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, 2018

☐ 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 every Interactive Data File required to be submitted 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 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 ☐ Non-accelerated filer ☑ Accelerated filer ☐

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, 2018 (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 $20,938,864, as computed by reference to the last reported sale which was on June 29, 2018.

As of March 21, 2019, there were 156,962 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 21, 2019, which will be filed within 120 days of the end of the registrant’s year ended December 31, 2018, 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	7
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	7
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	15
Item 8.	Financial Statements and Supplementary Data	15
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	37
Item 9A.	Controls and Procedures	37
Item 9B.	Other Information	38
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	38
Item 11.	Executive Compensation	38
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	38
Item 13.	Certain Relationships and Related Transactions and Director Independence	38
Item 14.	Principal Accountant Fees and Services	38
PART IV
Item 15.	Exhibits and Financial Statement Schedules	39
Item 16.	Form 10-K Summary	39

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 256,270 gross acres equivalent to 88,246 net acres. These mineral interests are located in ten different states in the north and south central United States. A total of 81,113 (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 2018, $3,149,054 (41%) of oil and gas sales was from royalty interests versus $1,737,841 (28%) in 2017. As a result of our mineral ownership, the Company had royalty interests in 23 gross (0.31 net) wells, which were drilled and completed as producing wells in 2018. This resulted in an average royalty interest of about 1.4% for these 23 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 2018, the Company participated in the drilling of 7 development wells with 5 wells (0.68 net) completed as producers and 2 wells in progress at year-end 2018.

3

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.

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 2018, we participated in the drilling of 8 exploratory wells with 2 wells (0.18 net) completed as producers, 3 wells in progress at the end of 2018 and 3 wells (0.24 net) completed as dry holes.

For a summation of exploratory and development wells drilled in 2018 or planned for in 2019, 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, 2017.”

Customers

In 2018, the Company had two customers whose total purchases were greater than 10% of revenues from oil and gas sales. Redland Resources, LLC purchases were $1,481,719 or 19% of total oil and gas sales and Luff Exploration Company purchases were $889,496 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 or certainty.

4

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 Method and Other Investments” and Item 8, Notes 2 and 7 to the accompanying financial statements for a discussion of other business including guarantees.

Employees

At December 31, 2018, the Company had nine employees, including officers. See the Proxy Statement for additional information. During 2018, 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 40% of them being working interest properties and the remaining 60% being royalty interest properties. About 81% of all properties are located in Oklahoma and Texas and account for approximately 74% of our annual oil and gas sales. About 15% of the properties are located in Arkansas, Kansas and South Dakota and account for approximately 24% of our annual oil and gas sales. The remaining 4% of these properties are located in Colorado, Montana, Nebraska and New Mexico 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 32 for working interest reserve quantity information.

5

Since January 1, 2018, 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 2017 Annual Report on Form 10-K and federal income tax return for the year ended December 31, 2017. 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, 2018, 2017 and 2016. 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
2018	$	62.48	$	2.93	$	60.87	$	2.79	$	2.72
2017	$	47.95	$	2.91	$	46.00	$	2.91	$	2.25
2016	$	38.53	$	2.21	$	36.49	$	2.16	$	1.85

At December 31, 2018, the Company had working interests in 183 gross (26.7 net) wells producing primarily gas and 241 gross (23.86 net) wells producing primarily oil. These interests were in 66,160 gross (7,892 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, 2018.

	Acreage
	Gross		Net
Non-producing Mineral Interests		256,270		88,246
Undeveloped Leaseholds		77,559		13,655

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, 2016 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 2018 include the 3 exploratory wells still drilling at the end of 2017. As indicated in the “Exploration Program” on Page 4, 3 exploratory wells were still in progress at the time of this Form 10-K.

	Number of Net Working Interest Wells Drilled
	Exploratory				Development
	Productive		Dry		Productive		Dry
2018		0.18		0.24		0.68		---
2017		0.50		0.95		0.35		---
2016		0.16		1.41		0.47		---

Recent Activities

See Item 7, under the subheading “Update of Oil and Gas Exploration and Development Activity from December 31, 2017” 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.

6

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
03/31/17	$	245	$	197
06/30/17	$	246	$	211
09/30/17	$	230	$	205
12/31/17	$	226	$	195
03/31/18	$	220	$	201
06/30/18	$	212	$	182
09/30/18	$	207	$	180
12/31/18	$	212	$	178

There was limited public trading in the Company’s common stock in 2018 and 2017. There were 5 brokered trades appearing in the Company’s transfer ledger for 2018 and 2017.

At March 21, 2019, the Company had approximately 1,841 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 2018 and in the second quarter of 2017. 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 2019, 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, 2018		9	$	150		---		---
November 1 to November 30, 2018		6	$	150		---		---
December 1 to December 31, 2018		25	$	150		---		---
Total		40	$	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.

7

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 2019 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.

● 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.

8

● 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.

● 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 20% 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 METHOD AND OTHER INVESTMENTS

For equity method investments, the Company records the original investment in the entities 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 entities. The Company does not have actual or effective control of the entities. The management of the entities 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 investments. These investments include Broadway Sixty-Eight, Ltd. (the “Partnership”), Grand Woods Development, LLC (the “LLC”), and QSN Office Park (“QSN”).

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, less any impairment, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer. Cash distributions from the investment are recognized as income when received. These investments include OKC Industrial Properties (“OKC”), Bailey Hilltop Pipeline (“Bailey”), Cloudburst Solutions (“Solutions”), and Ocean’s NG (“Ocean”).

See Item 8, Note 7 to the accompanying financial statements for related disclosures and additional information regarding all investments.

