. OKC originally owned approximately 260 acres of undeveloped land in north Oklahoma City and over time has sold all but approximately 46 acres. The Company’s investment in OKC totaled $56,164 at December 31, 2017 and 2016.

Bailey Hilltop Pipeline (“Bailey”), with a 10% ownership, was acquired in 2008. Bailey is a gas gathering system pipeline for the Bailey Hilltop Prospect oil and gas properties in Grady County, Oklahoma. The Company’s investment in Bailey totaled $80,377 at December 31, 2017 and 2016.

Cloudburst Solutions (“Solutions”), with an 8.125% ownership, was acquired with an initial investment of $500,000 in 2014 and an additional investment of $750,000 in 2016. Solutions owns exclusive rights to a water purification process technology that is being developed and currently tested. The Company’s investment in Solutions totaled $1,250,000 at December 31, 2017 and 2016. The Company also holds a note receivable of $175,000 from Solutions.

Ocean’s NG (“Ocean”), with a 12.44% ownership, was acquired in 2015. Ocean is developing an underground Compressed Natural Gas (“CNG”) storage and delivery system for retail sales of CNG. The Company’s investment in Ocean totaled $206,444 and $200,000 at December 31, 2017 and 2016, respectively.

25

Note 8 – COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION, AND DEVELOPMENT ACTIVITIES

All of the Company’s oil and gas operations are within the continental United States. In connection with its oil and gas operations, the following costs were incurred:

	Year Ended December 31,
	2017		2016
Acquisition of Properties:
Unproved	$	568,893	$	715,520
Proved		---		---
Exploration Costs		1,274,931		856,075
Development Costs		976,731		254,351
Asset Retirement Obligation		39,956		18,321

Note 9 – FAIR VALUE MEASUREMENTS

Inputs used to measure fair value are organized into a fair value hierarchy based on how observable the inputs are. Level 1 inputs consist of quoted prices in active markets for identical assets. Level 2 inputs are inputs, other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs. During 2017 and 2016 there were no transfers into or out of Level 2 or Level 3.

Recurring Fair Value Measurements

Certain of the Company’s assets are reported at fair value in the accompanying balance sheets on a recurring basis. The Company determined the fair value of the available-for-sale securities using quoted market prices for securities with similar maturity dates and interest rates. At December 31, 2017 and 2016, the Company’s assets reported at fair value on a recurring basis are summarized as follows:

	2017
	Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
Financial Assets:
Available-for-Sale Securities –
U.S. Treasury Bills Maturing in 2018	$	---	$	16,371,544	$	---
Trading Securities –
Domestic Equities		249,210		---		---
International Equities		271,921		---		---
Others		38,805		---		---

	2016
	Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
Financial Assets:
Available-for-Sale Securities –
U.S. Treasury Bills Maturing in 2017	$	---	$	13,443,636	$	---
Trading Securities –
Domestic Equities		333,516		---		---
International Equities		83,948		---		---
Others		56,243		---		---

Non-recurring Fair Value Measurements

The Company’s asset retirement obligation incurred annually represents non-recurring fair value liabilities. The fair value of the non-financial liabilities incurred was $31,627 in 2017 and $18,321 in 2016 and was calculated using Level 3 inputs. See Note 2 for more information about this liability and the inputs used for calculating fair value.

The fair value of oil and gas properties used in estimating impairment losses of $426,822 for 2017 and $727,845 for 2016 were based on Level 3 inputs. See Note 10 for the procedure used for calculating these expenses.

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, trade receivables, marketable securities, trade payables, and dividends payable. As of December 31, 2017 and 2016, the historical cost of cash and cash equivalents, trade receivables, trade payables, and dividends payable are considered to be representative of their respective fair values due to the short-term maturities of these items.

26

Note 10 – LONG-LIVED ASSETS IMPAIRMENT LOSS

Certain oil and gas producing properties have been deemed to be impaired because the assets, evaluated on a property-by-property basis, are not expected to recover their entire carrying value through future cash flows. Impairment losses totaling $426,822 for 2017 and $727,845 for 2016 are included in the Statements of Operations in the line item Depreciation, Depletion, Amortization and Valuation Provisions. The impairments for 2017 and 2016 were calculated by reducing the carrying value of the individual properties to an estimated fair value equal to the discounted present value of the future cash flow from these properties. Forward pricing was used for calculating future revenue and cash flow.

Note 11 – OTHER INCOME, NET

The following is an analysis of the components of Other Income, Net:

	2017			2016
Net Realized and Unrealized Gain (Loss) on Trading Securities	$	83,622		$	61,729
Gains on Asset Sales		59,683			22,123
Interest Income		130,498			46,370
Settlements of Class Action Lawsuits		3,540			55,048
Agricultural Rental Income		5,600			5,600
Dividend Income		2,597			1,254
Income from Other Investments		445,000			155,000
Interest and Other Expenses		(47,143	)		(47,532	)
Other Income, Net	$	683,397		$	299,592

Note 12 – CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The Company is affiliated by common management and ownership with Mesquite Minerals, Inc. (Mesquite), Mid-American Oil Company (Mid-American) and Lochbuie Limited Liability Company (LLTD). The Company also owns interests in certain producing and non-producing oil and gas properties as tenants in common with Mesquite, Mid-American and LLTD.

Mesquite, Mid-American and LLTD share facilities and employees including executive officers with the Company. The Company has been reimbursed for services, facilities, and miscellaneous business expenses incurred in 2017 in the amount of $190,665 each by Mesquite, Mid-American and LLTD. Reimbursements in 2016 were $182,926 each by Mesquite, Mid-American and LLTD. Included in the 2017 amounts, Mesquite, Mid-American and LLTD each paid $137,113 for their share of salaries. In 2016, the share of salaries paid by Mesquite, Mid-American and LLTD was $132,215 each.

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UNAUDITED SUPPLEMENTAL FINANCIAL INFORMATION

28

SUPPLEMENTAL SCHEDULE 1

THE RESERVE PETROLEUM COMPANY

WORKING INTEREST RESERVE QUANTITY INFORMATION

(Unaudited)

	Year Ended December 31,
	2017			2016
Oil and Condensate (Bbls)
Proved Developed and Undeveloped Reserves:
Beginning of Year		401,584			462,241
Revisions of Previous Estimates		18,951			(1,977	)
Extensions and Discoveries		16,405			9,148
Purchase of Reserves		------			---
Production		(60,544	)		(67,828	)
End of Year		376,396			401,584
Proved Developed Reserves:
Beginning of Year		358,822			415,402
End of Year		341,152			358,822
Gas (MCF)
Proved Developed and Undeveloped Reserves:
Beginning of Year		3,023,754			3,637,626
Revisions of Previous Estimates		494,665			(49,227	)
Extensions and Discoveries		190,923			71,715
Purchase of Reserves		---			---
Production		(517,831	)		(636,360	)
End of Year		3,191,511			3,023,754
Proved Developed Reserves:
Beginning of Year		2,809,944			3,309,750
End of Year		2,944,804			2,809,944

See notes on next page.

29

SUPPLEMENTAL SCHEDULE 1

THE RESERVE PETROLEUM COMPANY

WORKING INTEREST RESERVE QUANTITY INFORMATION

(Unaudited)

Notes:

1. Estimates of royalty interests’ reserves, on properties in which the Company does not own a working interest, have not been included because the information required for the estimation of such reserves is not available. The Company’s share of production from its net royalty interests was 16,421 Bbls of oil and 288,743 MCF of gas for 2017 and 17,423 Bbls of oil and 335,081 MCF of gas for 2016.

2. The preceding table sets forth estimates of the Company’s proved oil and gas reserves, together with the changes in those reserves, as prepared by the Company’s engineer for 2017 and 2016. The Company engineer’s qualifications set forth in the Proxy Statement and as incorporated into Item 10 of this Form 10-K, are incorporated herein by reference. All reserves are located within the United States.

3. The Company emphasizes that the reserve volumes shown are estimates, which by their nature are subject to revision in the near term. The estimates have been made by utilizing geological and reservoir data, as well as actual production performance data available to the Company. These estimates are reviewed annually and are revised upward or downward as warranted by additional performance data. The Company’s engineer is not independent, but strives to use an objective approach in calculating the Company’s working interest reserve estimates.

4. The Company’s internal controls relating to the calculation of its working interests’ reserve estimates include review and testing of the accounting data flowing into the calculation of the reserve estimates. In addition, the average oil and natural gas product prices calculated in the engineer’s 2017 summary reserve report was tested by comparison to 2017 average sales price information from the accounting records.

30

SUPPLEMENTAL SCHEDULE 2

THE RESERVE PETROLEUM COMPANY

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

RELATING TO PROVED WORKING INTEREST

OIL AND GAS RESERVES

(Unaudited)

	At December 31,
	2017			2016
Future Cash Inflows	$	25,418,030		$	20,452,614
Future Production and Development Costs		(12,989,835	)		(11,392,251	)
Future Asset Retirement Obligation		(1,881,972	)		(1,802,124	)
Future Income Tax Benefit (Expense)		(362,534	)		369,553
Future Net Cash Flows		10,183,689			7,627,792
10% Annual Discount for Estimated Timing of Cash Flows		(3,121,751	)		(2,373,717	)
Standardized Measure of Discounted Future Net Cash Flows	$	7,061,938		$	5,254,075

Estimates of future net cash flows from the Company’s proved working interests in oil and gas reserves are shown in the table above. These estimates, which by their nature are subject to revision in the near term, were based on an average monthly product price received by the Company for 2016 and 2017, with no escalation. The development and production costs are based on year-end cost levels, assuming the continuation of existing economic conditions. Cash flows are further reduced by estimated future asset retirement obligations and estimated future income tax expense calculated by applying the current statutory income tax rates to the pretax net cash flows, less depreciation of the tax basis of the properties and depletion applicable to oil and gas production.

31

SUPPLEMENTAL SCHEDULE 3

THE RESERVE PETROLEUM COMPANY

CHANGES IN STANDARDIZED MEASURE OF

DISCOUNTED FUTURE NET CASH FLOWS FROM

PROVED WORKING INTEREST RESERVE QUANTITIES

(Unaudited)

	Year Ended December 31,
	2017			2016
Standardized Measure, Beginning of Year	$	5,254,075		$	7,405,506
Sales and Transfers, Net of Production Costs		(2,343,561	)		(1,935,438	)
Net Change in Sales and Transfer Prices, Net of Production Costs		2,394,155			(1,992,946	)
Extensions, Discoveries and Improved Recoveries, Net of Future Production and Development Costs		710,294			347,007
Revisions of Quantity Estimates		929,958			(62,357	)
Accretion of Discount		689,080			1,006,978
Purchases of Reserves in Place		---			---
Net Change in Income Taxes		(517,818	)		1,009,435
Net Change in Asset Retirement Obligation		17,383			(13,669	)
Changes in Production Rates (Timing) and Other		(71,628	)		(510,441	)
Standardized Measure, End of Year	$	7,061,938		$	5,254,075

32

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (the "Exchange Act"), the term "disclosure controls and procedures" means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in 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 an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

Management of the Company, with the participation of the Principal Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Company's disclosure controls and procedures and concluded that the Company's disclosure controls and procedures were effective as of December 31, 2017.

