UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the Fiscal Year Ended December 31, 2014

¨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)

6801 Broadway ext., Suite 300

Oklahoma City, Oklahoma73116-9037

 (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☐o No☒þ

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☐o No☒þ

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☒  þNo ☐o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes☒þ No☐o

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.☒þ

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐  oNo ☒þ

As of June 28, 2013,30, 2014 (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 $34,568,417,$50,906,138, as computed by reference to the last reported sale which was on June 27, 2013.2014.

As of March 21, 2014,20, 2015, there were 159,045158,650 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 20, 2014,19, 2015, which will be filed within 120 days of the end of the registrant’s year ended December 31, 2013,2014, are incorporated by reference into Part III of this Form 10-K to the extent described therein.

TABLE OF CONTENTS

Page

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’sCompany'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 the Company’sour 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 256,364255,662 gross acres equivalent to 88,44588,259 net acres. These mineral interests are located in nine different states in the north and south central United States. A total of 81,31181,126 (92%) net acres are located in the States of Arkansas, Kansas, Oklahoma, South Dakota and Texas, the areas of concentration for the Company in itsour recent exploration and development programs.

The Company has several options relating to the exploration and/or development of theseour 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 itsour 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 itwe may choose to participate as a working interest owner and pay itsour proportionate share of any exploration or development drilling costs.

A substantial amount of the Company’s oil and gas revenue has resulted from itsour owned mineral property management. In 2013, $5,108,703 (28%2014, $4,715,113 (25%) of oil and gas sales was from royalty interests versus $3,517,635 (27%$5,108,703 (28%) in 2012.2013. As a result of itsour mineral ownership, the Company had royalty interests in 3416 gross (0.69(0.31 net) wells, which were drilled and completed as producing wells in 2013.2014. This resulted in an average royalty interest of about 2.0%1.9% for these 3416 new wells. The Company has very little control over the timing or extent of the operations conducted on itsour 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, itwe may participate in drilling additional wells on itsour producing leaseholds; or if itsour exploration program, discussed below, results in a successful exploratory well, itwe may participate in the drilling of additional wells on the exploratory prospect. In 2013,2014, the Company participated in the drilling of 3427 development wells with 3222 wells (4.24(2.8 net), including the 85 wells in progress at the end of 2012,2013, completed as producers, and 25 wells (0.34(0.57 net) in progress at the time of this Form 10-K.

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 itsour 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 by Company personnel. If evaluation indicates the prospect is within the Company’sour risk limits, the Companywe 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 2013, the Company2014, we participated in the drilling of 17 exploration14 exploratory wells with 106 wells (1.21(.73 net), including 43 wells in progress at the end of 2012,2013, completed as producers; 54 wells (0.75(0.41 net), including 1 well in progress at the end of 2012, completed as dry holes; and 24 wells (0.29(0.41 net) in progress at the time of this Form 10-K.

For a summation of exploratory and development wells drilled in 20132014 or planned for in 2014,2015, 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, 2012.2013.”

Customers

In 2013,2014, the Company had two customers whose total purchases were greater than 10% of revenues from oil and gas sales. Redland Resources, Inc. purchases were $4,513,392$4,717,131 or 25% of total oil and gas sales. Luff Exploration Company purchases were $2,353,871$1,976,927 or 13%10% 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. A minor amount of oil and gas sales are made under fixed price contracts having terms of more than one year.

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 it haswe have an interest; rather, it partnerswe 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 the Companyus to participate in exploration and development activities itwe could not undertake on itsour own due to financial and personnel limits and allows itus to maintain low overhead costs.

Regulation

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

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

Environmental Protection and Climate Change

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

In 2009, the EPA officially published its findings that greenhousethatgreenhouse 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. The CompanyWe 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 itsour 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 the Company’sour 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 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, 2013,2014, the Company had eightnine employees, including officers. See the Proxy Statement for additional information. During 2013,2014, all the Company’sof our employees devoted a portion of their time to duties with affiliated companies, and the Company waswe 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. The Company hasWe have interests in approximately 830900 producing properties with 36%40% of them being working interest properties and the remaining 64%60% being royalty interest properties. About 81%80% of all properties are located in Oklahoma and Texas and account for approximately 66%74% of the Company’sour annual oil and gas sales. About 15%16% of the properties are located in Arkansas, Kansas, and South Dakota and account for approximately 34%26% of the Company’s annual oil and gas sales. The remaining 4% of these properties are located in Colorado and Montana and account for less than 1% of the Company’sour annual oil and gas sales. No individual property provides more than 10%9% of the Company’s 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 31 for working interest reserve quantity information.

Since January 1, 2013,2014, 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 20122013 Annual Report on Form 10-K and federal income tax return for the year ended December 31, 2012.2013. Those reserve estimates were identical.

Production

The average sales price of oil and gas produced and for the Company’s working interests, the average production cost (lifting cost) per equivalent thousand cubic feet (MCF) of gas production is presented in the table below for the years ended December 31, 2014, 2013 2012 and 2011.2012. Equivalent MCF was calculated using approximate relative energy content.

At December 31, 2013,2014, the Company had working interests in 218227 gross (26.38(27.76 net) wells producing primarily gas and 219234 gross (22.86(24.7 net) wells producing primarily oil. These interests were in 95,48095,120 gross (11,431(11,542 net) producing acres. These wells include 5250 gross (1.30(1.29 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, 2013.2014.

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, 20112012 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 20132014 include the 138 wells still drilling at the end of 2012.2013. As indicated in the “Development Program” on Page 3 and “Exploration Program” on Page 4, 25 development wells and 24 exploratory wells were still in process at the time of this Form 10-K.