9

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 2018, 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 debt 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 debt 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 debt securities. Cash equivalents are highly liquid debt instruments purchased with a maturity of three months or less. All of the available-for-sale debt securities are U.S. Treasury Bills.

In 2018, net cash provided by operating activities was $4,846,100. Sales (including lease bonuses), net of production costs and general and administrative costs were $4,286,085, which accounted for 88% of net cash provided by operations. The remaining components provided 12% of cash flow. In 2018, net cash applied to investing activities was $2,161,108. In 2018, dividend payments and treasury stock purchases totaled $1,024,303 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:

Equity securities decreased $105,878 (19%) to $454,058 in 2018 from $559,936 in 2017. The net decrease is due to $181,818 in unrealized losses, which represent the change in the fair value of the securities from their original cost, plus $75,940 of 2018 income.

Refundable income taxes decreased $310,443 (95%) to $16,387 in 2018 from $326,830 in 2017.

In 2018, the Company added a note receivable in the amount of $43,158 to the LLC.

Accounts payable increased $83,380 (35%) to $318,387 in 2018 from $235,007 in 2017. This increase was primarily due to increased drilling activity.

10

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, 2018 and 2017. 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 2018 were $4,846,100, which, when compared to the $2,771,452 provided in 2017, represents a net increase of $2,074,648. The increase was mostly due to an increase in lease bonus cash flows of $377,902 and an increase in oil and gas sales of $1,760,668. Additional discussion of the significant items follows.

The $1,760,668 (29%) increase in cash received from oil and gas sales to $7,790,371 in 2018 from $6,029,703 in 2017 was the result of an increase in oil and gas sales volumes and an increase in oil sales price, offset by a decrease in gas sales price. See “Results of Operations” below for a price/volume analysis and the related discussion of oil and gas sales.

Cash received for lease bonuses increased $377,902 (205%) to $562,184 in 2018 from $184,282 in 2017.

The 2018 cash distribution of $24,750 from our equity method investment in Broadway Sixty-Eight, Ltd. was primarily for our share of operating profits versus $49,500 in 2017. 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 $3,041,054 (58%) to $2,161,108 in 2018 from $5,202,162 in 2017. This decrease was primarily due to increases in the maturity of available-for-sale debt securities of $2,944,915 and property dispositions of $436,460, offset by a decrease in cash received from other investments of $428,500. See “Equity Method and Other Investments” discussion on page 9 for additional information regarding the investments purchased in 2018 and 2017.

Financing Activities

Cash applied to financing activities increased $150,969 (17%) to $1,024,303 in 2018 from $873,334 in 2017. Cash applied to financing activities consist of cash dividends on common stock and cash used for the purchase of treasury stock. In 2018, cash dividends paid on common stock amounted to $959,499 as compared to $837,505 in 2017. Dividends of $5.00 per share were paid in 2018 and 2017. Cash applied to purchase treasury stock increased $28,975 to $64,804 in 2018 from $35,829 in 2017.

Forward-Looking Summary

The Company’s latest estimate of business to be done beyond 2018 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, the Company could require external sources of financing.

RESULTS OF OPERATIONS

As disclosed in the statements of income in Item 8 of this Form 10-K, in 2018 the Company had net income of $2,313,692 as compared to net income of $685,687 in 2017. Net income per share, basic and diluted, was $14.69 in 2018, an increase of $10.34 per share from $4.35 in 2017. Material line item changes in the statements of income will be discussed in the following paragraphs.

Operating Revenues

Operating revenues increased $2,017,908 to $8,327,498 in 2018 from $6,309,590 in 2017. Oil and gas sales increased $1,640,006 (27%) to $7,765,314 in 2018 from $6,125,308 in 2017. Lease bonuses and other revenues increased $377,902 (205%) to $562,184 in 2018 from $184,282 in 2017. The increase in oil and gas sales is discussed in the following paragraphs.

11

The $1,640,006 increase in oil and gas sales was the result of a $41,339 increase in gas sales, a $1,537,330 increase in oil sales and a $61,337 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 2017 to 2018. Miscellaneous oil and gas product sales of $267,929 in 2018 and $206,592 in 2017 are not included in the analysis.

			Variance
Production	2018		Price		Volume		2017
Gas –
MCF (000 omitted)		837				31		806
$ (000 omitted)	$	2,388	$	(47)	$	89	$	2,346
Unit Price	$	2.85	$	(.06)			$	2.91
Oil –
Bbls (000 omitted)		83				6		77
$ (000 omitted)	$	5,110	$	1,251	$	287	$	3,572
Unit Price	$	61.45	$	15.03			$	46.42

The $41,339 (2%) increase in natural gas sales to $2,387,611 in 2018 from $2,346,272 in 2017 was the result of an increase in gas sales volumes offset by a decrease in the average price received per thousand cubic feet (MCF). The average price per MCF of natural gas sales decreased $0.06 per MCF to $2.85 per MCF in 2018 from $2.91 per MCF in 2017, resulting in a negative gas price variance of $47,016. A positive volume variance of $88,355 was the result of an increase in natural gas volumes sold of 30,363 MCF to 836,938 MCF in 2018 from 806,575 MCF in 2017. The increase in the volume of gas production was the net result of new 2018 production of about 152,000 MCF, offset by a decline of about 122,000 MCF in production from previous wells. 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 2018 or 2017.

The gas production for 2018 and 2017 includes production from about 100 royalty interest properties drilled by various operators in Robertson County, Texas. These properties accounted for approximately 277,000 MCF and $802,000 of the 2018 gas sales and approximately 187,000 MCF and $544,000 of the 2017 gas sales. These properties accounted for about 35% of the Company’s gas revenues in 2018 versus 23% in 2017. The Company has no control over the timing of future drilling on the acreage in which we hold mineral interests.