Management's Annual Report on Internal Control over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting for the Company as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. This system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.

The Company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and the directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company's assets that could have a material effect on the financial statements, and provide reasonable assurance as to the detection of fraud.

Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time.

With the participation of the Principal Executive Officer and Principal Financial Officer, the Company’s management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting, based on the framework and criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, the Company’s management concluded that the Company's internal control over financial reporting was effective as of December 31, 2017.

This Annual Report on Form 10-K does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. As the Company is a Smaller Reporting Company, Management’s report was not subject to attestation by the Company’s independent registered public accounting firm.

/s/ Cameron R. McLain	/s/ Lawrence R. Francis
Cameron R. McLain, President	Lawrence R. Francis, 1st Vice President
Principal Executive Officer	Principal Financial Officer
March 29, 2018	March 29, 2018

33

Changes in Internal Control over Financial Reporting

Management of the Company, with the participation of the Principal Executive Officer and Principal Financial Officer, evaluated the internal control over financial reporting and concluded that no change in the Company’s internal control over financial reporting occurred during the fourth quarter ended December 31, 2017 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information regarding directors and executive officers, Section 16(a) Beneficial Ownership Reporting Compliance, the Company’s Code of Ethics, Corporate Governance, and any other information called for by this item is incorporated by reference to the Proxy Statement.

ITEM 11. EXECUTIVE COMPENSATION

Information regarding executive compensation called for by this Item is incorporated by reference to the Proxy Statement.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information regarding security ownership of certain beneficial owners and management and related stockholder matters called for by this Item is incorporated by reference to the Proxy Statement.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8, Note 12 to Financial Statements. Information regarding the independence of our directors and other information called for by this Item is incorporated by reference to the Proxy Statement.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information regarding fees billed to the Company by its independent registered public accounting firm is incorporated by reference to the Proxy Statement.

34

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The following documents are exhibits to this Form 10-K. Each document marked by an asterisk is filed electronically herewith.

Exhibit Number	Description
3.1	Restated Certificate of Incorporation dated June 1, 2012 is incorporated by reference to Exhibit 3.1 of The Reserve Petroleum Company’s Annual Report 10-K (Commission File No. 0-8157) filed March 28, 2013.
3.2	Amended By-Laws dated November 16, 2004, are incorporated by reference to Exhibit 3.2 of The Reserve Petroleum Company’s Annual Report on Form 10-KSB (Commission File No. 0-8157) filed March 30, 2006.
14	Code of Ethics for Senior Officers incorporated by reference to Exhibit 14 of The Reserve Petroleum Company’s Annual Report on Form 10-KSB (Commission File No. 0-8157) filed March 30, 2006.
31.1*	Certification of Principal Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as amended.
31.2*	Certification of Principal Financial Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as amended.
32*	Certification of Principal Executive Officer and Principal Financial Officer Pursuant to 18 U.S.C. Section 1350.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Definition Linkbase Document
101.LAB*	XBRL Taxonomy Label Linkbase Document
101.PRE*	XBRL Taxonomy Presentation Linkbase Document
	* Filed electronically herewith.

ITEM 16. FORM 10-K SUMMARY

None.

35

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	THE RESERVE PETROLEUM COMPANY (Registrant)
	/s/    Cameron R. McLain
	By:  Cameron R. McLain, President
	(Principal Executive Officer)
	/s/    Lawrence R. Francis
	By:  Lawrence R. Francis, 1st Vice President
	(Principal Financial Officer)
Date: March 29, 2018

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

/s/ Kyle L. McLain	/s/ Jerry L. Crow
Kyle L. McLain (Chairman of the Board)	Jerry L. Crow (Director)
March 29, 2018	March 29, 2018
/s/ Robert L. Savage	/s/ William M. Smith
Robert L. Savage (Director)	William M. Smith (Director)
March 29, 2018	March 29, 2018

36

EX-31.1

Exhibit 31.1

Certification of Principal Executive Officer Pursuant to Rules 13a-14(a) or 15d-14(a) under the

Securities Exchange Act of 1934, as amended

I, Cameron R. McLain, certify that:

1. I have reviewed this report on Form 10-K of The Reserve Petroleum Company;

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 officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within this entity, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer 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 the registrant’s board of directors (or persons performing the equivalent functions):

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

b) Any fraud, whether or not material that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	March 29, 2018	/s/ Cameron R. McLain
		Cameron R. McLain, President
		(Principal Executive Officer)

EX-31.2

Exhibit 31.2

Certification of Principal Financial Officer Pursuant to Rules 13a-14(a) or 15d-14(a) under the

Securities Exchange Act of 1934, as amended

I, Lawrence R. Francis, certify that:

1. I have reviewed this report on Form 10-K of The Reserve Petroleum Company;

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 officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within this entity, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer 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 the registrant’s board of directors (or persons performing the equivalent functions):

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

b) Any fraud, whether or not material that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	March 29, 2018	/s/ Lawrence R. Francis
		Lawrence R. Francis, 1st Vice President
		(Principal Financial Officer)

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Annual Report of The Reserve Petroleum Company (the "Company") on Form 10-K for the year ended December31, 2017, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), we, Cameron R. McLain and Lawrence R. Francis, Principal Executive Officer and Principal Financial Officer, respectively, of the Company, certify, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to our knowledge:

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

2. The information contained in the Report fairly present, in all material respects, the financial condition and results of operations of the Company for the year ended December31, 2017.

March 29, 2018	/s/    Cameron R. McLain
	By:  Cameron R. McLain, President
	(Principal Executive Officer)
	/s/    Lawrence R. Francis
	By:  Lawrence R. Francis, 1st Vice President
	(Principal Financial Officer)

XML

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Mar. 23, 2018	Jun. 30, 2017
Document Information [Line Items]
Entity Registrant Name	RESERVE PETROLEUM CO
Entity Central Index Key	0000083350
Trading Symbol	rsrv
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	No
Entity Common Stock, Shares Outstanding (in shares)		157,599
Entity Public Float			$ 25,095,004
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Amendment Flag	false

XML

Balance Sheets - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Current Assets:
Cash and Cash Equivalents (Note 2)	$ 4,767,810	$ 8,071,854
Available-for-Sale Securities (Notes 2, 5 & 9)	16,371,544	13,443,636
Trading Securities (Notes 2, 5 & 9)	559,936	473,707
Refundable Income Taxes	326,830	536,798
Accounts Receivable (Note 2)	829,824	764,641
Note Receivable (Note 7)	175,000
Total Current Assets	23,030,944	23,290,636
Investments:
Equity Investments (Notes 2 & 7)	991,094	822,570
Other, at Cost (Notes 2 & 7)	1,633,300	1,906,856
Total Investments	2,624,394	2,729,426
Unproved Properties	2,296,686	2,180,018
Proved Properties	53,536,453	53,030,034
Oil and Gas Properties, Gross	55,833,139	55,210,052
Less – Accumulated Depreciation, Depletion, Amortization and Valuation Allowance	45,335,894	44,456,113
Oil and Gas Properties, Net	10,497,245	10,753,939
Other Property and Equipment, at Cost	404,256	406,430
Less – Accumulated Depreciation	253,239	231,887
Other Property and Equipment, Net	151,017	174,543
Total Property, Plant and Equipment	10,648,262	10,928,482
Total Assets	36,303,600	36,948,544
Current Liabilities:
Accounts Payable	235,007	161,749
Other Current Liabilities	25,243	25,590
Total Current Liabilities	260,250	187,339
Long-Term Liabilities:
Asset Retirement Obligation (Note 2)	1,774,634	1,710,677
Dividends Payable (Note 3)	1,228,648	1,278,266
Deferred Tax Liability, Net (Note 6)	918,050	1,511,160
Total Long-Term Liabilities	3,921,332	4,500,103
Total Liabilities	4,181,582	4,687,442
Commitments and Contingencies (Notes 2 & 7)
Stockholders’ Equity (Notes 3 & 4):
Common Stock	92,368	92,368
Additional Paid-in Capital	65,000	65,000
Retained Earnings	33,497,463	33,600,718
Stockholders’ Equity Before Treasury Stock	33,654,831	33,758,086
Less – Treasury Stock, at Cost	1,532,813	1,496,984
Total Stockholders’ Equity	32,122,018	32,261,102
Total Liabilities and Stockholders’ Equity	$ 36,303,600	$ 36,948,544

XML

Statements of Operations - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Operating Revenues:
Oil and Gas Sales	$ 6,125,308	$ 5,418,164
Lease Bonuses and Other	184,282	872,974
Total Operating Revenues	6,309,590	6,291,138
Operating Costs and Expenses:
Production	2,190,020	2,140,756
Exploration	883,593	429,210
Depreciation, Depletion, Amortization and Valuation Provisions (Note 10)	2,133,338	2,719,899
General, Administrative and Other	1,620,955	1,580,776
Total Operating Costs and Expenses	6,827,906	6,870,641
Loss from Operations	(518,316)	(579,503)
Equity Income/(Loss) in Investees (Note 7)	(61,976)	22,800
Other Income, Net (Note 11)	683,397	299,592
Income/(Loss) Before Income Taxes	103,105	(257,111)
Income Tax Benefit (Notes 2 & 6)	(582,582)	(172,886)
Net Income/(Loss)	$ 685,687	$ (84,225)
Per Share Data (Note 2):
Net Income/(Loss), Basic and Diluted (in dollars per share)	$ 4.35	$ (0.53)
Cash Dividends (in dollars per share)	$ 5	$ 5
Weighted Average Shares Outstanding, Basic and Diluted (in shares)	157,788	158,107

XML

Statements of Stockholders' Equity - USD ($)	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Treasury Stock [Member]	Total
Balance at Dec. 31, 2015	$ 92,368	$ 65,000	$ 34,475,369	$ (1,408,149)	$ 33,224,588
Net Loss			(84,225)		(84,225)
Dividends Declared			(790,426)		(790,426)
Purchase of Treasury Stock				(88,835)	(88,835)
Balance at Dec. 31, 2016	92,368	65,000	33,600,718	(1,496,984)	32,261,102
Net Loss			685,687		685,687
Dividends Declared			(788,942)		(788,942)
Purchase of Treasury Stock				(35,829)	(35,829)
Balance at Dec. 31, 2017	$ 92,368	$ 65,000	$ 33,497,463	$ (1,532,813)	$ 32,122,018