Recent Activities

See Item 7, under the subheading “Update of Oil and Gas Exploration and Development Activity from December 31, 2012”2013” for a summary of recent activities related to oil and natural gas operations.

Item 3.

Legal Proceedings

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

Item 4.

MINE SAFETY DISCLOSURES

Not applicable.

PART II

Item 5.

Market for REGISTRANT’S Common Equity, Related Stock-holderMatters 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.

There was limited public trading in the Company’s common stock in 20132014 and 2012.2013. There were 6744 brokered trades appearing in the Company’s transfer ledger for 20132014 and 1167 in 2012.2013.

At March 21, 2014,20, 2015, the Company had approximately 1620 record holders of its common stock. The Company paid dividends on its common stock in the amount of $20.00 per share in the second quarter of 2014 and $10.00 per share in 2013 (in the second quarter of 2013) and $20.00 per share in 2012 ($10.00 per share in both the second and fourth quarters of 2012).2013. 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 20142015 with the Board of Directors for its approval.

ISSUER PURCHASES OF EQUITY SECURITIES

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

ITEM 6.

SELECTED FINANCIAL DATA

Not applicable.

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Forward-Looking Statements

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

Although management believes that the expectations reflected in such 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 the Company’sour business include, but are not limited to, the following:

The Company does not undertake any obligation to publicly revise forward-looking statements to reflect events or circumstances that arise after the date hereof. 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 20142015 and any Current Reports on Form 8-K filed by the Company.

Critical Accounting Estimates

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 PartnershipLiability Company (LLTD) and Lochbuie Holding Company (LHC). 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.

Mason McLain, a director of the Company, is a director of Mesquite and Mid-American. Robert T. McLain and Jerry Crow, directors of the Company, are directors of Mesquite and Mid-American. Kyle McLain, and Cameron R. McLain and John McLain are sonsbrothers and directors of Masonthe Company. Kyle McLain who ownsand Cameron McLain, each own more than 5% of the Company and are officers and directors of the Company.officers. Kyle McLain and Cameron McLain are officers and directors of Mesquite and Mid-American. Mason McLain and Robert T. McLain who are brothers, each ownowns an approximate 32% limited partner33% interest in LLTD, and Mason McLain is president of LHC, the general partner of LLTD. Robert T. McLain isand John McLain are not an employeeemployees of any of the above entities and devotesdevote only a small amount of time conducting their business.

The above named officers, directors, and employees as a group, beneficially own approximately 28%27% of the common stock of the Company, approximately 33%15% of the common stock of Mesquite, and approximately 19%5% of the common stock of Mid-American. These three corporations, each, have only one class of stock outstanding. See Item 8, Note 12 to the accompanying financial statements for additional disclosures regarding these relationships.

EQUITY INVESTMENT

The Company had a 33% partnership interest in Broadway Sixty-Eight, Ltd. (the “Partnership”) in 20122013 and 2013,2014, which it accounted for on the equity method. In using the equity method, the Company records the original investment in an entity as an asset and adjusts the asset balance for the Company’s share of any income or loss, as well as any additional contributions to or distributions from the entity. The Company does not have actual or effective control of the Partnership. The management of the Partnership could, at any time, make decisions in their own best interests that could affect the Company’s net income or the value of the Company’s investment.

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

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 2013,2014, as in prior years, the Company funded its business activity through the use of internal sources of capital. For the most part, these internal sources are cash flows from operations, cash, cash equivalents and available-for-sale securities. When cash flows from operating activities are in excess of those needed for other business activities, the remaining balance is used to increase cash, cash equivalents and/or available-for-sale securities. When cash flows from operating activities are not adequate to fund other business activities, withdrawals are made from cash, cash equivalents and/or available-for-sale securities. Cash equivalents are highly liquid debt instruments purchased with a maturity of three months or less. All of the available-for-sale securities are U.S. Treasury Bills.

In 2013,2014, net cash provided by operating activities was $12,258,084.$14,591,253. Sales (including lease bonuses), net of production costs, general and administrative costs and income taxes paid were $12,218,843,$14,096,337, which accounted for 99.7%96.6% of net cash provided by operations. The remaining components provided less than 1%4% of cash flow. In 2013,2014, net cash applied to investing activities was $10,246,949.$6,887,431. In 2013,2014, dividend payments and treasury stock purchases totaled $2,088,940$3,264,770 and accounted for all of the cash applied to financing activities.

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

Trading securities increased $197,373 (51%decreased $141,232 (24%) to $445,476 in 2014 from $586,708 in 2013 from $389,335 in 2012. Most of the increase2013. The net decrease is due to a $166,804 increase$200,714 in unrealized gains,losses, which represent the change in the fair value of the securities from their original cost. The remaining increasecost, offset by $59,482 of $30,569 represents the 20132014 income.

Refundable income taxes decreased $181,457 (35%$182,227 (54%) to $154,393 in 2014 from $336,620 in 2013 from $518,077 in 2012.2013. This decrease was due to excess 20132014 estimated tax payments being less than in 2012.2013.

Receivables increased $712,879 (41%decreased $306,692 (13%) to $2,142,356 in 2014 from $2,449,048 in 2013 from $1,736,169 in 2012.2013. The increasedecrease was due primarily to the use of increasedlower product prices and volumes for both oil and natural gas sales accrual estimates for year-end 20132014 compared to 2012.2013. Additional information about oil and natural gas sales for 20132014 is included in the “Results of Operations” section that follows.