The $1,537,330 (43%) increase in crude oil sales to $5,109,773 in 2018 from $3,572,443 in 2017 was the result of increases in the average price per barrel (Bbl) and oil sales volumes. The average price received per Bbl of oil increased $15.03 to $61.45 in 2018 from $46.42 in 2017, resulting in a positive oil price variance of $1,250,183. An increase in oil sales volumes of 6,186 Bbls to 83,151 Bbls in 2018 from 76,965 Bbls in 2017 resulted in a positive volume variance of $287,146. The increase in the oil volume production was the net result of new 2018 production of about 20,000 Bbls, offset by a 14,000 Bbl decline in production from previous wells. 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 2018 or 2017.

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 $457,750 (7%) to $6,370,156 in 2018 from $6,827,906 in 2017, primarily due to a decrease in exploration expense. The material components of operating costs and expenses are discussed below.

Production Costs. Production costs increased $201,636 (9%) to $2,391,656 in 2018 from $2,190,020 in 2017. The increase was a result of a $104,875 (37%) increase in gross production tax to $390,563 in 2018 from $285,688 in 2017, and an increase in lease operating and other production costs of $96,762 (5%) to $2,001,093 in 2018 from $1,904,331 in 2017. 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.

12

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 $2,428,412 in 2018 and $2,251,662 in 2017. See Item 8, Note 8 to the accompanying financial statements for a breakdown of these costs. Exploration costs charged to operations were $195,111 in 2018 and $883,593 in 2017, inclusive of geological and geophysical costs of $162,514 in 2018 and $243,251 in 2017.

Update of Oil and Gas Exploration and Development Activity from December 31, 2017. For the year ended December 31, 2018, the Company participated in the drilling of 8 gross exploratory working interest wells (including 3 in progress at the end of 2017) and 7 gross development working interest wells, with working interests ranging from a high of 18% to a low of 4.7%. Of the 8 exploratory wells, 2 were completed as producing wells, 3 as dry holes and 3 were in progress. Five (5) development wells were completed as producing wells and 2 were in progress at the end of 2018.

The following is a summary as of March 6, 2019, updating both exploration and development activity from December 31, 2017, for the period ended December 31, 2018.

The Company participated with 12% and 8% working interests in the drilling of two development wells on a Woods County, Oklahoma prospect. Both wells were completed as commercial oil and gas producers. Capitalized costs for the period were $135,623.

The Company participated with 12.1% and 9.5% working interests in the drilling of two development wells on a Woods County, Oklahoma prospect. One well has been completed and is awaiting pipeline connection and a completion is in progress on the other. Capitalized costs for the period were $105,615.

The Company participated with its 18% working interest in the drilling of a development well on a Barber County, Kansas prospect. The well was completed as a commercial oil and gas producer. Capitalized costs for the period were $70,875.

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 dry hole. No additional drilling is planned on the prospect. Dry hole costs for the period were $15,107 and an impairment expense of $19,258 was taken against the leasehold.

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. No additional drilling is planned on the prospect. Dry hole costs for the period were $19,949 and an impairment expense of $684 was taken against the leasehold.

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. Both wells were completed as commercial oil and gas producers. Actual costs of $122,627 for the period were offset by prepaid costs from 2017 for a net capitalized amount of $0.

The Company participated with its 14% working interest in the drilling of two injection wells on a Hansford County, Texas waterflood unit. One well was completed and is injecting water and the other missed the reservoir and was plugged. There are three other injection wells and two producing wells in the unit. Actual costs of $268,250 for the period were offset by $103,936 of prepaid costs from 2017 for a net capitalized amount of $164,314.

The Company is participating with its 14% interest in the reworking of previously acquired 3-D seismic and in the acquisition of additional leasehold on a Creek County, Oklahoma prospect. The Company also participated in the deepening of an existing well on the prospect. The well has been completed and appears to be a marginal oil producer. Leasehold costs for the period were $17,622 and seismic costs were $3,357. Additional capitalized costs were $17,873.

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 has entered into an agreement whereby a third party will drill two strat tests on the prospect, earning the option to purchase a 50% interest in the acreage and conduct a thermal recovery pilot test. The strat tests will be drilled in March 2019. Geological costs for the period were $1,916.

The Company is participating with a 35% interest in the development of a Val Verde County, Texas prospect on which 312.6 net acres of leasehold have been acquired. Leasehold costs for the period were $10,603.

The Company owns a 12.25% interest in 4,882.5 net acres of leasehold on a Crockett County, Texas prospect. An exploratory well was drilled on the prospect in 2017. A completion attempt of the well was unsuccessful and it has been plugged. A dry hole expense of $32,040 was taken against the well.

13

The Company is participating with a 13% interest in a 3-D seismic prospect covering approximately 35,000 acres in San Patricio County, Texas. A 3-D seismic survey of the prospect area has been completed and analysis of the data is ongoing. Eleven prospects have already been identified and lease acquisition is in progress on five. An exploratory well has been drilled and completed on one prospect and is awaiting pipeline connection. Leasehold costs for the period were $44,107 and seismic costs were $107,752. Prepaid drilling costs were $155,125.

The Company participated with its 10.5% working interest in the completion of an exploratory well that was drilled in 2017 on a Lea County, New Mexico prospect. The well is a marginal oil producer. Capitalized costs for the period were $65,421 and an impairment expense of $265,818 was taken against the well.

The Company participated with its 7% working interest in the drilling of an exploratory well on a Summit County, Utah prospect. The well has been completed as a commercial gas and gas condensate producer and is awaiting pipeline connection. Capitalized costs for the period were $994,180.