XML

Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Cash from Operating Activities:
Oil and Gas Sales	$ 6,029,703	$ 5,346,837
Lease Bonuses and Other	184,282	872,974
Sale of Trading Securities	3,483,394	858,921
Interest Received	119,265	42,228
Agricultural Rentals and Other	9,140	60,648
Dividends Received on Trading Securities	2,597	1,254
Cash Distributions from Equity Investments	49,500	165,000
Income Tax Refunds, Net of Income Taxes Paid	199,439	8,930
Cash Paid –
Production Costs	(2,195,844)	(2,132,055)
General Suppliers, Employees and Taxes, Other than Income Taxes	(1,623,453)	(1,587,921)
Purchase of Trading Securities	(3,486,002)	(860,175)
Farm Expense and Other	(569)	(513)
Net Cash Provided by Operating Activities	2,771,452	2,776,128
Cash Provided by/(Applied to) Investing Activities:
Maturity of Available-for-Sale Securities	29,841,639	17,283,067
Purchase of Available-for-Sale Securities	(32,769,546)	(22,084,650)
Proceeds from Disposal of Property, Plant and Equipment	150,948	23,774
Purchase of Property, Plant and Equipment	(2,688,759)	(1,978,179)
Cash Distributions from Other Investments	445,000	155,000
Purchase of Equity and Other Investments	(6,444)	(1,030,000)
Note Receivable	(175,000)
Net Cash Applied to Investing Activities	(5,202,162)	(7,630,988)
Cash Applied to Financing Activities:
Dividends Paid to Stockholders	(837,505)	(921,667)
Purchase of Treasury Stock	(35,829)	(88,834)
Total Cash Applied to Financing Activities	(873,334)	(1,010,501)
Net Change in Cash and Cash Equivalents	(3,304,044)	(5,865,361)
Cash and Cash Equivalents at Beginning of Year	8,071,854	13,937,215
Cash and Cash Equivalents at End of Year	4,767,810	8,071,854
Reconciliation of Net Income/(Loss) to Net Cash Provided by Operating Activities:
Net Income/(Loss)	685,687	(84,225)
Net Income/(Loss) Increased (Decreased) by Net Change in –
Net Unrealized Holding (Gains)/Losses on Trading Securities	(48,738)	(82,159)
Accounts Receivable	(95,259)	(70,046)
Interest and Dividends Receivable	(11,233)	(4,142)
Refundable Income Taxes	209,968	(48,746)
Accounts Payable	(13,034)	5,911
Trading Securities	(37,491)	19,176
Deferred Taxes	(593,111)	(115,210)
Other Liabilities	46,228	46,602
Income from Equity and Other Investments	(383,024)	(177,800)
Cash Distributions from Equity Investments	49,500	165,000
Exploration Costs	838,145	377,112
Disposition of Property, Plant and Equipment	(9,524)	24,756
Depreciation, Depletion, Amortization and Valuation Provisions	2,133,338	2,719,899
Net Cash Provided by Operating Activities	$ 2,771,452	$ 2,776,128

XML

Note 1 - Nature of Operations

12 Months Ended

Dec. 31, 2017

Notes to Financial Statements

Basis of Accounting [Text Block]

Note

1

–

NATURE OF OPERATIONS

The Company is engaged in oil and natural gas exploration and development and minerals management with areas of concentration in Texas, Oklahoma, Kansas

, Arkansas and South Dakota, a single business segment.

XML

Note 2 - Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Notes to Financial Statements

Significant Accounting Policies [Text Block]

Note

2

–

SUMMARY OF

SIGNIFICANT

ACCOUNTING POLICIES

Cash

and

Cash Equivalents

The Company considers all highly liquid debt instruments purchased with a maturity of

three

months or less to be cash equivalents.

Investments

Marketable Securities:

The Company

classifies its debt and marketable equity securities in

one

of

two

categories: trading or available-for-sale. Trading securities are bought and held principally for the purposes of selling them in the near term. All other securities are classified as available-for-sale.

Trading and available-for-sale securities are recorded at fair value.

Unrealized gains and losses on trading securities, which consist primarily of equity securities, are reported in current earnings.

Unrealized gains and losses on a

vailable-for-sale securities, which consist entirely of U.S. Government securities, are reported as a component of other comprehensive income when significant to the financial statements. There are

no

significant cumulative unrealized gains or losses on available-for-sale securities as of

December 31, 2017

or

2016.

Equity

and Cost Method Investments:

The Company accounts for its

non-marketable investment in partnerships on the equity method if ownership allows the Company to exercise significant influence, or the cost method, if

not.

See Note

7

for additional information on investments.

Management reviews our cost method investments and the underlying projects and activity periodically and assesses the need for any impairment. Management does

not

believe any investments need to be impaired at the present time.

Receivables and Revenue Recognition

Oil and gas sales and resulting receivables are recognized when the product is delivered to the purchaser and title has transferred. Sales are to credit-worthy major energy purchasers with payments generally received within

60

days of transportation from the well site.

Historically, the Company has had little, if any, uncollectible receivables; therefore, an allowance for uncollectible accounts has

not

been provided.

Property, Plant and Equipment

Oil and gas properties are accounted for on the successful efforts method. The acquisition, exploration and development costs of producing properties are capitalized. The Company has

not

historically had any capitalized exploratory drilling costs that are pending determination of reserves for more than

one

year. All costs relating to unsuccessful exploratory wells, geological and geophysical costs, delay rentals, and abandoned properties are expensed. Lease costs related to unproved properties are amortized over the life of the lease and are assessed for impairment when indicators of impairment are present. Any impairment of value is charged to expense.

Depreciation, depletion and amortization of producing properties

is computed on the units-of-production method on a property-by-property basis. The units-of-production method is based primarily on estimates of proved reserve quantities. Due to uncertainties inherent in this estimation process, it is at least reasonably possible that reserve quantities will be revised in the near term. Changes in estimated reserve quantities are applied to depreciation, depletion and amortization computations prospectively.

Other property and equipment

are depreciated on the straight-line, declining-balance, or other accelerated methods as appropriate.

The following estimated useful lives are used for the different types of property:

Office furniture and fixtures (years)	5	to	10
Automotive equipment (years)	5	to	8

Impairment losses are recorded on long-lived assets used in operations when indicators of impairment are present.

The Company uses its oil and gas reserve reports to test each producing property for impairment quarterly. See Note

10

for discussion of impairment losses.

Income Taxes

The Company utilizes a

n asset/liability approach to calculating deferred income taxes. Deferred income taxes are provided to reflect temporary differences in the basis of net assets and liabilities for income tax and financial reporting purposes. Deferred tax assets are reduced by a valuation allowance if a determination is made that it is more likely than

not

that some or all of the deferred assets will

not

be realized based on the weight of all available evidence.

The Company recognizes a tax benefit from an uncertain tax position when it is more likely than

not

that the position will be sustained upon examination, based upon the technical merits of the position. The Company will record the largest amount of tax benefit that is greater than

50%

likely of being realized upon settlement with taxing authorities.

The Company recognizes interest and penalties related to unrecognized tax benef

its in income tax expense.

There were

no

uncertain tax positions as of

December 31, 2017

and

2016.

 

The federal income tax returns for

2014,

2015

and

2016

are subject to examination.

Earnings

Per Share

Accounting guidance

for Earnings Per Share (EPS) establishes the methodology of calculating basic earnings per share and diluted earnings per share. The calculations of basic earnings per share and diluted earnings per share differ in that instruments convertible to common stock (such as stock options, warrants, and convertible preferred stock) are added to weighted average shares outstanding when computing diluted earnings per share. For

2017

and

2016,

the Company had

no

dilutive shares outstanding; therefore, basic and diluted earnings per share are the same.

Concentrations of Credit Risk and Major Customers

The Company

’s receivables relate primarily to sales of oil and natural gas to purchasers with operations in Texas, Oklahoma, Kansas, and South Dakota. The Company had

two

purchasers in both

2017

and

2016

whose purchases were

35%

of total oil and gas sales.

The Company maintains its cash in bank deposit accounts, which at times

may

exceed federally insured limits. The Company has

not

experienced any losses in such accounts, and believes that it is

not

exposed to any significant credit risk with respect to cash and cash equivalents.

Use of Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include oil and natural gas reserve quantities that form the basis for the calculation of amortization of oil and natural gas properties. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories. Actual results could differ from the estimates and assumptions used in the preparation of the Company

’s financial statements.

Gas Balancing

Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability is recorded when the Company

’s excess takes of natural gas volumes exceed our estimated remaining recoverable reserves (over-produced).

No

receivables are recorded for those wells where the Company has taken less than our ownership share of gas production (under-produced).

Guarantees

At the inception of a guarantee or subsequent modification, the Company records a liability for the fair value of the obligation undertaken in issuing the guarantee. The Company record

s a liability for its obligations when it becomes probable that the Company will have to perform under the guarantee. The Company has issued guarantees associated with the Company’s equity investments.

Asset Retirement Obligation

The Company records the fair value of its estimated liability to retire its oil and natural gas producing properties in the period in which it is incurred

(typically the date of

first

sales). The estimated liability is calculated by obtaining current estimated plugging costs from the well operators, inflating it over the life of the property and discounting the estimated obligation to its present value. Current year inflation rate used is

4.08%.

When the liability is

first

recorded, a corresponding increase in the carrying amount of the related long-lived asset is also recorded. Subsequently, the asset is amortized to expense over the life of the property and the liability is increased annually for the change in its present value, which is currently

3.25%.

The following table summarizes the

asset retirement obligation for

2017

and

2016:

	201 7			201 6
Beginning balance at January 1	$	1,710,677		$	1,677,328
Liabilities incurred		31,627			18,321
Liabilities settled (wells sold or plugged)		(22,573	)		(20,542	)
Accretion expense		46,574			47,018
Revision to estimate		8,329			(11,448	)
Ending balance at December 31	$	1,774,634		$	1,710,677

New Accounting Pronouncements

In

May 2014,

the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update

No.

2014

-

09,

Revenue from Contracts with Customers.

ASU

2014

-

09

is a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic

605,

Revenue Recognition, and industry-specific guidance in Subtopic

932

-

605,

Extractive Activities-Oil and Gas-Revenue Recognition. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a

five

-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for

two

transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. In

March,

April,

May

and

December 2016,

the FASB issued new guidance in Topic

606,

Revenue from Contracts with Customers, to address the following potential implementation issues of the new revenue standard: (a) to clarify the implementation guidance on principal versus agent considerations, (b) to clarify the identification of performance obligations and the licensing implementation guidance and (c) to address certain issues in the guidance on assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. This standard is effective for annual reporting periods beginning after

December 

15,

2017,

including interim periods within that reporting period. The Company follows the sales method of accounting for oil and natural gas production, which is generally consistent with the revenue recognition provision of the new standard. The Company has completed the process of evaluating the effect of the adoption and determined there were

no

changes required to our reported revenues as a result of the adoption. The majority of our revenue arrangements generally consist of a single performance obligation to transfer promised goods or services. Based on our evaluation process and review of our contracts with customers, the timing and amount of revenue recognized based on the standard is consistent with our revenue recognition policy under previous guidance. The Company adopted the new standard on

January 

1,

2018,

using the modified retrospective method, and will expand our financial statement disclosures in order to comply with the standard. We have determined the adoption of the standard will

not

have a material impact on our results of operations, cash flows, or financial position.