Accounts payable decreased $152,032 (29%increased $451,388 (123%) to $819,010 in 2014 from $367,622 in 2013 from $519,654 in 2012.2013. This decreaseincrease was primarily due to decreasedparticipation in the drilling activity at the end of 2013 compared to 2012.two wells with an operator who did not require an advance payment.

Deferred income taxes and other accrued liabilities increased $130,194 (63%decreased $74,390 (22%) to $263,234 in 2014 from $337,624 in 2013 from $207,430 in 2012.2013. This increasedecrease was primarily due to the increasedecrease in the current deferred tax accrual duerelating to the increase$200,714 of trading securities unrealized losses in the oil and gas sales accrual in 2013.2014 discussed above.

The following is a discussion of material changes in cash flow by activity between the years ended December 31, 20132014 and 2012.2013. 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 20132014 were $12,258,084,$14,591,253, which, when compared to the $10,454,012$12,258,084 provided in 2012,2013, represents a net increase of $1,804,072$2,333,169 or 17%19%. The increase was mostly due to an increase in oil and gas sales cash flows of $4,723,598,$1,647,084; increased lease bonus cash flows of $1,720,663; and a cash distribution of $337,095 from our equity investment, offset by lower lease bonuses and coal royalties of $1,922,985 and an increase in production costs of $562,326$441,125 and taxes of $421,900.$995,665. Additional discussion of the more significant items follows.

Discussion of Selected Material Line Items Resulting in an Increase in Cash Flows. The $4,723,598 (36%$1,647,084 (9%) increase in cash received from oil and gas sales to $19,375,879 in 2014 from $17,728,795 in 2013 from $13,005,197 in 2012 was the result of an increase in both thegas sales volumes and prices, partially offset by lower oil and gas sales volumes and prices. 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 $1,720,663 (461%) to $2,093,558 in 2014 from $372,895 in 2013.

The cash distribution from our equity investment, Broadway Sixty-Eight, Ltd. of $337,095 represented our share of the profits from the construction and sale of several small office buildings on some land adjacent to our current office building. See Item 8, Note 7 to the accompanying financial statements for additional information regarding Broadway Sixty-Eight, Ltd.

Discussion of Selected Material Line Items Resulting in a Decrease in Cash Flows. Cash received for lease bonuses and coal royalties decreased $1,922,985 (84%) to $372,895 in 2013 from $2,295,880 in 2012. The decrease is due to a decrease in cash received for lease bonuses of $1,593,692 and coal royalties of $329,293 in 2013 versus 2012. No coal was produced from the Company’s leases in 2013.

Cash paid for production costs increased $562,326 (24%$441,125 (15%) to $3,393,795 in 2014 from $2,952,670 in 2013 from $2,390,344 in 2012.2013. This increase was mostly due to lease operating expense and handling expenseproduction taxes on new and acquired wells of about $379,000. The remaining increase was due to increased operating expense on previous wells and production taxes.$376,000. The increase in production taxes was also due to the increase in gas sales in 20132014 versus 2012.2013.

Cash flow decreased due to an increase inpaid for estimated income tax payments of $421,900 (47%taxes increased $995,665 (76%) to $2,306,915 in 2014 from $1,311,250 in 2013 from $889,350 in 2012.2013. The higher payments were mostly due to higher net income and current taxable income in 2013.2014.

Investing Activities

Net cash applied to investing activities increased $3,625,281decreased $3,359,518 (33%) to $10,246,949$6,887,431 in 20132014 from $6,621,668$10,246,949 of cash applied in 2012.2013. This $3,625,280 increase$3,359,518 decrease was due primarily to a $3,258,946 increase$3,918,378 decrease in cash applied to exploration and development expenditures, including $1,917,376 in December 2013 for some producing properties and leasehold.expenditures. See the “Exploration and Development Costs” section in the “Results of Operations” section below for more information about this acquisition. The remaining significant increaseinformation. This decline in cash applied to investing activities pertains towas partially offset by the decrease$530,625 purchase of other investments, which includes a $500,000 investment in proceeds from property disposals. This line item decreased $368,153 (74%) to $131,400 in 2013 from $499,553 in 2012. This decrease was the result of fewer sales of Kansas and Oklahoma non-producing leaseholds in 2013 compared to 2012.Cloudburst Solutions LLC, a wastewater purification technology company.

Financing Activities

Cash applied to financing activities decreased $1,051,835 (33%increased $1,175,830 (56%) to $3,264,770 in 2014 from $2,088,940 in 2013 from $3,140,775 in 2012.2013. Cash applied to financing activities consist of cash dividends on common stock and cash used for the purchase of treasury stock. In 2013,2014, cash dividends paid on common stock amounted to $1,767,613$3,097,246 as compared to $3,100,835$1,767,613 in 2012.2013. Dividends of $10.00$20.00 per share were paid for 2013in 2014 and $20.00$10.00 per share for 2012.in 2013. This $1,333,222 decline$1,329,633 increase in dividends paid was partially offset by a $281,387 increase$153,803 decrease in cash applied to purchase treasury stock.

Forward-Looking Summary

The Company’s latest estimate of business to be done in 20142015 and beyond indicates the projected activity can be funded from cash flow from operations and other internal sources, including net working capital. The Company is engaged in exploratory drilling. If this drilling is successful, substantial development drilling may result. Also, should other exploration projects which fit the Company’sCompany���s risk parameters become available or other investment opportunities become known, capital requirements may be more than the Company has available. If so, external sources of financing could be required.