The Company is participating with its 11.2% working interest in workovers on a group of wells that were purchased in 2017 on a Tyler County, Texas prospect. The workovers performed so far have been successful in significantly increasing production. Capitalized costs for the period were negligible as most of the work was charged to expense.

The Company participated with its 8.33% working interest in the drilling of a horizontal well in a Harding County, South Dakota producing unit in an effort to develop the unit for waterflooding. An attempt to complete the well as an oil producer was unsuccessful and it is under evaluation for possible use as an injector. Capitalized costs for the period were $150,969.

The Company has been participating with a 50% interest in an attempt to develop shallow oil prospects in the Permian Basin. Lease acquisition is in progress on one prospect in Crane County, Texas. The Company will sell a portion of its interest prior to any drilling. Geological costs were $48,961 for the period and leasehold costs were $13,691.

In October 2018, the Company purchased a 16% interest in 784.12 net acres of leasehold on a Barber County, Kansas prospect for $12,546. An exploratory well has been drilled on the prospect and a completion is in progress. Additional capitalized costs for the period were $51,814.

In October 2018, the Company entered into an agreement to acquire mineral rights in Tyler, Doddridge and Ritchie Counties, West Virginia. The Company is funding the acquisition of the mineral rights which will then be sold to a third party for a profit, with the Company retaining an interest in the minerals. Costs for the period were $173,220.

In November 2018, the Company purchased a 10.5% interest in 3,410 net acres of leasehold on an Oldham County, Texas prospect for $179,025. The Company participated in the drilling of an exploratory well on the prospect. A completion is in progress. Additional capitalized costs for the period were $187,051.

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 $240,635 in 2018, of which $27,463 were specific impairments, and $363,431 in 2017.

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 2018 and 2017. The 2018 impairment loss was $832,651 and the 2017 impairment loss was $426,823.

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 provision for depletion and depreciation declined $311,113 to $1,000,945 in 2018 from $1,312,058 in 2017. This decrease is due to higher oil prices in 2018 compared to 2017. The provision also includes $65,615 for 2018 and $81,035 for 2017 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.

14

Other Income, Net. See Item 8, Note 11 to the accompanying financial statements for an analysis of the components of this line item for 2018 and 2017. Other income, net increased $145,317 (21%) to $828,714 in 2018 from $683,397 in 2017. The line items responsible for this net increase are described below.

Net realized and unrealized gain (loss) on equity securities decreased $192,490 to a net loss of $(108,868) in 2018 from a net gain of $83,622 in 2017. Realized gains or losses result when an equity security is sold. Unrealized gains or losses result from adjusting the Company’s carrying amount in equity securities owned at the reporting date to estimated fair value. In 2018, the Company had realized gains of $72,950 and unrealized losses of $(181,818). In 2017, the Company had realized gains of $34,884 and unrealized gains of $48,738.

Income from other investments decreased $428,500 to $16,500 in 2018 from $445,000 in 2017.

Gains on asset sales increased $551,598 to $611,281 in 2018 from $59,683 in 2017.

Interest income increased $218,117 to $348,615 in 2018 from $130,498 in 2017. 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 debt securities from which most of the interest income is derived. The average interest rate increased from 0.43% in 2017 to 1.56% in 2018. The average balance outstanding increased $3,633,895 to $19,045,941 in 2018 from $15,412,046 in 2017.

Provision for Income Taxes. In 2018, the Company had an estimated income tax provision of $387,880 as the result of a deferred tax provision of $292,221 and a current tax provision of $95,659. 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. 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	16
Balance Sheets – December 31, 2018 and 2017	17
Statements of Income – Years Ended December 31, 2018 and 2017	19
Statements of Stockholders’ Equity – Years Ended December 31, 2018 and 2017	20
Statements of Cash Flows – Years Ended December 31, 2018 and 2017	21
Notes to Financial Statements	23
Unaudited Supplemental Financial Information	32

15

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, 2018 and 2017, the related statements of income, 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, 2018 and 2017, 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 27, 2019

16

THE RESERVE PETROLEUM COMPANY

BALANCE SHEETS

ASSETS

	December 31,
	2018		2017
Current Assets:
Cash and Cash Equivalents (Note 2)	$	6,428,499	$	4,767,810
Available-for-Sale Debt Securities (Notes 2, 5 & 9)		16,249,414		16,371,544
Equity Securities (Notes 2, 5 & 9)		454,058		559,936
Refundable Income Taxes		16,387		326,830
Accounts Receivable (Note 2)		846,419		829,824
Notes Receivable (Note 7)		218,158		175,000
Total Current Assets		24,212,935		23,030,944
Investments:
Equity Method Investments (Notes 2 & 7)		881,860		991,094
Other Investments (Notes 2 & 7)		1,689,249		1,633,300
Total Investments		2,571,109		2,624,394
Property, Plant and Equipment (Notes 2, 8 & 10):
Oil and Gas Properties, at Cost,
Based on the Successful Efforts Method of Accounting –
Unproved Properties		2,249,113		2,296,686
Proved Properties		54,789,836		53,536,453
Oil and Gas Properties, Gross		57,038,949		55,833,139
Less – Accumulated Depreciation, Depletion, Amortization and Valuation Allowance		46,008,467		45,335,894
Oil and Gas Properties, Net		11,030,482		10,497,245
Other Property and Equipment, at Cost		403,718		404,256
Less – Accumulated Depreciation		249,333		253,239
Other Property and Equipment, Net		154,385		151,017
Total Property, Plant and Equipment		11,184,867		10,648,262
Total Assets	$	37,968,911	$	36,303,600