In

January 2016,

the FASB issued ASU

No.

2016

-

01

,

Recognition and Measurement of Financial Assets and Liabilities

. The update simplifies the accounting and disclosures related to equity investments. The amendments in ASU

2016

-

01

are effective for fiscal years beginning after

December

 

15,

2017

and for interim periods therein. Adoption of this update will

not

have a material impact on the Company’s financial position, results of operations or cash flows.

In

February 2016,

the FASB issued ASU

No.

2016

-

02,

Leases

with new lease accounting guidance. Under the new guidance, at the commencement date, lessees will be required to recognize a lease liability, which is a lessee‘s obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The new guidance is

not

applicable for leases with a term of

12

months or less. Lessor accounting is largely unchanged. ASU

2016

-

02

is effective for the Company for fiscal years beginning after

December 

15,

2018,

including interim periods within those fiscal years. The Company currently has

no

capital or operating leases. Accordingly, we do

not

expect this new guidance to have any impact on the Company’s financial position, results of operations or cash flows.

In

August 2016,

the FASB issued ASU

No.

2016

-

15,

 

Classification of Certain Cash Receipts and Cash Payments

, which addresses certain issues where diversity in practice was identified and

may

change how an entity classifies certain cash receipts and cash payments on its statement of cash flows. The new guidance also clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than

one

class of cash flows. This guidance will generally be applied retrospectively and is effective for public business entities for fiscal years beginning after

December 

15,

2017,

and interim periods within those years. Early adoption is permitted. All of the amendments in ASU

2016

-

15

are required to be adopted at the same time. The Company does

not

expect this new guidance to have a material impact on the Company’s statement of cash flows.

In

January 2017,

the FASB issued ASU

No.

2017

-

01,

Business Combinations (Topic

805

): Clarifying the Definition of a Business

, which clarifies the definition of a business to provide guidance in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU

2017

-

01

provides a screen to determine when a set of assets is

not

a business, requiring that when substantially all fair value of gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set of assets is

not

a business. A framework is provided to assist in evaluating whether both an input and a substantive process are present for the set to be a business. ASU

2017

-

01

is effective for periods beginning after

December 

15,

2017,

including interim periods within those annual periods.

No

disclosures are required at transition and early adoption is permitted. The Company adopted this standard on

January 

1,

2018

and will apply this guidance to any future business combinations.

Reclassifications

Certain amounts in the

2016

financial statements have been reclassified to conform to the

2017

presentation. The amounts were

not

material to the financial statements and had

no

effect on previously reported net income.

XML

Note 3 - Dividends Payable

12 Months Ended

Dec. 31, 2017

Notes to Financial Statements

Dividends Payable [Text Block]

Note

3

–

DIVIDENDS PAYABLE

Dividends payable include

s amounts that are due to stockholders whom the Company has been unable to locate, stockholders’ heirs pending ownership transfer documents, or uncashed dividend checks of other stockholders.

XML

Note 4 - Common Stock

12 Months Ended

Dec. 31, 2017

Notes to Financial Statements

Stockholders' Equity Note Disclosure [Text Block]

Note

4

–

COMMON STOCK

The following table summarizes the changes in common stock issued and outstanding:

			Shares of
	Shares		Treasury		Shares
	Issued		Stock		Outstanding
January 1, 2016, $.50 par value stock, 200 ,000 shares authorized		184,735		26,277		158,458
Purchase of stock		---		554		(554	)
December 31, 2016, $.50 par value stock, 200 ,000 shares authorized		184,735		26,831		157,904
Purchase of stock		---		239		( 239	)
December 31, 2017, $.50 par value stock, 2 00,000 shares authorized		184,735		27,070		157,665

XML

Note 5 - Marketable Securities

12 Months Ended

Dec. 31, 2017

Notes to Financial Statements

Investments in Debt and Marketable Equity Securities (and Certain Trading Assets) Disclosure [Text Block]

Note

5

–

MARKETABLE SECURITIES

At

December

31,

2017,

available-for-sale securities, consisting entirely of U.S. government securities, are due within

one

year or less by contractual maturity.

For trading securities

, in

2017

the Company recorded realized gains of

$34,884

and unrealized gains of

$48,738.

In

2016

the Company recorded realized losses of

$20,430

and unrealized gains of

$82,159.

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Note 6 - Income Taxes

12 Months Ended

Dec. 31, 2017

Notes to Financial Statements

Income Tax Disclosure [Text Block]

Note

6

–

INCOME TAXES

On

December 

22,

2017,

the United States enacted the Tax Cuts and Jobs Act (“the Act”), which made significant changes that affect the Company. Among other provisions, the Act lowered the U.S. Federal corporate tax rate to

21%,

effective

January 

1,

2018.

Since the change in tax rate is

not

effective until

2018,

the current income tax provision in

2017

is unaffected. The Company measures its deferred tax assets and liabilities using the enacted tax rates that will apply in the years in which the temporary differences are expected to be recovered or paid. Accordingly, the Company’s deferred tax assets and liabilities were re-measured to reflect the reduction in the corporate tax rate to

21%,

which resulted in a

$577,797

increase in income tax benefit and a corresponding decrease in net deferred tax liabilities during

2017.

The Act is a comprehensive tax reform bill containing a number of other provisions that either currently or in the future could impact the Company. The Company has completed the analysis of the Act and does

not

expect a material change due to the transition impacts. Any changes that do arise due to changes in interpretations of the Act, legislative action to address questions that arise because of the Act, changes in accounting standards for income taxes or related interpretations in response to the Act, or any updates or changes to estimates the Company has utilized to calculate the transition impacts will be disclosed in future periods as they arise. The effect of certain limitations effective for the tax year

2018

and forward, specifically related to the deductibility of executive compensation and interest expense, have been evaluated.

Components of deferred taxes

are as follows:

	December 31,
	2017			2016
Assets:
Net Leasehold Impairment Reserves	$	189,867		$	290,167
Gas Balance Receivable		32,352			52,379
Long-Lived Asset Impairment		945,399			1,745,936
Deferred Geological and Geophysical Expense		47,539			62,720
Other		266,141			406,579
Total Assets		1,481,298			2,557,781
Liabilities:
Receivables		59,561			91,622
Intangible Drilling Costs		1,614,470			2,856,294
Depletion, Depreciation and Other		725,317			1,121,025
Total Liabilities		2,399,348			4,068,941
Net Deferred Tax Liability	$	(918,050	)	$	(1,511,160	)

The decrease in the deferred tax liability for

2017

reflected in the above table is primarily the result of the decrease in the corporate tax rate to

21%

as noted above and a decline of intangible drilling costs.

The following table summarizes the current and deferred portions of income tax expense:

	Year Ended December 31,
	201 7			201 6
Current Tax Provision /(Benefit):
Federal	$	10,362		$	(57,494	)
State		167			(182	)
Total Current Provision /(Benefit)		10,529			(57,676	)
Deferred Tax Benefit		(593,111	)		(115,210	)
Total Benefit	$	(582,582	)	$	(172,886	)

The total income tax benefit expressed as a percentage of income/(loss) before income tax, excluding effect of change in federal income tax rate discussed below, was

5%

for

2017

and

67%

for

2016.

These amounts differ from the amounts computed by applying the statutory U.S. federal enacted income tax rate for

2017

and

2016

as summarized in the following reconciliation:

	Year Ended December 31,
	201 7			201 6
Computed Federal Tax Provision/(Benefit)	$	35,035		$	(87,418	)
Increase (Decrease) in Tax From:
Allowable Depletion in Excess of Basis		(51,533	)		(83,460	)
Dividend Received Deduction		(618	)		(878	)
State Income Tax Benefit		(167	)		(182	)
Federal Income Tax Rate Change		(577,797	)		---
Other		12,498			(948	)
Income Tax Benefit	$	(582,582	)	$	(172,886	)
Effective Tax Rate		5%			67%

Excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, reduces estimated taxable income projected for any year. When a provision for income taxes is recorded, federal excess percentage depletion benefits decrease the effective tax rate. When a benefit for income taxes is recorded, federal excess percentage depletion benefits increase the effective tax rate. The benefit of federal excess percentage depletion is

not

directly related to the amount of pre-tax income recorded in a period. Accordingly, in periods where a recorded pre-tax income is relatively small or a pre-tax loss, the proportional effect of these items on the effective tax rate

may

be significant.

XML

Note 7 - Equity and Cost Method Investments and Related Commitments and Contingent Liabilities Including Guarantees

12 Months Ended

Dec. 31, 2017

Notes to Financial Statements

Equity Method Investments and Joint Ventures Disclosure [Text Block]

Note

7

–

EQUITY AND COST METHOD INVESTMENTS AND RELATED COMMITMENTS AND CONTINGENT LIABILITIES INCLUDING GUARANTEES

The Company

’s Equity Investments include:

Broadway Sixty-Eight, Ltd. (the “Partnership”), an Oklahoma limited partnership, with a

33%

ownership. The Partnership owns and operates an office building in Oklahoma City, Oklahoma. Although the Company invested as a limited partner, it agreed, jointly and severally, with all other limited partners to reimburse the general partner for any losses suffered from operating the Partnership. The indemnity agreement provides

no

limitation to the maximum potential future payments. To date,

no

monies have been paid with respect to this agreement. The Company leases its corporate office from the Partnership. The operating lease, under which the space was rented, expired

February

 

28,

1994,

and the space is currently rented on a year-to-year basis under the terms of the expired lease. Rent expense for lease of the corporate office from the Partnership was approximately

$30,000

for

2017

and

2016.

The Company’s investment in the Partnership totaled

$171,243

and

$187,380

at

December 31, 2017

and

2016,

respectively.

Grand Woods Development, LLC (the “LLC”), an Oklahoma limited liability company, with a

47%

ownership. The LLC owns approximately

26.3

acres of undeveloped real estate in northeast Oklahoma City. The Company has guaranteed a loan for which the proceeds were used to purchase a portion of the undeveloped real estate acreage. The Company

’s investment in the LLC totaled

$544,603

and

$635,190

at

December 31, 2017

and

2016,

respectively.

QSN Office Park (“QSN”), an Oklahoma limited liability company acquired in

March 2016,

with a

20%

ownership. QSN is constructing and selling office buildings in a new office park. The Company

’s investment in QSN totaled

$275,248

and

$280,000

at

December 31, 2017

and

2016,

respectively.