RESULTS OF OPERATIONS

As disclosed in the Statements of Income in Item 8 of this Form 10-K, in 20132014 the Company had net income of $6,068,042$6,762,875 as compared to a net income of $4,553,845$6,068,042 in 2012.2013. Net income per share, basic and diluted, was $37.90$42.55 in 2013,2014, an increase of $9.60$4.65 per share from $28.30$37.90 in 2012.2013. Material line item changes in the Statements of Income will be discussed in the following paragraphs.

Operating Revenues

Operating revenues increased $3,678,292 (24%$2,355,139 (13%) to $21,167,812 in 2014 from $18,812,673 in 2013 from $15,134,381 in 2012.2013. Oil and gas sales increased $5,494,876 (42%$630,270 (3%) to $19,074,254 in 2014 from $18,443,984 in 2013 from $12,949,108 in 2012.2013. Lease bonuses and other revenues decreased $1,816,584increased $1,724,869 (468%) to $2,093,558 in 2014 from $368,689 in 2013 from $2,185,273 in 2012.2013. This decreaseincrease was thea result of a decrease in lease bonuses of $1,593,692 primarily from leases in Texas. In addition, coalTexas and Oklahoma. Coal royalties from North Dakota leases declined $222,893 (99%) towere $1,443 in 2013 from $224,336 in 2012.both 2014 and 2013. The increase in oil and gas sales is discussed in the following paragraphs.

The $5,494,876$630,270 increase in oil and gas sales was the net result of a $1,889,973$1,324,569 increase in gas sales, a $3,597,493 increase$953,789 decrease in oil sales and a $7,410$259,490 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 20132014 to 2012.2013. Miscellaneous oil and gas product sales of $621,753 in 2014 and $362,263 in 2013 and $354,853 in 2012 are not included in the analysis.

The $1,889,973 (58%$1,324,569 (26%) increase in natural gas sales to $6,453,271 in 2014 from $5,128,702 in 2013 from $3,238,729 in 2012 was the result of an increase in both gas sales volumes and the average price received per thousand cubic feet (MCF). The average price per MCF of natural gas sales increased $0.64$0.88 per MCF to $3.51$4.39 in 20132014 from $2.87$3.51 per MCF in 2012,2013, resulting in a positive gas price variance of $939,323.$1,286,161. A positive volume variance of $950,650$38,408 was the result of an increase in natural gas volumes sold of 331,23710,942 MCF to 1,470,564 MCF in 2014 from 1,459,622 MCF in 2013 from 1,128,385 MCF in 2012.2013. The increase in the volume of gas production was the net result of new 20132014 production of about 367,000317,000 MCF, offset by a decline of about 36,000306,000 MCF in production from previous wells. About 184,000 MCF (60%) of this decline is from working interest wells in Van Buren County, Arkansas. 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 adequate to replace working interest reserves produced in 20122014 but not in 2013.

The gas production for 20122013 and 20132014 includes production from about 100 royalty interest properties drilled by various operators in Robertson County, Texas. These properties accounted for approximately 387,000 MCF and $965,000 of the 2012 gas sales and approximately 370,000 MCF and $1,257,000 of the 2013 gas sales and approximately 304,000 MCF and $1,258,000 of the 2014 gas sales. These properties accounted for about 30%25% of the Company’s 20122013 gas revenues compared to 25%20% of 20132014 gas revenues. The Company has no control over the timing of future drilling on the acreage in which we hold mineral interests. However, if natural gas prices continue to recover, the Company expects that drilling activity in Robertson County will increase also.

The $3,597,493 (38%$953,789 (7%) increasedecrease in crude oil sales to $11,999,230 in 2014 from $12,953,019 in 2013 from $9,355,526 in 2012 was the result of an increasea decrease in both the average price per barrel (Bbl) and an increase inthe oil sales volumes. The average price received per Bbl of oil increased $3.87decreased $3.76 to $87.21 in 2014 from $90.97 in 2013, from $87.10 in 2012, resulting in a positivenegative oil price variance of $550,969. An increase$517,189. A decline in oil sales volumes of 34,9774,799 Bbls to 137,585 Bbls in 2014 from 142,384 Bbls in 2013 from 107,407 Bbls in 2012 resulted in a positivenegative volume variance of $3,046,524.$436,600. The increasedecrease in the oil volume production was the net result of new 20132014 production of about 49,30038,550 Bbls, offset by a 14,30043,350 Bbl decline in production from previous wells. Of the new 20132014 production, approximately 12,20017,000 Bbls (25%) was from Woods County, Oklahoma; about 17,500 Bbls (35%(44%) was from new working interest wells in Woods County, Oklahoma; about 6,200 Bbls (16%) was from new working interest wells in Roger Mills County, Oklahoma (in counties other than Woods); 9,000and 7,800 Bbls (18%(20%) was from new royalty interest wells in Oklahoma; and about 10,600 Bbls (22%) was from new royalty interest and working interest wells in Arkansas, Kansas, South Dakota and Texas.Oklahoma. As disclosed in Supplemental Schedule 1 of the Unaudited Supplemental Financial Information included below in Item 8, working interests in oil extensions and discoveries were adequate to replace working interest reserves produced in 2012 and 2013.2013 but not in 2014.

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 increased $1,746,348 (18%$1,222,266 (11%) to $12,461,694 in 2014 from $11,239,428 in 2013, from $9,493,080 in 2012, primarily due to an increase in production and depreciation, depletion and amortizationexploration expense. The material components of operating costs and expenses are discussed below.