See Accompanying Notes

17

THE RESERVE PETROLEUM COMPANY

BALANCE SHEETS

LIABILITIES AND STOCKHOLDERS’ EQUITY

	December 31,
	2018		2017
Current Liabilities:
Accounts Payable	$	318,387	$	235,007
Other Current Liabilities		25,243		25,243
Total Current Liabilities		343,630		260,250
Long-Term Liabilities:
Asset Retirement Obligation (Note 2)		1,774,114		1,774,634
Dividends Payable (Note 3)		1,057,483		1,228,648
Deferred Tax Liability, Net (Note 6)		1,210,271		918,050
Total Long-Term Liabilities		4,041,868		3,921,332
Total Liabilities		4,385,498		4,181,582
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		35,023,662		33,497,463
Stockholders’ Equity Before Treasury Stock		35,181,030		33,654,831
Less – Treasury Stock, at Cost		1,597,617		1,532,813
Total Stockholders’ Equity		33,583,413		32,122,018
Total Liabilities and Stockholders’ Equity	$	37,968,911	$	36,303,600

See Accompanying Notes

18

THE RESERVE PETROLEUM COMPANY

STATEMENTS OF INCOME

	Year Ended December 31,
	2018			2017
Operating Revenues:
Oil and Gas Sales (Note 2)	$	7,765,314		$	6,125,308
Lease Bonuses and Other		562,184			184,282
Total Operating Revenues		8,327,498			6,309,590
Operating Costs and Expenses:
Production		2,391,656			2,190,020
Exploration		195,111			883,593
Depreciation, Depletion, Amortization and Valuation Provisions (Note 10)		2,103,882			2,133,338
General, Administrative and Other		1,679,507			1,620,955
Total Operating Costs and Expenses		6,370,156			6,827,906
Income/(Loss) from Operations		1,957,342			(518,316	)
Equity Loss in Investees (Note 7)		(84,484	)		(61,976	)
Other Income, Net (Note 11)		828,714			683,397
Income Before Income Taxes		2,701,572			103,105
Income Tax Provision/(Benefit) (Notes 2 & 6)		387,880			(582,582	)
Net Income	$	2,313,692		$	685,687
Per Share Data (Note 2):
Net Income, Basic and Diluted	$	14.69		$	4.35
Cash Dividends	$	5.00		$	5.00
Weighted Average Shares Outstanding, Basic and Diluted		157,458			157,788

See Accompanying Notes

19

THE RESERVE PETROLEUM COMPANY

STATEMENTS OF STOCKHOLDERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2018 AND 2017

			Additional
	Common		Paid-in		Retained			Treasury
	Stock		Capital		Earnings			Stock			Total
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
Net Income		---		---		2,313,692			---			2,313,692
Dividends Declared		---		---		(787,493	)		---			(787,493	)
Purchase of Treasury Stock		---		---		---			(64,804	)		(64,804	)
Balance at December 31, 2018	$	92,368	$	65,000	$	35,023,662		$	(1,597,617	)	$	33,583,413

See Accompanying Notes

20

THE RESERVE PETROLEUM COMPANY

STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2018			2017
Cash from Operating Activities:
Cash Received –
Oil and Gas Sales	$	7,790,371		$	6,029,703
Lease Bonuses and Other		562,184			184,282
Sale of Equity Securities		1,514,362			3,483,394
Interest Received		315,146			119,265
Agricultural Rentals and Other		6,008			9,140
Dividends Received on Equity Securities		2,902			2,597
Cash Distributions from Equity Method Investments		24,750			49,500
Income Tax Refunds, Net of Income Taxes Paid		214,784			199,439
Cash Paid –
Production Costs		(2,391,711	)		(2,195,844	)
General Suppliers, Employees and Taxes, Other than Income Taxes		(1,674,759	)		(1,623,453	)
Purchase of Equity Securities		(1,517,352	)		(3,486,002	)
Farm Expense and Other		(585	)		(569	)
Net Cash Provided by Operating Activities		4,846,100			2,771,452
Cash Provided by/(Applied to) Investing Activities:
Maturity of Available-for-Sale Debt Securities		32,786,554			29,841,639
Purchase of Available-for-Sale Debt Securities		(32,664,425	)		(32,769,546	)
Proceeds from Disposal of Property, Plant and Equipment		587,408			150,948
Purchase of Property, Plant and Equipment		(2,788,038	)		(2,688,759	)
Cash Distributions from Other Investments		16,500			445,000
Purchase of Other Investments		(55,949	)		(6,444	)
Notes Receivable		(43,158	)		(175,000	)
Net Cash Applied to Investing Activities		(2,161,108	)		(5,202,162	)

See Accompanying Notes

21

THE RESERVE PETROLEUM COMPANY

STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2018			2017
Cash Applied to Financing Activities:
Dividends Paid to Stockholders	$	(959,499	)	$	(837,505	)
Purchase of Treasury Stock		(64,804	)		(35,829	)
Total Cash Applied to Financing Activities		(1,024,303	)		(873,334	)
Net Change in Cash and Cash Equivalents		1,660,689			(3,304,044	)
Cash and Cash Equivalents at Beginning of Year		4,767,810			8,071,854
Cash and Cash Equivalents at End of Year	$	6,428,499		$	4,767,810
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	$	2,313,692		$	685,687
Net Income Increased (Decreased) by Net Change in –
Net Unrealized Holding (Gains)/Losses on Equity Securities		181,818			(48,738	)
Accounts Receivable		25,057			(95,259	)
Interest and Dividends Receivable		(33,469	)		(11,233	)
Refundable Income Taxes		310,443			209,968
Accounts Payable		4,692			(13,034	)
Equity Securities		(75,940	)		(37,491	)
Deferred Taxes		292,221			(593,111	)
Other Liabilities		(12,030	)		46,228
(Income)/Loss from Equity Method and Other Investments		67,984			(383,024	)
Cash Distribution from Equity Method Investments		24,750			49,500
Exploration Costs		205,671			838,145
Disposition of Property, Plant and Equipment		(562,671	)		(9,524	)
Depreciation, Depletion, Amortization and Valuation Provisions		2,103,882			2,133,338
Net Cash Provided by Operating Activities	$	4,846,100		$	2,771,452

See Accompanying Notes

22

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: equity or available-for-sale. Equity 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 debt securities.