The Company

’s Cost Method Investments include:

OKC Industrial Properties (“OKC”), with a

10%

ownership, was acquired in

1992.

OKC originally owned approximately

260

acres of undeveloped land in north Oklahoma City and over time has sold all but approximately

46

acres. The Company’s investment in OKC totaled

$56,164

at

December 31, 2017

and

2016.

Bailey Hilltop Pipeline (“Bailey”), with a

10%

ownership, was acquired in

2008.

Bailey is a gas gathering system pipeline for the Bailey Hilltop Prospect oil and gas properties in Grady County, Oklahoma. The Company’s investment in Bailey totaled

$80,377

at

December 31, 2017

and

2016.

Cloudburst Solutions (“Solutions”), with an

8.125%

ownership, was acquired with an initial investment of

$500,000

in

2014

and an additional investment of

$750,000

in

2016.

Solutions owns exclusive rights to a water purification process technology that is being developed and currently tested. The Company’s investment in Solutions totaled

$1,250,000

at

December 31, 2017

and

2016.

The Company also holds a note receivable of

$175,000

from Solutions.

Ocean’s NG (“Ocean”), with a

12.44%

ownership, was acquired in

2015.

Ocean is developing an underground Compressed Natural Gas (“CNG”) storage and delivery system for retail sales of CNG. The Company’s investment in Ocean totaled

$206,444

and

$200,000

at

December 31, 2017

and

2016,

respectively.

XML

Note 8 - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities

12 Months Ended

Dec. 31, 2017

Notes to Financial Statements

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Text Block]

Note

8

–

COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION, AND DEVELOPMENT ACTIVITIES

All of the Company

’s oil and gas operations are within the continental United States. In connection with its oil and gas operations, the following costs were incurred:

	Year Ended December 31,
	201 7		201 6
Acquisition of Properties:
Unproved	$	568,893	$	715,520
Proved		---		---
Exploration Costs		1,274,931		856,075
Development Costs		976,731		254,351
Asset Retirement Obligation		39,956		18,321

XML

Note 9 - Fair Value Measurements

12 Months Ended

Dec. 31, 2017

Notes to Financial Statements

Fair Value Disclosures [Text Block]

Note

9

–

FAIR VALUE MEASUREMENTS

Inp

uts used to measure fair value are organized into a fair value hierarchy based on how observable the inputs are. Level

1

inputs consist of quoted prices in active markets for identical assets. Level

2

inputs are inputs, other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level

3

inputs are unobservable inputs. During

2017

and

2016

there were

no

transfers into or out of Level

2

or Level

3.

Recurring Fair Value Measurements

Certain of the Company

’s assets are reported at fair value in the accompanying balance sheets on a recurring basis. The Company determined the fair value of the available-for-sale securities using quoted market prices for securities with similar maturity dates and interest rates. At

December 

31,

2017

and

2016,

the Company’s assets reported at fair value on a recurring basis are summarized as follows:

	2017
	Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
Financial Assets:
Available-for-Sale Securities –
U.S. Treasury Bills Maturing in 2018	$	---	$	16,371,544	$	---
Trading Securities –
Domestic Equities		249,210		---		---
International Equities		271,921		---		---
Others		38,805		---		---

	2016
	Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
Financial Assets:
Available-for-Sale Securities –
U.S. Treasury Bills Maturing in 2017	$	---	$	13,443,636	$	---
Trading Securities –
Domestic Equities		333,516		---		---
International Equities		83,948		---		---
Others		56,243		---		---

Non-recurring Fair Value Measurements

The Company

’s asset retirement obligation incurred annually represents non-recurring fair value liabilities. The fair value of the non-financial liabilities incurred was

$31,627

in

2017

and

$18,321

in

2016

and was calculated using Level

3

inputs. See Note

2

for more information about this liability and the inputs used for calculating fair value.

The

fair value of oil and gas properties used in estimating impairment losses of

$426,822

for

2017

and

$727,845

for

2016

were based on Level

3

inputs. See Note

10

for the procedure used for calculating these expenses.

Fair Value of Financial Instruments

The Company

’s financial instruments consist primarily of cash and cash equivalents, trade receivables, marketable securities, trade payables, and dividends payable. As of

December 

31,

2017

and

2016,

the historical cost of cash and cash equivalents, trade receivables, trade payables, and dividends payable are considered to be representative of their respective fair values due to the short-term maturities of these items.

XML

Note 10 - Long-lived Assets Impairment Loss

12 Months Ended

Dec. 31, 2017

Notes to Financial Statements

Long Lived Assets Impairment Loss [Text Block]

Note

10

–

LONG-LIVED ASSETS IMPAIRMENT LOSS

Certain oil and gas producing properties have been deemed to be impaired because the assets, evaluated on a property-by-property basis, are

not

expected to recover their entire carrying value through future cash flows. Impairment losses totaling

$426,822

for

2017

and

$727,845

for

2016

are included in the Statements of Operations in the line item Depreciation, Depletion, Amortization and Valuation Provisions. The impairments for

2017

and

2016

were calculated by reducing the carrying value of the individual properties to an estimated fair value equal to the discounted present value of the future cash flow from these properties. Forward pricing was used for calculating future revenue and cash flow.

XML

Note 11 - Other Income, Net

12 Months Ended

Dec. 31, 2017

Notes to Financial Statements

Other Income and Other Expense Disclosure [Text Block]

Note

11

–

OTHER INCOME, NET

The following is an analysis of the components of Other Income, Net:

	201 7			201 6
Net Realized and Unrealized Gain (Loss) on Trading Securities	$	83,622		$	61,729
Gains on Asset Sales		59,683			22,123
Interest Income		130,498			46,370
Settlements of Class Action Lawsuits		3,540			55,048
Agricultural Rental Income		5,600			5,600
Dividend Income		2,597			1,254
Income from Other Investments		445,000			155,000
Interest and Other Expenses		(47,143	)		(47,532	)
Other Income, Net	$	683,397		$	299,592

XML

Note 12 - Certain Relationships and Related Transactions

12 Months Ended

Dec. 31, 2017

Notes to Financial Statements

Related Party Transactions Disclosure [Text Block]

Note

12

–

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The Company is affiliated by common management and ownership with Mesquite Minerals, Inc. (Mesquite), Mid-American Oil Company (Mid-American)

and Lochbuie Limited Liability Company (LLTD). The Company also owns interests in certain producing and non-producing oil and gas properties as tenants in common with Mesquite, Mid-American and LLTD.

Mesquite, Mid-American and LLTD share facilities and employees including executive officers with the Company. The Company has been reimbursed for services, facilities

, and miscellaneous business expenses incurred in

2017

in the amount of

$190,665

each by Mesquite, Mid-American and LLTD. Reimbursements in

2016

were

$182,926

each by Mesquite, Mid-American and LLTD. Included in the

2017

amounts, Mesquite, Mid-American and LLTD each paid

$137,113

for their share of salaries. In

2016,

the share of salaries paid by Mesquite, Mid-American and LLTD was

$132,215

each.

XML

Supplemental Schedules of Oil and Gas Information

12 Months Ended

Dec. 31, 2017

Notes to Financial Statements

Oil and Gas Exploration and Production Industries Disclosures [Text Block]

SUPPLEMENTAL SCHEDULE

1

THE RESERVE PETROLEUM COMPANY

WORKING INTEREST RESERVE QUANTITY INFORMATION

(Unaudited)

	Year Ended December 31,
	201 7			201 6
Oil and Condensate (Bbls)
Proved Developed and Undeveloped Reserves :
Beginning of Year		401,584			462,241
Revisions of Previous Estimates		18,951			(1,977	)
Extensions and Discoveries		16,405			9,148
Purchase of Reserves		------			---
Production		(60,544	)		(67,828	)
End of Year		376,396			401,584
Proved Developed Reserves:
Beginning of Year		358,822			415,402
End of Year		341,152			358,822
Gas (MCF)
Proved Developed and Undeveloped Reserves:
Beginning of Year		3,023,754			3,637,626
Revisions of Previous Estimates		494,665			(49,227	)
Extensions and Discoveries		190,923			71,715
Purchase of Reserves		---			---
Production		(517,831	)		(636,360	)
End of Year		3,191,511			3,023,754
Proved Developed Reserves:
Beginning of Year		2,809,944			3,309,750
End of Year		2,944,804			2,809,944

See notes on next page.

SUPPLEMENTAL SCHEDULE

1

THE RESERVE PETROLEUM COMPANY

WORKING INTEREST RESERVE QUANTITY INFORMATION

(Unaudited)

Notes

:

1. Estimates of royalty interests ’ reserves, on properties in which the Company does not own a working interest, have not been included because the information required for the estimation of such reserves is not available. The Company’s share of production from its net royalty interests was 16,421 Bbls of oil and 288,743 MCF of gas for 2017 and 17,423 Bbls of oil and 335,081 MCF of gas for 2016.

2. The preceding table sets forth estimates of the Company ’s proved oil and gas reserves, together with the changes in those reserves, as prepared by the Company’s engineer for 2017 and 2016. The Company engineer’s qualifications set forth in the Proxy Statement and as incorporated into Item 10 of this Form 10 -K, are incorporated herein by reference. All reserves are located within the United States.

3. The Company emphasizes that the reserve volumes shown are estimates , which by their nature are subject to revision in the near term. The estimates have been made by utilizing geological and reservoir data, as well as actual production performance data available to the Company. These estimates are reviewed annually and are revised upward or downward as warranted by additional performance data. The Company’s engineer is not independent, but strives to use an objective approach in calculating the Company’s working interest reserve estimates.

4. The Company ’s internal controls relating to the calculation of its working interests’ reserve estimates include review and testing of the accounting data flowing into the calculation of the reserve estimates. In addition, the average oil and natural gas product prices calculated in the engineer’s 2017 summary reserve report was tested by comparison to 2017 average sales price information from the accounting records.

SUPPLEMENTAL SCHEDULE

2

THE RESERVE PETROLEUM COMPANY

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

RELATING TO PROVED WORKING INTEREST

OIL AND GAS RESERVES

(Unaudited)

	At December 31,
	201 7			201 6
Future Cash Inflows	$	25,418,030		$	20,452,614
Future Production and Development Costs		(12,989,835	)		(11,392,251	)
Future Asset Retirement Obligation		(1,881,972	)		(1,802,124	)
Future Income Tax Benefit (Expense)		(362,534	)		369,553
Future Net Cash Flows		10,183,689			7,627,792
10% Annual Discount for Estimated Timing of Cash Flows		(3,121,751	)		(2,373,717	)
Standardized Measure of Discounted Future Net Cash Flows	$	7,061,938		$	5,254,075

Estimates of future net cash flows from the Company

’s proved working interests in oil and gas reserves are shown in the table above. These estimates, which by their nature are subject to revision in the near term, were based on an average monthly product price received by the Company for

2016

and

2017,

with

no

escalation. The development and production costs are based on year-end cost levels, assuming the continuation of existing economic conditions. Cash flows are further reduced by estimated future asset retirement obligations and estimated future income tax expense calculated by applying the current statutory income tax rates to the pretax net cash flows, less depreciation of the tax basis of the properties and depletion applicable to oil and gas production.