Production Costs. Production costs increased $595,192 (25%$367,859 (12%) to $3,377,812 in 2014 from $3,009,953 in 2013 from $2,414,761 in 2012.2013. The increase was primarily the result of a $127,357 (23%$101,545 (15%) increase in gross production tax (net of production tax refunds) to $779,560 in 2014 from $678,015 in 2013 from $550,658 in 2012;and an increase in lease operating expense of $265,036 (18%$274,134 (16%) to $2,004,107 in 2014 from $1,729,973 in 2013 from $1,464,937 in 2012; and an increase in handling expense of $202,799 (51%) to $601,965 in 2013 from $399,166 in 2012.2013. Of the increase in lease operating expense, $258,565$257,388 was the result of new wells with the remaining $6,471$16,746 due to an increase in expenses for existing wells. Of the increase in handling expense, $120,227 was the result of new wells with the remaining $82,572 due to an increase in expenses for existing wells. Handling expense is comprised of gas gathering, treating, transportation, and compression costs. Gross production taxes are state taxes, which are calculated as a percentage of gross proceeds from the sale of products from each producing oil and gas property; therefore, they fluctuate with the change in the dollar amount of revenues from oil and gas sales.

Exploration and Development Costs. Under the successful efforts method of accounting used by the Company, geological and geophysical costs are expensed as incurred as are the costs of unsuccessful exploratory drilling. The costs of successful exploratory drilling and all development costs are capitalized. Total costs of exploration and development, excluding asset retirement obligations but inclusive of geological and geophysical costs, were $6,350,095 in 2014 and $7,485,378 in 2013 and $7,197,753 in 2012.2013. See Item 8, Note 8 to the accompanying financial statements for a breakdown of these costs. Exploration costs charged to operations were $1,284,483 in 2014 and $663,627 in 2013, and $316,465 in 2012, inclusive of unsuccessful exploratory well costs of $598,900 in 2014 and $199,144 in 2013, and $316,465 in 2012 and geological and geophysical costs of $685,583 in 2014 and $464,483 in 2013, with no geological and geophysical costs in 2012.2013.

Update of Oil and Gas Exploration and Development Activity from December 31, 2012.2013. For the year ended December 31, 2013,2014, the Company participated in the drilling of 1714 gross exploratory and 3427 gross development working interest wells with working interests ranging from a high of 18% to a low of 0.2%3.6%. Of the 1714 exploratory wells, 106 were completed as producing wells, 54 as dry holes and 24 were in progress. Of the 3427 development wells, 3222 were completed as producing wells and 25 were in progress. In management’s opinion, the exploratory drilling summarized above has produced some possible development drilling opportunities.

The following is a summary as of February 28, 2014,March 6, 2015, updating both exploration and development activity from December 31, 2012,2013, for the period ended December 31, 2013.2014.

The Company participated with its 18% working interest in the drilling of seventhree development wells on a Barber County, Kansas prospect. FourTwo of thesethe wells were completed as commercial gas producers oneand the third as a commercial oil and gas producer, one as a commercial oil producer and one as a marginal oil producer. Three additional development wells will be drilled starting in March 2014. Capitalized costs for the period were $655,584, including $47,912 in prepaid drilling costs.$256,479.

The Company participated with 14%, 14%16%, 8%, 12% and 16% working interests in the drilling of four step-outdevelopment wells on a Woods County, Oklahoma prospect. The first three wells were completed as commercial oil and gas producers and a completionthe fourth is in progress on the fourth. The Company will participate with 16% and 8% working interests in the drilling of two additional step-out wells starting in March 2014.awaiting completion. Capitalized costs for the period were $363,120,$308,418, including $71,757 in prepaid drilling costs.

The Company participated with 13.7% working interests in the drilling of three development wells and with a 17.9% interest in the drilling of a fourth on a Woods County, Oklahoma prospect. All four of these wells were completed as commercial oil and gas producers. Capitalized costs for the period were $425,106, including $28,073 in prepaid drilling costs.

The Company participated with its 16% working interest in the drilling of a step-out well on a Woods County, Oklahoma prospect. The well was completed as a marginal oil and gas producer. Capitalized costs were $75,340 for the period.

The Company participated with its 16% working interest in the drilling of two step-out wells on a Hodgeman County, Kansas prospect. Both wells were completed as commercial oil producers. Capitalized costs for the period were $172,286.

The Company participated with its 8.3% interest in the drilling of two additional horizontal wells in a Harding County, South Dakota waterflood unit. Both wells were completed as commercial oil producers. Capitalized costs for the period were $430,705.

The Company participated with its 10.5% working interest in the drilling of a step-out horizontal well on a Garfield County, Oklahoma prospect. The well was completed as a commercial oil and gas producer. Capitalized costs for the period were $136,984.

The Company participated with its 7% working interest in the drilling of two exploratory wells on a Grayson County, Texas prospect. The first well was drilled and completed as a horizontal well and is a marginal oil producer. For geologic reasons, the planned horizontal section of the second well was not drilled and it was completed as a vertical well. The initial completion resulted in marginal oil production. Additional completion operations are in progress. Capitalized costs for the period were $969,939, including $201,901 in prepaid drilling costs, and a $510,000 impairment loss was recorded for the horizontal well.

The Company participated with fee mineral interests in completion operations on two exploratory horizontal wells in Beaver County, Oklahoma (the wells were drilled in 2012). The Company has interests of 12.6% and 10.2% in the wells, which were both completed as commercial oil producers. Capitalized costs for the period were $606,009.

The Company participated with a 5.7% working interest in the drilling of a horizontal development well on a Dewey County, Oklahoma prospect. The well was completed as a commercial oil and gas producer. Capitalized costs for the period were $269,889.