Equity securities and available-for-sale debt securities are recorded at fair value. Unrealized gains and losses on equity securities are reported in current earnings.

Unrealized gains and losses on available-for-sale debt 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 debt securities as of December 31, 2018 or 2017.

Equity Method and Other Investments:

The Company accounts for its non-marketable investment in partnerships on the equity method if ownership allows the Company to exercise significant influence.

The Financial Accounting Standards Board (FASB) issued ASU 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”). The Company early adopted ASU 2016-01 effective July 1, 2018. ASU 2016-01 applies to all entities that hold financial assets or owe financial liabilities and is intended to provide more useful information on the recognition, measurement, presentation and disclosure of financial instruments. Among other things, ASU 2016-01 (i) requires equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income; (ii) simplifies the impairment assessment of equity investments without readily determinable fair values by requiring a qualitative assessment to identify impairment; (iii) eliminates the requirement to disclose the fair value of financial instruments measured at amortized cost for entities that are not public business entities; (iv) eliminates the requirement for public business entities to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost on the balance sheet; (v) requires public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes; (vi) requires an entity to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments; (vii) requires separate presentation of financial assets and financial liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements; and (viii) clarifies that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The adoption of this guidance did not have a material effect on the Company’s financial position, results of operation or cash flows.

Other investments, without readily determinable fair values, that are not accounted for under the equity method are measured at cost, less any impairment, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer. Management reviews our other 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.

The FASB issued Revenue from Contracts with Customers (Topic 606) superseding virtually all existing revenue recognition guidance. We adopted this new standard in the first quarter of 2018 using the modified retrospective approach. Adoption of the new standard did not require an adjustment to the opening balance of equity and did not have an impact on income from operations, earnings per share or cash flows.

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The Company’s revenues are primarily derived from its interests in the sale of oil and natural gas production. Each barrel of oil or thousand cubic feet of natural gas delivered is considered a separate performance obligation. The Company recognizes revenue from its interests in the sales of oil and natural gas in the period that its performance obligations to provide oil and natural gas to customers are satisfied. Performance obligations are satisfied when the Company has no further obligations to perform related to the sale and the customer obtains control of product. The sales of oil and natural gas are made under contracts which the third-party operators of the wells have negotiated with customers, which typically include variable consideration that is based on pricing tied to local indices and volumes delivered in the current month. The Company receives payment from the sale of oil and natural gas production from one to three months after delivery. At the end of each month, as performance obligations are satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in accounts receivable in the balance sheets. Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received; however, differences have been and are insignificant. Accordingly, the variable consideration is not constrained. A portion of oil and gas sales recorded in the statements of income are the result of estimated volumes and pricing for oil and gas product not yet received for the period. For the periods ending December 31, 2018 and 2017, that estimate represented approximately $346,711 and $283,626, respectively, of accrued oil and gas sales included in the statements of income.

The Company’s contracts with customers originate at or near the time of delivery and transfer of control of oil and natural gas to the purchasers. As such, the Company does not have significant unsatisfied performance obligations.

The Company’s oil is typically sold at delivery points under contracts terms that are common in our industry. The Company's natural gas produced is delivered by the well operators to various purchasers at agreed upon delivery points under a limited number of contract types that are also common in our industry. However, under these contracts, the natural gas may be sold to a single purchaser or may be sold to separate purchasers. Regardless of the contract type, the terms of these contracts compensate the well operators for the value of the oil and natural gas at specified prices, and then the well operators will remit payment to the Company for its share in the value of the oil and natural gas sold.

The Company’s disaggregated revenue has two primary revenue sources which are oil sales and natural gas sales. Oil sales for the years ended December 31, 2018 and 2017 were $5,109,773 and $3,572,443, respectively. Natural gas sales for the years ended December 31, 2018 and 2017 were $2,387,612 and $2,346,273, respectively. Miscellaneous oil and gas product sales for the year ended December 31, 2018 and 2017 were $267,929 and $206,592, respectively.

The Company recognizes revenue from lease bonuses when it has received an executed lease agreement with a third party transferring the rights to explore for and produce any oil or gas they may find within the term of the lease, the payment has been collected, and the Company has no obligation to refund the payment. The Company recognizes the lease bonus as a cost recovery with any excess above its cost basis in the mineral properties being treated as income.

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 property and equipment:

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.

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.

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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, 2018 and 2017. The federal income tax returns for 2015, 2016 and 2017 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 2018 and 2017, 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 2018 and 2017 whose purchases were 31% and 35%, respectively, 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 method 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 2018 and 2017:

	2018			2017
Beginning balance at January 1	$	1,774,634		$	1,710,677
Liabilities incurred		11,386			31,627
Liabilities settled (wells sold or plugged)		(64,129	)		(22,573	)
Accretion expense		47,139			46,574
Revision to estimate		5,084			8,329
Ending balance at December 31	$	1,774,114		$	1,774,634

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New Accounting Pronouncements

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, nor is it applicable for oil and gas leases. 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 significant capital or operating leases. The Company adopted this standard on January 1, 2019. The new guidance will not have any impact on the Company’s financial position, results of operations or cash flows.