SUPPLEMENTAL SCHEDULE

3

THE RESERVE PETROLEUM COMPANY

CHANGES IN STANDARDIZED MEASURE OF

DISCOUNTED FUTURE NET CASH FLOWS FROM

PROVED WORKING INTEREST RESERVE QUANTITIES

(Unaudited)

	Year Ended December 31,
	201 7			201 6
Standardized Measure, Beginning of Year	$	5,254,075		$	7,405,506
Sales and Transfers, Net of Production Costs		(2,343,561	)		(1,935,438	)
Net Change in Sales and Transfer Prices, Net of Production Costs		2,394,155			(1,992,946	)
Extensions, Discoveries and Improved Recoveries, Net of Future Production and Development Costs		710,294			347,007
Revisions of Quantity Estimates		929,958			(62,357	)
Accretion of Discount		689,080			1,006,978
Purchases of Reserves in Place		---			---
Net Change in Income Taxes		(517,818	)		1,009,435
Net Change in Asset Retirement Obligation		17,383			(13,669	)
Changes in Production Rates (Timing) and Other		(71,628	)		(510,441	)
Standardized Measure, End of Year	$	7,061,938		$	5,254,075

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Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Cash and Cash Equivalents, Policy [Policy Text Block]

Cash

and

Cash Equivalents

The Company considers all highly liquid debt instruments purchased with a maturity of

three

months or less to be cash equivalents.

Investment, Policy [Policy Text Block]

Investments

Marketable Securities:

The Company

classifies its debt and marketable equity securities in

one

of

two

categories: trading or available-for-sale. Trading securities are bought and held principally for the purposes of selling them in the near term. All other securities are classified as available-for-sale.

Trading and available-for-sale securities are recorded at fair value.

Unrealized gains and losses on trading securities, which consist primarily of equity securities, are reported in current earnings.

Unrealized gains and losses on a

vailable-for-sale securities, which consist entirely of U.S. Government securities, are reported as a component of other comprehensive income when significant to the financial statements. There are

no

significant cumulative unrealized gains or losses on available-for-sale securities as of

December 31, 2017

or

2016.

Equity

and Cost Method Investments:

The Company accounts for its

non-marketable investment in partnerships on the equity method if ownership allows the Company to exercise significant influence, or the cost method, if

not.

See Note

7

for additional information on investments.

Management reviews our cost method investments and the underlying projects and activity periodically and assesses the need for any impairment. Management does

not

believe any investments need to be impaired at the present time.

Revenue Recognition, Policy [Policy Text Block]

Receivables and Revenue Recognition

Oil and gas sales and resulting receivables are recognized when the product is delivered to the purchaser and title has transferred. Sales are to credit-worthy major energy purchasers with payments generally received within

60

days of transportation from the well site.

Historically, the Company has had little, if any, uncollectible receivables; therefore, an allowance for uncollectible accounts has

not

been provided.

Property, Plant and Equipment, Policy [Policy Text Block]

Property, Plant and Equipment

Oil and gas properties are accounted for on the successful efforts method. The acquisition, exploration and development costs of producing properties are capitalized. The Company has

not

historically had any capitalized exploratory drilling costs that are pending determination of reserves for more than

one

year. All costs relating to unsuccessful exploratory wells, geological and geophysical costs, delay rentals, and abandoned properties are expensed. Lease costs related to unproved properties are amortized over the life of the lease and are assessed for impairment when indicators of impairment are present. Any impairment of value is charged to expense.

Depreciation, depletion and amortization of producing properties

is computed on the units-of-production method on a property-by-property basis. The units-of-production method is based primarily on estimates of proved reserve quantities. Due to uncertainties inherent in this estimation process, it is at least reasonably possible that reserve quantities will be revised in the near term. Changes in estimated reserve quantities are applied to depreciation, depletion and amortization computations prospectively.

Other property and equipment

are depreciated on the straight-line, declining-balance, or other accelerated methods as appropriate.

The following estimated useful lives are used for the different types of property:

Office furniture and fixtures (years)	5	to	10
Automotive equipment (years)	5	to	8

Impairment losses are recorded on long-lived assets used in operations when indicators of impairment are present.

The Company uses its oil and gas reserve reports to test each producing property for impairment quarterly. See Note

10

for discussion of impairment losses.

Income Tax, Policy [Policy Text Block]

Income Taxes

The Company utilizes a

n asset/liability approach to calculating deferred income taxes. Deferred income taxes are provided to reflect temporary differences in the basis of net assets and liabilities for income tax and financial reporting purposes. Deferred tax assets are reduced by a valuation allowance if a determination is made that it is more likely than

not

that some or all of the deferred assets will

not

be realized based on the weight of all available evidence.

The Company recognizes a tax benefit from an uncertain tax position when it is more likely than

not

that the position will be sustained upon examination, based upon the technical merits of the position. The Company will record the largest amount of tax benefit that is greater than

50%

likely of being realized upon settlement with taxing authorities.

The Company recognizes interest and penalties related to unrecognized tax benef

its in income tax expense.

There were

no

uncertain tax positions as of

December 31, 2017

and

2016.

 

The federal income tax returns for

2014,

2015

and

2016

are subject to examination.

Earnings Per Share, Policy [Policy Text Block]

Earnings

Per Share

Accounting guidance

for Earnings Per Share (EPS) establishes the methodology of calculating basic earnings per share and diluted earnings per share. The calculations of basic earnings per share and diluted earnings per share differ in that instruments convertible to common stock (such as stock options, warrants, and convertible preferred stock) are added to weighted average shares outstanding when computing diluted earnings per share. For

2017

and

2016,

the Company had

no

dilutive shares outstanding; therefore, basic and diluted earnings per share are the same.

Concentration Risk, Credit Risk, Policy [Policy Text Block]

Concentrations of Credit Risk and Major Customers

The Company

’s receivables relate primarily to sales of oil and natural gas to purchasers with operations in Texas, Oklahoma, Kansas, and South Dakota. The Company had

two

purchasers in both

2017

and

2016

whose purchases were

35%

of total oil and gas sales.

The Company maintains its cash in bank deposit accounts, which at times

may

exceed federally insured limits. The Company has

not

experienced any losses in such accounts, and believes that it is

not

exposed to any significant credit risk with respect to cash and cash equivalents.

Use of Estimates, Policy [Policy Text Block]

Use of Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include oil and natural gas reserve quantities that form the basis for the calculation of amortization of oil and natural gas properties. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories. Actual results could differ from the estimates and assumptions used in the preparation of the Company

’s financial statements.

Gas Balancing Arrangements, Policy [Policy Text Block]

Gas Balancing

Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability is recorded when the Company

’s excess takes of natural gas volumes exceed our estimated remaining recoverable reserves (over-produced).

No

receivables are recorded for those wells where the Company has taken less than our ownership share of gas production (under-produced).

Minimum Guarantees, Policy [Policy Text Block]

Guarantees

At the inception of a guarantee or subsequent modification, the Company records a liability for the fair value of the obligation undertaken in issuing the guarantee. The Company record

s a liability for its obligations when it becomes probable that the Company will have to perform under the guarantee. The Company has issued guarantees associated with the Company’s equity investments.

Asset Retirement Obligation [Policy Text Block]

Asset Retirement Obligation

The Company records the fair value of its estimated liability to retire its oil and natural gas producing properties in the period in which it is incurred

(typically the date of

first

sales). The estimated liability is calculated by obtaining current estimated plugging costs from the well operators, inflating it over the life of the property and discounting the estimated obligation to its present value. Current year inflation rate used is

4.08%.

When the liability is

first

recorded, a corresponding increase in the carrying amount of the related long-lived asset is also recorded. Subsequently, the asset is amortized to expense over the life of the property and the liability is increased annually for the change in its present value, which is currently

3.25%.

The following table summarizes the

asset retirement obligation for

2017

and

2016:

	201 7			201 6
Beginning balance at January 1	$	1,710,677		$	1,677,328
Liabilities incurred		31,627			18,321
Liabilities settled (wells sold or plugged)		(22,573	)		(20,542	)
Accretion expense		46,574			47,018
Revision to estimate		8,329			(11,448	)
Ending balance at December 31	$	1,774,634		$	1,710,677

New Accounting Pronouncements, Policy [Policy Text Block]

New Accounting Pronouncements

In

May 2014,

the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update

No.

2014

-

09,

Revenue from Contracts with Customers.

ASU

2014

-

09

is a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic

605,

Revenue Recognition, and industry-specific guidance in Subtopic

932

-

605,

Extractive Activities-Oil and Gas-Revenue Recognition. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a

five

-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for

two

transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. In

March,

April,

May

and

December 2016,

the FASB issued new guidance in Topic

606,

Revenue from Contracts with Customers, to address the following potential implementation issues of the new revenue standard: (a) to clarify the implementation guidance on principal versus agent considerations, (b) to clarify the identification of performance obligations and the licensing implementation guidance and (c) to address certain issues in the guidance on assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. This standard is effective for annual reporting periods beginning after

December 

15,

2017,

including interim periods within that reporting period. The Company follows the sales method of accounting for oil and natural gas production, which is generally consistent with the revenue recognition provision of the new standard. The Company has completed the process of evaluating the effect of the adoption and determined there were

no

changes required to our reported revenues as a result of the adoption. The majority of our revenue arrangements generally consist of a single performance obligation to transfer promised goods or services. Based on our evaluation process and review of our contracts with customers, the timing and amount of revenue recognized based on the standard is consistent with our revenue recognition policy under previous guidance. The Company adopted the new standard on

January 

1,

2018,

using the modified retrospective method, and will expand our financial statement disclosures in order to comply with the standard. We have determined the adoption of the standard will

not

have a material impact on our results of operations, cash flows, or financial position.

In

January 2016,

the FASB issued ASU

No.

2016

-

01

,

Recognition and Measurement of Financial Assets and Liabilities

. The update simplifies the accounting and disclosures related to equity investments. The amendments in ASU

2016

-

01

are effective for fiscal years beginning after

December

 

15,

2017

and for interim periods therein. Adoption of this update will

not

have a material impact on the Company’s financial position, results of operations or cash flows.

In

February 2016,

the FASB issued ASU

No.

2016

-

02,

Leases

with new lease accounting guidance. Under the new guidance, at the commencement date, lessees will be required to recognize a lease liability, which is a lessee‘s obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The new guidance is

not

applicable for leases with a term of

12

months or less. Lessor accounting is largely unchanged. ASU

2016

-

02

is effective for the Company for fiscal years beginning after

December 

15,

2018,

including interim periods within those fiscal years. The Company currently has

no

capital or operating leases. Accordingly, we do

not

expect this new guidance to have any impact on the Company’s financial position, results of operations or cash flows.