The Company participated with its 16% interest in a 3-D seismic survey on a Hodgeman County, Kansas prospect. An exploratory well was drilled and completed as a marginal oil producer. Capitalized costs for the period were $88,000, including $13,220 in prepaid drilling costs. Seismic costs of $15,533 were expensed.

The Company participated with its 10.5% interest in a 3-D seismic survey on a Cimarron County, Oklahoma prospect. An exploratory well was drilled and completed, testing oil and water. Temporary pumping equipment will be installed to further test the well. A second exploratory well was drilled and completed as a dry hole. The prospect is under evaluation for the possible drilling of an additional exploratory well. Seismic costs of $91,822 were expensed for the period. Capitalized costs were $131,953, including $28,784 in prepaid drilling costs. Dry hole costs for the period were $59,600.

Starting in January 2013, the Company purchased a 14% interest in 12,404 net acres of leasehold on a Ford and Gray Counties, Kansas prospect for $167,097. A 3-D seismic survey was conducted on the prospect. The Company participated in the drilling of two exploratory wells that were both completed as dry holes. Dry hole costs for the period were $81,447. Seismic costs of $185,187 were expensed.

The Company is participating in the development of a Grayson County, Texas prospect with an 8.75% interest. The first phase of acreage acquisition has been completed. The second phase will involve selling a portion of the acreage to an industry partner, additional acreage acquisition and the drilling of exploratory wells. Prospect costs for the period were $175,000.

In July 2013, the Company purchased an 18% interest in 1,440 net acres of leasehold on a Meade County, Kansas prospect for $24,624. The Company participated in the drilling of an exploratory well that was completed as a dry hole. The leasehold cost was written off to impairment expense. Dry hole costs for the period were $45,575.

The Company participated with a 7.5% working interest in the drilling of a step-out horizontal well on a Woods County, Oklahoma prospect. The well was completed as a commercial oil and gas producer. Capitalized costs for the period were $430,800.

The Company participated with a 9% working interest in the drilling of a step-out horizontal well on a Roger Mills County, Oklahoma prospect. The well was completed as a commercial gas and condensate producer. Capitalized costs for the period were $712,754.

In September 2013, the Company paid $4,320 to renew and extend its 18% interest in 320 net acres of leasehold on a Kiowa County, Kansas prospect. The Company participated in the drilling of two exploratory wells. The first well was completed as a commercial oil producer. The second has been completed, testing gas, and is awaiting pipeline connection. Capitalized costs for the period were $215,550, including $77,180$67,650 in prepaid drilling costs.

The Company participated with its 18% working interest in the drilling of a development well on a Woods County, Oklahoma prospect. A completion is in progress.The well was completed as a commercial gas producer. Capitalized costs for the period were $133,200,$131,400, including $82,780$35,334 in prepaid drilling costs.

The Company participated with 11.8% and 8% working interests in the drilling of two development wells on a Woods County, Oklahoma prospect. The first well was completed as a commercial oil and gas producer and the second is awaiting completion. Capitalized costs for the period were $147,087, including $46,244 in prepaid drilling costs.

The Company participated with a 13.7% working interest 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 $191,335, including $18,920 in prepaid drilling costs.

The Company participated with its 10.5% working interest in the drilling of two exploratory wells on a Cimarron County, Oklahoma prospect. Both wells were completed as dry holes. The Company also participated in a salt water disposal well that has allowed a commercial oil well drilled on the prospect in 2013 to be placed on production. Capitalized costs for the period were $29,569. Costs expensed to dry hole costs were $69,972.

The Company participated with a 7.5% working interest in the drilling of three horizontal development wells on a Woods County, Oklahoma prospect. All three wells were completed as commercial oil and gas producers. Capitalized costs for the period were $913,961.

The Company participated with a 9% working interest in the drilling of two horizontal development wells on a Roger Mills County, Oklahoma prospect. Both wells were completed as commercial gas and condensate producers. Capitalized costs for the period were $1,698,478.

The Company participated with its 10.5% working interest in the drilling of an exploratory well on a Logan County, Oklahoma prospect. Completion operations are in progress. Prepaid drilling costs were $77,213.

The Company participated with a 6.6% working interest in the drilling of an exploratory well on a Garvin County, Oklahoma prospect. The deep objectives were non-productive and the lower portion of the hole was plugged. The Company has participated with a 12.8% working interest in a completion attempt of a shallow zone that has so far been unsuccessful. The well is under evaluation. Capitalized costs for the period were $96,038. Costs of $482,882 were expensed to dry hole costs.

The Company participated with its 10.5% interest in the purchase of a producing oil well and two salt water disposal wells on a Seminole County, Oklahoma prospect. One of the disposal wells was recompleted as an oil producer and a pipeline was constructed from the producing wells to the remaining disposal well. The wells will be placed on production pending a workover of the first well and electrical hookup of the second. The Company is participating in a development well on the prospect that is currently drilling. Prepaid costs for the period were $307,964.

The Company participated with its 10.5% interest in the drilling and completion of an exploratory well and a salt water disposal well on a Seminole County, Oklahoma prospect. The exploratory well is being tested, but appears to be a commercial oil producer. Prepaid drilling costs for the period were $200,808.

The Company participated with 10.7%, 10.3%, 11.1% and 10.3% working interests in the drilling of four development wells and with a 10.3% working interest in an unsuccessful re-entry and washdown attempt on a Woods County, Oklahoma prospect. All four of the wells were completed as commercial oil and gas producers. Capitalized costs for the period were $311,096, including $90,219 in prepaid drilling costs. Costs expensed to dry hole costs for the re-entry were $13,682.