Pronouncements Adopted in 2018

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 adopted this standard on January 1, 2018 with no material effect on the Company’s financial position, results of operation or 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.

The FASB has issued Accounting Standards Update (ASU) No. 2018-03, Technical Corrections and Improvements to Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, which clarifies certain aspects of the guidance in ASU No. 2016-01, Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, that were brought to the FASB’s attention by stakeholders. Areas for correction or improvement include (1) equity securities without a readily determinable fair value—discontinuation, (2) equity securities without a readily determinable fair value—adjustments, (3) forward contracts and purchased options, (4) presentation requirements for certain fair value option liabilities, (5) fair value option liabilities denominated in a foreign currency, and (6) transition guidance for equity securities without a readily determinable fair value. The amendments are effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years beginning after June 15, 2018. The Company adopted this standard on July 1, 2018 with no material effect on the Company’s financial position, results of operation or cash flows.

There were no other accounting pronouncements issued or that have become effective since December 31, 2017, other than ASU 2016-01 and Topic 606 discussed in Note 2, which were directly applicable to the Company or will have any material impact on the Company’s financial position, results of operations or cash flows.

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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.

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, 2017, $.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, 200,000 shares authorized		184,735		27,070		157,665
Purchase of stock		---		432		(432	)
December 31, 2018, $.50 par value stock, 200,000 shares authorized		184,735		27,502		157,233

Note 5 – MARKETABLE SECURITIES

At December 31, 2018, available-for-sale debt securities, consisting entirely of U.S. government securities, are due within one year or less by contractual maturity.

For equity securities, in 2018 the Company recorded realized gains of $72,950 and unrealized losses of $(181,818). In 2017 the Company recorded realized gains of $34,884 and unrealized gains of $48,738.

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. 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 completed the analysis of the Act and did not experience 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,
	2018			2017
Assets:
Net Leasehold Impairment Reserves	$	127,906		$	189,867
Gas Balance Receivable		32,352			32,352
Long-Lived Asset Impairment		936,272			945,399
Deferred Geological and Geophysical Expense		38,367			47,539
Other		224,670			266,141
Total Assets		1,359,567			1,481,298
Liabilities:
Receivables		72,807			59,561
Intangible Drilling Costs		1,741,413			1,614,470
Depletion, Depreciation and Other		755,618			725,317
Total Liabilities		2,569,838			2,399,348
Net Deferred Tax Liability	$	(1,210,271	)	$	(918,050	)

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The increase in the deferred tax liability for 2018 reflected in the above table is primarily the result of the increase in intangible drilling costs.

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

	Year Ended December 31,
	2018			2017
Current Tax Provision/(Benefit):
Federal	$	96,443		$	10,362
State		(784	)		167
Total Current Provision		95,659			10,529
Deferred Tax Provision/(Benefit)		292,221			(593,111	)
Total Provision/(Benefit)	$	387,880		$	(582,582	)

The total income tax provision/(benefit) expressed as a percentage of income before income tax, excluding effect of change in federal income tax rate discussed below, was 14% for 2018 and 5% for 2017. These amounts differ from the amounts computed by applying the statutory U.S. federal enacted income tax rate of 21% for 2018 and 2017 as summarized in the following reconciliation:

	Year Ended December 31,
	2018			2017
Computed Federal Tax Provision	$	567,330		$	35,035
Increase (Decrease) in Tax From:
Allowable Depletion in Excess of Basis		(192,979	)		(51,533	)
Dividend Received Deduction		(305	)		(618	)
State Income Tax Provision/(Benefit)		784			(167	)
Federal Income Tax Rate Change		---			(577,797	)
Other		13,050			12,498
Income Tax Provision/(Benefit)	$	387,880		$	(582,582	)
Effective Tax Rate		14	%		5	%

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.

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

The Company’s Equity Method 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 on a month-to-month basis under the terms of the modified lease agreement. Rent expense for lease of the corporate office from the Partnership was approximately $30,000 for 2018 and 2017. The Company’s investment in the Partnership totaled $172,722 and $171,243 at December 31, 2018 and 2017, respectively.

Grand Woods Development, LLC (the “LLC”), an Oklahoma limited liability company, with a 47% ownership, was acquired in 2015. The LLC owns approximately 26.56 acres of undeveloped real estate in northeast Oklahoma City. The Company has guaranteed $1,000,000 of a $1,595,750 loan for which the proceeds were used to purchase a portion of the undeveloped real estate acreage. The loan matures October 31, 2020. The Company’s investment in the LLC totaled $438,303 and $544,603 at December 31, 2018 and 2017, respectively. The Company also holds a note receivable of $43,158 from the LLC.

QSN Office Park (“QSN”), an Oklahoma limited liability company, with a 20% ownership, was acquired in 2016. QSN is constructing and selling office buildings in a new office park. The Company has guaranteed a $521,602 loan for which the proceeds were used to build a speculative office building. The loan matures November 19, 2019. The Company’s investment in QSN totaled $270,835 and $275,248 at December 31, 2018 and 2017, respectively.

The Company’s Other 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, 2018 and 2017.

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, 2018 and 2017.

Cloudburst Solutions (“Solutions”), with a 10.625% ownership, was acquired with an initial investment of $500,000 in 2014, and additional investments of $750,000 and $44,375 in 2016 and 2018, respectively. Solutions owns exclusive rights to a water purification process technology that is being developed and currently tested. The Company’s investment in Solutions totaled $1,294,375 and $1,250,000 at December 31, 2018 and 2017, respectively. 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 $218,018 and $206,444 at December 31, 2018 and 2017, respectively.