In

August 2016,

the FASB issued ASU

No.

2016

-

15,

 

Classification of Certain Cash Receipts and Cash Payments

, which addresses certain issues where diversity in practice was identified and

may

change how an entity classifies certain cash receipts and cash payments on its statement of cash flows. The new guidance also clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than

one

class of cash flows. This guidance will generally be applied retrospectively and is effective for public business entities for fiscal years beginning after

December 

15,

2017,

and interim periods within those years. Early adoption is permitted. All of the amendments in ASU

2016

-

15

are required to be adopted at the same time. The Company does

not

expect this new guidance to have a material impact on the Company’s statement of cash flows.

In

January 2017,

the FASB issued ASU

No.

2017

-

01,

Business Combinations (Topic

805

): Clarifying the Definition of a Business

, which clarifies the definition of a business to provide guidance in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU

2017

-

01

provides a screen to determine when a set of assets is

not

a business, requiring that when substantially all fair value of gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set of assets is

not

a business. A framework is provided to assist in evaluating whether both an input and a substantive process are present for the set to be a business. ASU

2017

-

01

is effective for periods beginning after

December 

15,

2017,

including interim periods within those annual periods.

No

disclosures are required at transition and early adoption is permitted. The Company adopted this standard on

January 

1,

2018

and will apply this guidance to any future business combinations.

Reclassification, Policy [Policy Text Block]

Reclassifications

Certain amounts in the

2016

financial statements have been reclassified to conform to the

2017

presentation. The amounts were

not

material to the financial statements and had

no

effect on previously reported net income.

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Note 2 - Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2017

Notes Tables

Schedule Of Useful Lives Of Property And Equipment [Table Text Block]

Office furniture and fixtures (years)	5	to	10
Automotive equipment (years)	5	to	8

Schedule of Asset Retirement Obligations [Table Text Block]

	201 7			201 6
Beginning balance at January 1	$	1,710,677		$	1,677,328
Liabilities incurred		31,627			18,321
Liabilities settled (wells sold or plugged)		(22,573	)		(20,542	)
Accretion expense		46,574			47,018
Revision to estimate		8,329			(11,448	)
Ending balance at December 31	$	1,774,634		$	1,710,677

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Note 4 - Common Stock (Tables)

12 Months Ended

Dec. 31, 2017

Notes Tables

Schedule of Common Stock Outstanding Roll Forward [Table Text Block]

			Shares of
	Shares		Treasury		Shares
	Issued		Stock		Outstanding
January 1, 2016, $.50 par value stock, 200 ,000 shares authorized		184,735		26,277		158,458
Purchase of stock		---		554		(554	)
December 31, 2016, $.50 par value stock, 200 ,000 shares authorized		184,735		26,831		157,904
Purchase of stock		---		239		( 239	)
December 31, 2017, $.50 par value stock, 2 00,000 shares authorized		184,735		27,070		157,665

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Note 6 - Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

Notes Tables

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

	December 31,
	2017			2016
Assets:
Net Leasehold Impairment Reserves	$	189,867		$	290,167
Gas Balance Receivable		32,352			52,379
Long-Lived Asset Impairment		945,399			1,745,936
Deferred Geological and Geophysical Expense		47,539			62,720
Other		266,141			406,579
Total Assets		1,481,298			2,557,781
Liabilities:
Receivables		59,561			91,622
Intangible Drilling Costs		1,614,470			2,856,294
Depletion, Depreciation and Other		725,317			1,121,025
Total Liabilities		2,399,348			4,068,941
Net Deferred Tax Liability	$	(918,050	)	$	(1,511,160	)

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

	Year Ended December 31,
	201 7			201 6
Current Tax Provision /(Benefit):
Federal	$	10,362		$	(57,494	)
State		167			(182	)
Total Current Provision /(Benefit)		10,529			(57,676	)
Deferred Tax Benefit		(593,111	)		(115,210	)
Total Benefit	$	(582,582	)	$	(172,886	)

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

	Year Ended December 31,
	201 7			201 6
Computed Federal Tax Provision/(Benefit)	$	35,035		$	(87,418	)
Increase (Decrease) in Tax From:
Allowable Depletion in Excess of Basis		(51,533	)		(83,460	)
Dividend Received Deduction		(618	)		(878	)
State Income Tax Benefit		(167	)		(182	)
Federal Income Tax Rate Change		(577,797	)		---
Other		12,498			(948	)
Income Tax Benefit	$	(582,582	)	$	(172,886	)
Effective Tax Rate		5%			67%

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Note 8 - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities (Tables)

12 Months Ended

Dec. 31, 2017

Notes Tables

Schedule of Oil and Gas In Process Activities [Table Text Block]

	Year Ended December 31,
	201 7		201 6
Acquisition of Properties:
Unproved	$	568,893	$	715,520
Proved		---		---
Exploration Costs		1,274,931		856,075
Development Costs		976,731		254,351
Asset Retirement Obligation		39,956		18,321

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Note 9 - Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2017

Notes Tables

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

	2017
	Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
Financial Assets:
Available-for-Sale Securities –
U.S. Treasury Bills Maturing in 2018	$	---	$	16,371,544	$	---
Trading Securities –
Domestic Equities		249,210		---		---
International Equities		271,921		---		---
Others		38,805		---		---

	2016
	Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
Financial Assets:
Available-for-Sale Securities –
U.S. Treasury Bills Maturing in 2017	$	---	$	13,443,636	$	---
Trading Securities –
Domestic Equities		333,516		---		---
International Equities		83,948		---		---
Others		56,243		---		---

XML

Note 11 - Other Income, Net (Tables)

12 Months Ended

Dec. 31, 2017

Notes Tables

Interest and Other Income [Table Text Block]

	201 7			201 6
Net Realized and Unrealized Gain (Loss) on Trading Securities	$	83,622		$	61,729
Gains on Asset Sales		59,683			22,123
Interest Income		130,498			46,370
Settlements of Class Action Lawsuits		3,540			55,048
Agricultural Rental Income		5,600			5,600
Dividend Income		2,597			1,254
Income from Other Investments		445,000			155,000
Interest and Other Expenses		(47,143	)		(47,532	)
Other Income, Net	$	683,397		$	299,592

XML

Supplemental Schedules of Oil and Gas Information (Tables)

12 Months Ended

Dec. 31, 2017

Notes Tables

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]

	Year Ended December 31,
	201 7			201 6
Oil and Condensate (Bbls)
Proved Developed and Undeveloped Reserves :
Beginning of Year		401,584			462,241
Revisions of Previous Estimates		18,951			(1,977	)
Extensions and Discoveries		16,405			9,148
Purchase of Reserves		------			---
Production		(60,544	)		(67,828	)
End of Year		376,396			401,584
Proved Developed Reserves:
Beginning of Year		358,822			415,402
End of Year		341,152			358,822
Gas (MCF)
Proved Developed and Undeveloped Reserves:
Beginning of Year		3,023,754			3,637,626
Revisions of Previous Estimates		494,665			(49,227	)
Extensions and Discoveries		190,923			71,715
Purchase of Reserves		---			---
Production		(517,831	)		(636,360	)
End of Year		3,191,511			3,023,754
Proved Developed Reserves:
Beginning of Year		2,809,944			3,309,750
End of Year		2,944,804			2,809,944

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]

	At December 31,
	201 7			201 6
Future Cash Inflows	$	25,418,030		$	20,452,614
Future Production and Development Costs		(12,989,835	)		(11,392,251	)
Future Asset Retirement Obligation		(1,881,972	)		(1,802,124	)
Future Income Tax Benefit (Expense)		(362,534	)		369,553
Future Net Cash Flows		10,183,689			7,627,792
10% Annual Discount for Estimated Timing of Cash Flows		(3,121,751	)		(2,373,717	)
Standardized Measure of Discounted Future Net Cash Flows	$	7,061,938		$	5,254,075

Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]

	Year Ended December 31,
	201 7			201 6
Standardized Measure, Beginning of Year	$	5,254,075		$	7,405,506
Sales and Transfers, Net of Production Costs		(2,343,561	)		(1,935,438	)
Net Change in Sales and Transfer Prices, Net of Production Costs		2,394,155			(1,992,946	)
Extensions, Discoveries and Improved Recoveries, Net of Future Production and Development Costs		710,294			347,007
Revisions of Quantity Estimates		929,958			(62,357	)
Accretion of Discount		689,080			1,006,978
Purchases of Reserves in Place		---			---
Net Change in Income Taxes		(517,818	)		1,009,435
Net Change in Asset Retirement Obligation		17,383			(13,669	)
Changes in Production Rates (Timing) and Other		(71,628	)		(510,441	)
Standardized Measure, End of Year	$	7,061,938		$	5,254,075

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Note 2 - Summary of Significant Accounting Policies (Details Textual) - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Available-for-sale Securities, Accumulated Gross Unrealized Gain (Loss), before Tax	$ 0	$ 0
Unrecognized Tax Benefits	$ 0	$ 0
Weighted Average Number of Shares Outstanding, Diluted	0	0
Current Year Inflation Rate	4.08%
Change In Present Value Percent	3.25%
Customer Concentration Risk [Member] | Sales Revenue, Net [Member]
Number of Major Customers	2
Concentration Risk, Percentage	35.00%
Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member] | Tax Year 2014 [Member]
Open Tax Year	2014
Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member] | Tax Year 2015 [Member]
Open Tax Year	2015
Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member] | Tax Year 2016 [Member]
Open Tax Year	2016

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Note 2 - Summary of Significant Accounting Policies - Property, Plant, and Equipment, Useful Lives (Details)	12 Months Ended
	Dec. 31, 2017
Furniture and Fixtures [Member] | Minimum [Member]
Property useful lives (Year)	5 years
Furniture and Fixtures [Member] | Maximum [Member]
Property useful lives (Year)	10 years
Automobiles [Member] | Minimum [Member]
Property useful lives (Year)	5 years
Automobiles [Member] | Maximum [Member]
Property useful lives (Year)	8 years

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Note 2 - Summary of Significant Accounting Policies - Asset Retirement Obligation (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Balance , asset retirement obligation	$ 1,710,677	$ 1,677,328
Liabilities incurred	31,627	18,321
Liabilities settled (wells sold or plugged)	(22,573)	(20,542)
Accretion expense	46,574	47,018
Revision to estimate	8,329	(11,448)
Balance , asset retirement obligation	$ 1,774,634	$ 1,710,677