The Company participated with a fee mineral interest in the drilling of an exploratorya step-out horizontal well in KingfisherBeaver County, Oklahoma. The Company has a 3.5%5.1% interest in the well which was completed as a commercial oil and gas producer. Capitalized costs for the period were $460,541.$276,844.

In November 2013, the Company purchased a 10.5% interest in 718 net acres of leasehold and 8.5 square miles of 3-D seismic data on a Logan County, Oklahoma prospect for $120,549. An exploratory well will be drilled in the second quarter of 2014.

In December 2013, the Company purchased a 7% interest in 2,083 net acres of leasehold and 11 square miles of 3-D seismic data on a Garvin County, Oklahoma prospect for $155,285. The Company is participating in an exploratory well that is currently drilling. Prepaid drilling costs for the period were $322,371.

In December 2013, the Company purchased a 10.5%participated with its 14% working interest in a five prospect package in Seminole County, Oklahoma covering 1,240 acres, paying a $58,590 up-front fee (50% of its ultimate cost if all of the acreage is acquired). The Company will participate in the drilling of an exploratory well andon a salt water disposal well on one of the prospects starting in March 2014.

In December 2013, the Company purchased a 14% interest in 7,290 net acres of producing leasehold and interests ranging from 5.9% to 12.5% in 50 producing wells in Woods County, Oklahoma and BarberFord County, Kansas for $1,917,376.prospect. The Company will participate withwell was completed as a 5.9% working interest in the drilling of a development well in the second quarter of 2014.dry hole. Costs expensed to dry hole costs were $44,798.

In February 2014, the Company purchased a 10% interest in 250 net acres of leasehold on a McClain County, Oklahoma prospect for $11,875. AnThe Company participated in the drilling of an exploratory well will be drilled starting in March or April 2014.that was completed as a marginal oil producer. Capitalized costs for the period were $117,310.

In FebruaryMarch 2014, the Company agreed to purchasepurchased a 14% interest in 1,705 net acres of leasehold and 70 square miles of 3-D seismic data on a Creek County, Oklahoma prospect for $684,376. Seismic interpretationEight potential structures have been identified and additional leasehold acquisition arehas been acquired. The Company participated in progress,the drilling of an exploratory well that was completed as a dry hole and will participate in a second exploratory well starting in March 2015. Additional leasehold costs for the period were $36,805.

In September 2014, the Company purchased a 14% interest in 160 net acres of leasehold on a Creek County, Oklahoma prospect for $24,500. The Company participated in the drilling of an exploratory well that was completed as a marginal oil producer. Capitalized costs for the period were $106,573.

In September 2014, the Company purchased a 10.5% interest in 180 net acres of leasehold on a Seminole County, Oklahoma prospect for $9,734. The Company participated in the drilling of an exploratory well that was completed as a dry hole. Capitalized costs for the period were $62,299, including $25,363 in prepaid drilling costs

In October 2014, the Company purchased a 10.5% interest in a leasehold position on a Cowley County, Kansas prospect for $33,495. An exploratory well was drilled and completed, testing gas. An effort is currently underway to find a market for the gas. Capitalized costs for the period were $58,204, including $8,837 in prepaid drilling costs.

In December 2014, the Company purchased an 8.4% interest in 14,388 net acres of leasehold for $171,219 and paid $108,570 in prepaid seismic costs on a Thomas County, Kansas prospect. A 3-D seismic survey of the prospect has been completed, and once the data has been processed and analyzed, decisions about drilling exploratory wells will be drilled in the second half of 2014.made.

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 $310,413 in 2014 and $215,861 in 2013 and $136,456 in 2012.2013. Of the 20132014 provision, $174,048$190,407 was due to the annual amortization of undeveloped leaseholds and $41,813$120,006 was due to specific leasehold impairments. The 20122013 provision was due to the annual amortization of undeveloped leaseholds of $101,596$174,048 and specific leasehold impairments of $34,860.$41,813.

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 20132014 and 2012.2013. The 2014 impairment loss was $1,928,548 and the 2013 impairment loss was $1,644,142 and the 2012 impairment loss was $1,811,732.$1,644,142. The $167,590 decline$284,406 increase in impairments in 20132014 was mainly due to the improved natural gasdecline in oil prices.

The depletion and depreciation of oil and gas properties are computed by the units-of-production method. The amount expensed in any year will fluctuate with the change in estimated reserves of oil and gas, a change in the rate of production or a change in the basis of the assets. In 2012,2013, approximately 40%34% and in 2013,2014, approximately 34%17% of the working interest wells in which the Company participated were horizontal wells. A horizontal well may cost five to eight times as much as a vertically drilled well. In addition, horizontal wells’ initial production rates tend to be greater and their production decline rates are usually higher than in vertical wells. The larger investment in the costlier horizontal wells and the increased production rates result in an increase in depreciation expense. The provision for depletion and depreciation increased $901,893 (28%declined $214,504 (5%) to $3,857,215 in 2014 from $4,071,720 in 2013 from $3,169,827 in 2012.2013. This increasedecrease is due to the reasons discussed above. The provision also includes $90,151 for 2014 and $88,457 for 2013 and $116,048 for 2012 for the amortization of the Asset Retirement Costs. See Item 8, Note 2 to the accompanying financial statements for additional information regarding the Asset Retirement Obligation.