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,
	2018		2017
Acquisition of Properties:
Unproved	$	485,348	$	568,893
Proved		---		---
Exploration Costs		1,770,215		1,274,931
Development Costs		622,024		976,731
Asset Retirement Obligation		16,470		39,956

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 2018 and 2017 there were no transfers into or out of Level 2 or Level 3.

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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 debt securities using quoted market prices for securities with similar maturity dates and interest rates. At December 31, 2018 and 2017, the Company’s assets reported at fair value on a recurring basis are summarized as follows:

	2018
	Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
Financial Assets:
Available-for-Sale Debt Securities –
U.S. Treasury Bills Maturing in 2019	$	---	$	16,249,414	$	---
Equity Securities –
Domestic Equities		259,843		---		---
International Equities		179,083		---		---
Others		15,132		---		---

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

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 $11,386 in 2018 and $31,627 in 2017 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 $832,651 for 2018 and $426,822 for 2017 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 and notes receivables, marketable securities, trade payables, and dividends payable. As of December 31, 2018 and 2017, the historical cost of cash and cash equivalents, trade and notes 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.

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 $832,651 for 2018 and $426,822 for 2017 are included in the statements of income in the line item Depreciation, Depletion, Amortization and Valuation Provisions. The impairments for 2018 and 2017 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.

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Note 11 – OTHER INCOME, NET

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

	2018			2017
Net Realized and Unrealized Gain (Loss) on Equity Securities	$	(108,868	)	$	83,622
Gains on Asset Sales		611,281			59,683
Interest Income		348,615			130,498
Settlements of Class Action Lawsuits		408			3,540
Agricultural Rental Income		5,600			5,600
Dividend Income		2,902			2,597
Income from Other Investments		16,500			445,000
Interest and Other Expenses		(47,724	)		(47,143	)
Other Income, Net	$	828,714		$	683,397

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 2018 in the amount of $192,629 each by Mesquite, Mid-American and LLTD. Reimbursements in 2017 were $190,665 each by Mesquite, Mid-American and LLTD. Included in the 2018 amounts, Mesquite, Mid-American and LLTD each paid $135,693 for their share of salaries. In 2017, the share of salaries paid by Mesquite, Mid-American and LLTD was $137,113 each.

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UNAUDITED SUPPLEMENTAL FINANCIAL INFORMATION

32

SUPPLEMENTAL SCHEDULE 1

THE RESERVE PETROLEUM COMPANY

WORKING INTEREST RESERVE QUANTITY INFORMATION

(Unaudited)

	Year Ended December 31,
	2018			2017
Oil and Condensate (Bbls)
Proved Developed and Undeveloped Reserves:
Beginning of Year		376,396			401,584
Revisions of Previous Estimates		26,063			18,951
Extensions and Discoveries		13,699			16,405
Purchase of Reserves		------			---
Production		(52,960	)		(60,544	)
End of Year		363,198			376,396
Proved Developed Reserves:
Beginning of Year		341,152			358,822
End of Year		326,752			341,152
Gas (MCF)
Proved Developed and Undeveloped Reserves:
Beginning of Year		3,191,511			3,023,754
Revisions of Previous Estimates		75,610			494,665
Extensions and Discoveries		8,094			190,923
Purchase of Reserves		---			---
Production		(443,354	)		(517,831	)
End of Year		2,831,861			3,191,511
Proved Developed Reserves:
Beginning of Year		2,944,804			2,809,944
End of Year		2,576,738			2,944,804

See notes on next page.

33

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 30,191 Bbls of oil and 393,584 MCF of gas for 2018 and 16,421 Bbls of oil and 288,743 MCF of gas for 2017.

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 2018 and 2017. 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 2018 summary reserve report was tested by comparison to 2018 average sales price information from the accounting records.

34

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,
	2018			2017
Future Cash Inflows	$	28,398,588		$	25,418,030
Future Production and Development Costs		(14,212,906	)		(12,989,835	)
Future Asset Retirement Obligation		(1,873,939	)		(1,881,972	)
Future Income Tax Expense		(701,106	)		(362,534	)
Future Net Cash Flows		11,610,637			10,183,689
10% Annual Discount for Estimated Timing of Cash Flows		(3,749,911	)		(3,121,751	)
Standardized Measure of Discounted Future Net Cash Flows	$	7,860,726		$	7,061,938

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 2017 and 2018, 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.

35

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,
	2018			2017
Standardized Measure, Beginning of Year	$	7,061,938		$	5,254,075
Sales and Transfers, Net of Production Costs		(2,430,324	)		(2,343,561	)
Net Change in Sales and Transfer Prices, Net of Production Costs		2,156,124			2,394,155
Extensions, Discoveries and Improved Recoveries, Net of Future Production and Development Costs		332,441			710,294
Revisions of Quantity Estimates		442,030			929,958
Accretion of Discount		923,952			689,080
Purchases of Reserves in Place		---			---
Net Change in Income Taxes		(225,892	)		(517,818	)
Net Change in Asset Retirement Obligation		(47,659	)		17,383
Changes in Production Rates (Timing) and Other		(351,884	)		(71,628	)
Standardized Measure, End of Year	$	7,860,726		$	7,061,938

36

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, 2018.

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, 2018.

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 27, 2019	March 27, 2019

37

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, 2018 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.

38

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 31, 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 31, 2006, amended January 1, 2018.
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.

39

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, 1^st Vice President

(Principal Financial Officer)

Date: March 27, 2019

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 27, 2019	March 27, 2019
/s/ Robert L. Savage	/s/ William M. Smith
Robert L. Savage (Director)	William M. Smith (Director)
March 27, 2019	March 27, 2019

40