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Note 4 - Common Stock - Changes in Common Stock Issued and Outstanding (Details) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Balance, shares issued (in shares)	184,735	184,735
Balance, treasury stock (in shares)	26,831	26,277
Balance, shares outstanding (in shares)	157,904	158,458
Purchase of stock (in shares)	239	554
Purchase of stock (in shares)	(239)	(554)
Balance, shares issued (in shares)	184,735	184,735
Balance, treasury stock (in shares)	27,070	26,831
Balance, shares outstanding (in shares)	157,665	157,904

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Note 4 - Common Stock - Changes in Common Stock Issued and Outstanding (Details) (Parentheticals) - $ / shares	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Common stock, par value (in dollars per share)	$ 0.50	$ 0.50	$ 0.50
Common stock, shares authorized (in shares)	200,000,000	200,000,000	200,000,000

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Note 5 - Marketable Securities (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Trading Securities, Realized Gain (Loss)	$ 34,884	$ (20,430)
Trading Securities, Change in Unrealized Holding Gain (Loss)	$ 48,738	$ 82,159

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Note 6 - Income Taxes (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Expense (Benefit), Continuing Operations, Adjustment of Deferred Tax (Asset) Liability		$ (577,797)
Effective Income Tax Rate Reconciliation, Percent		5.00%	67.00%
Scenario, Forecast [Member]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%

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Note 6 - Income Taxes - Deferred Taxes Components (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Assets:
Net Leasehold Impairment Reserves	$ 189,867	$ 290,167
Gas Balance Receivable	32,352	52,379
Long-Lived Asset Impairment	945,399	1,745,936
Deferred Geological and Geophysical Expense	47,539	62,720
Other	266,141	406,579
Total Assets	1,481,298	2,557,781
Liabilities:
Receivables	59,561	91,622
Intangible Drilling Costs	1,614,470	2,856,294
Depletion, Depreciation and Other	725,317	1,121,025
Total Liabilities	2,399,348	4,068,941
Net Deferred Tax Liability	$ (918,050)	$ (1,511,160)

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Note 6 - Income Taxes - Income Tax Expense, Current and Deferred Portions (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Current Tax Provision/(Benefit):
Federal	$ 10,362	$ (57,494)
State	167	(182)
Total Current Provision/(Benefit)	10,529	(57,676)
Deferred Tax Benefit	(593,111)	(115,210)
Total Benefit	$ (582,582)	$ (172,886)

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Note 6 - Income Taxes - Reconciliation of Computed Income Tax (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Computed Federal Tax Provision/(Benefit)	$ 35,035	$ (87,418)
Increase (Decrease) in Tax From:
Allowable Depletion in Excess of Basis	(51,533)	(83,460)
Dividend Received Deduction	(618)	(878)
State Income Tax Benefit	(167)	(182)
Federal Income Tax Rate Change	(577,797)
Other	12,498	(948)
Total Benefit	$ (582,582)	$ (172,886)
Effective Tax Rate	5.00%	67.00%

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Note 7 - Equity and Cost Method Investments and Related Commitments and Contingent Liabilities Including Guarantees (Details Textual)	12 Months Ended
	Dec. 31, 2017 USD ($) a	Dec. 31, 2016 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 1992 a
Equity Method Investments	$ 991,094	$ 822,570
Cost Method Investments	1,633,300	1,906,856
Notes, Loans and Financing Receivable, Net, Current	$ 175,000
OKC Industrial Properties [Member]
Area of Land | a	46			260
Broadway Sixty-Eight Partnership [Member]
Equity Method Investment, Ownership Percentage	33.00%
Operating Leases, Rent Expense	$ 30,000	30,000
Equity Method Investments	$ 171,243	187,380
Grand Woods Development, LLC [Member]
Equity Method Investment, Ownership Percentage	47.00%
Equity Method Investments	$ 544,603	635,190
Area of Real Estate Property | a	26.3
QSN Office Park [Member]
Equity Method Investment, Ownership Percentage	20.00%
Equity Method Investments	$ 275,248	280,000
OKC Industrial Properties [Member]
Cost Method Investment, Ownership Percentage	10.00%
Cost Method Investments	$ 56,164	56,164
Bailey [Member]
Cost Method Investment, Ownership Percentage	10.00%
Cost Method Investments	$ 80,377	80,377
Cloudburst Solutions [Member]
Cost Method Investment, Ownership Percentage	8.125%
Cost Method Investments	$ 1,250,000	1,250,000
Payments to Acquire Interest in Subsidiaries and Affiliates		750,000	$ 500,000
Notes, Loans and Financing Receivable, Net, Current	$ 175,000
Ocean [Member]
Cost Method Investment, Ownership Percentage	12.44%
Cost Method Investments	$ 206,444	$ 200,000

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Note 8 - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities - Costs Related to Oil and Gas Operations (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Acquisition of Properties:
Unproved	$ 568,893	$ 715,520
Proved
Exploration Costs	1,274,931	856,075
Development Costs	976,731	254,351
Liabilities incurred	$ 31,627	$ 18,321

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Note 9 - Fair Value Measurements (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Liabilities Incurred	$ 31,627	$ 18,321
Impairment Of Oil And Gas Cost Properties	426,822	727,845
Fair Value, Inputs, Level 3 [Member]
Asset Retirement Obligation, Liabilities Incurred	31,627	18,321
Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member]
Impairment Of Oil And Gas Cost Properties	$ 426,822	$ 727,845

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Note 9 - Fair Value Measurements - Schedule of Fair Value Reported on a Recurring Basis (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Available-for-Sale Securities (Notes 2, 5 & 9)	$ 16,371,544	$ 13,443,636
Trading Securities	559,936	473,707
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | US Treasury Securities [Member]
Available-for-Sale Securities (Notes 2, 5 & 9)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Domestic Equities [Member]
Trading Securities	249,210	333,516
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | International Equities [Member]
Trading Securities	271,921	83,948
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Other [Member]
Trading Securities	38,805	56,243
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | US Treasury Securities [Member]
Available-for-Sale Securities (Notes 2, 5 & 9)	16,371,544	13,443,636
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Domestic Equities [Member]
Trading Securities
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | International Equities [Member]
Trading Securities
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Other [Member]
Trading Securities
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | US Treasury Securities [Member]
Available-for-Sale Securities (Notes 2, 5 & 9)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Domestic Equities [Member]
Trading Securities
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | International Equities [Member]
Trading Securities
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Other [Member]
Trading Securities

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Note 10 - Long-lived Assets Impairment Loss (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Impairment Of Oil And Gas Cost Properties	$ 426,822	$ 727,845

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Note 11 - Other Income, Net - Schedule of Components of Other Income, Net (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Net Realized and Unrealized Gain (Loss) on Trading Securities	$ 83,622	$ 61,729
Gains on Asset Sales	59,683	22,123
Interest Income	130,498	46,370
Settlements of Class Action Lawsuits	3,540	55,048
Agricultural Rental Income	5,600	5,600
Dividend Income	2,597	1,254
Income from Other Investments	445,000	155,000
Interest and Other Expenses	(47,143)	(47,532)
Other Income, Net	$ 683,397	$ 299,592

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Note 12 - Certain Relationships and Related Transactions (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Lochbuie Limited Liability Company, LLTD [Member]
Related Party Transaction, Amounts of Transaction	$ 190,665	$ 182,926
Lochbuie Limited Liability Company, LLTD [Member] | Payments For Salaries [Member]
Related Party Transaction, Amounts of Transaction	137,113	132,215
Mesquite [Member]
Related Party Transaction, Amounts of Transaction	190,665	182,926
Mesquite [Member] | Payments For Salaries [Member]
Related Party Transaction, Amounts of Transaction	137,113	132,215
Mid American [Member]
Related Party Transaction, Amounts of Transaction	190,665	182,926
Mid American [Member] | Payments For Salaries [Member]
Related Party Transaction, Amounts of Transaction	$ 137,113	$ 132,215

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Supplemental Schedules of Oil and Gas Information (Details Textual) - bbl	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Oil and Condensate (Bbls) [Member]
Proved Developed and Undeveloped Reserves Production Royalty	16,421	17,423
Gas (MCF) [Member]
Proved Developed and Undeveloped Reserves Production Royalty	288,743	335,081

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Supplemental Schedules of Oil and Gas Information - Working Interest Reserve Quantity Information (Details) - bbl	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Oil and Condensate (Bbls) [Member]
Beginning of Year (Barrel of Oil)	401,584	462,241
Revisions of Previous Estimates (Barrel of Oil)	18,951	(1,977)
Extensions and Discoveries (Barrel of Oil)	16,405	9,148
Purchase of Reserves (Barrel of Oil)
Production (Barrel of Oil)	(60,544)	(67,828)
End of Year (Barrel of Oil)	376,396	401,584
Beginning of Year (Barrel of Oil)	358,822	415,402
End of Year (Barrel of Oil)	341,152	358,822
Gas (MCF) [Member]
Beginning of Year (Barrel of Oil)	3,023,754	3,637,626
Revisions of Previous Estimates (Barrel of Oil)	494,665	(49,227)
Extensions and Discoveries (Barrel of Oil)	190,923	71,715
Purchase of Reserves (Barrel of Oil)
Production (Barrel of Oil)	(517,831)	(636,360)
End of Year (Barrel of Oil)	3,191,511	3,023,754
Beginning of Year (Barrel of Oil)	2,809,944	3,309,750
End of Year (Barrel of Oil)	2,944,804	2,809,944

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Supplemental Schedules of Oil and Gas Information - Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Future Cash Inflows	$ 25,418,030	$ 20,452,614
Future Production and Development Costs	(12,989,835)	(11,392,251)
Future Asset Retirement Obligation	(1,881,972)	(1,802,124)
Future Income Tax Benefit (Expense)	(362,534)	369,553
Future Net Cash Flows	10,183,689	7,627,792
10% Annual Discount for Estimated Timing of Cash Flows	(3,121,751)	(2,373,717)
Standardized Measure of Discounted Future Net Cash Flows	$ 7,061,938	$ 5,254,075	$ 7,405,506

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Supplemental Schedules of Oil and Gas Information - Changes in Standardized Measure of Discounted Future Net Cash Flows From Proved Working Interest Reserve Quantities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Standardized Measure, Beginning of Year	$ 5,254,075	$ 7,405,506
Sales and Transfers, Net of Production Costs	(2,343,561)	(1,935,438)
Net Change in Sales and Transfer Prices, Net of Production Costs	2,394,155	(1,992,946)
Extensions, Discoveries and Improved Recoveries, Net of Future Production and Development Costs	710,294	347,007
Revisions of Quantity Estimates	929,958	(62,357)
Accretion of Discount	689,080	1,006,978
Purchases of Reserves in Place
Net Change in Income Taxes	(517,818)	1,009,435
Net Change in Asset Retirement Obligation	17,383	(13,669)
Changes in Production Rates (Timing) and Other	(71,628)	(510,441)
Standardized Measure, End of Year	$ 7,061,938	$ 5,254,075