Other Income (Loss), Net. See Item 8, Note 11 to the accompanying financial statements for an analysis of the components of this line item for 20132014 and 2012.2013. Other income, net decreased $134,281 (27%$249,667 (70%) to $107,414 in 2014 from $357,081 in 2013 from $491,362 in 2012.2013. The line items responsible for this decrease are described below.

Net realized and unrealized gains (losses) on trading securities increased $207,017decreased $338,243 to a net loss of $(142,522) in 2014 from a net gain of $195,721 in 2013 from a net loss of $(11,296) in 2012.2013. Realized gains or losses result when a trading security is sold. Unrealized gains or losses result from adjusting the Company’s carrying amount in trading securities owned at the reporting date to estimated fair value. In 2014, the Company had realized gains of $58,192 and unrealized losses of $200,714. In 2013, the Company had realized gains of $28,917 and unrealized gains of $166,804. In 2012, the Company had realized gains of $6,359 and unrealized losses of $(17,655).

Gains on sales or disposals of assetsIncome from investments decreased $334,579 (74%)$13,000 to $118,011$20,000 in 20132014 from gains of $452,590$33,000 in 2012. This2013.

Interest and other expenses increased $10,231 to $45,048 in 2014 from $34,817 in 2013. The increase was due to lower sales ofa $10,218 increase in the Company’s interestsaccretion expense to $44,602 in certain non-producing leaseholds2014 from $34,384 in Oklahoma and Kansas.2013.

Interest income decreased $9,601 (30%)$5,656 to $17,177 in 2014 from $22,833 in 2013 from $32,434 in 2012.2013. This decrease was the net result of a decreasedecline in the average interest rate, partially offset by an increase in the average balance of cash equivalents and average balance of available-for-sale securities from which most of the interest income is derived. The average interest rate declined from .19% in 2013 to .14% in 2014. The average balance outstanding decreased $666,735increased $18,610 to $11,841,395 in 2014 from $11,822,785 in 20132013.

These declines were partially offset by an increase in class action settlements of $116,093 to $131,178 in 2014 from $12,489,520$15,085 in 2012.2013.

Provision for Income Taxes. See Item 8, Note 6 to the accompanying financial statements for an analysis of the various components of income taxes. In 2014, the Company had an estimated provision for income taxes of $2,117,241 as the result of a current tax provision of $2,489,141, partially offset by a deferred tax benefit of $371,900. In 2013, the Company had an estimated provision for income taxes of $1,897,487 as the result of a current tax provision of $1,492,708 and a deferred tax provision of $404,779. In 2012, the Company had an estimated provision for income taxes of $1,651,821 as the result of a current tax provision of $1,187,398 and a deferred tax provision of $464,423.

ITEM 7A.

QUANTITATIVEAND 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

To the Board of Directors and Stockholders

The Reserve Petroleum Company

We have audited the accompanying balance sheets of The Reserve Petroleum Company as of December 31, 20132014 and 2012,2013, and the related statements of income, stockholders’ equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’sCompany's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of The Reserve Petroleum Company as of December 31, 20132014 and 2012,2013, and the results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

/s/ HoganTaylor LLP

Oklahoma City, Oklahoma

March 28, 201430, 2015

See Accompanying Notes

See Accompanying Notes

See Accompanying Notes

See Accompanying Notes

See Accompanying Notes

See Accompanying Notes

THE RESERVE PETROLEUM COMPANY

NOTES TO FINANCIAL STATEMENTS

Note 1 –NATURE OF OPERATIONS

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

Note 2 –SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash and Cash Equivalents

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

Investments

Marketable Securities:

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

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

Unrealized gains and losses on available-for-sale securities, which consist entirely of U.S. Government securities, are reported as a component of other comprehensive income when significant to the financial statements. There are no significant cumulative unrealized gains or losses on available-for-sale securities as of December 31, 2014 or 2013.

Equity Investments:

The Company accounts for its non-marketable investment in a partnership on the equity basis. See Note 7 for additional information.

Receivables and Revenue Recognition

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

Property 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 periodically. Any impairment of value is charged to expense.

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

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

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

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 annually. 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.

The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense. The federal income tax returns for 2010, 2011, 2012 and 20122013 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 20132014 and 2012,2013, 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 20132014 and 20122013 whose combined purchases were 38%35% and 42%38%, 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 a guarantee associated with the Company’s equity investment in Broadway Sixty-Eight, Ltd.

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 and inflating it over the life of the property. 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 20132014 and 2012:2013:

New Accounting Pronouncements

No new accounting standards that were issued or became effective during 2013 have had or are expected to have a material impact on the Company’s financial statements.

In February 2013,May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers” (“ASU”ASU 2014-09”). ASU 2014-09 clarifies the principles for recognizing revenue and develops a common revenue standard under U.S. GAAP under which an entity should recognize revenue to depict the transfer of promised goods or “Update”) 2013-02,Comprehensive Income: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income,services to customers in an amount that reflects the consideration to which adds new disclosure requirementsthe entity expects to be entitled in exchange for items reclassified out of accumulated other comprehensive income (“AOCI”). The Update requires that the Company present either in a single notethose goods or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of AOCI based on its source and the income statement line items affected by the reclassification. The guidanceservices. ASU 2014-09 is effective for the Company for interim and annual reporting periods beginning on or after December 15, 2012. This guidance had no2016. The new standard allows application either retrospectively to each prior reporting period presented or retrospectively as a cumulative-effect adjustment as of the date of adoption. Management is currently assessing the adoption method and the impact ASU 2014-09 will have on the Company, but it is not expected to have a material effect on the Company’s financial statements.position, results of operations or cash flows.

Reclassifications

Certain amounts in the 20122013 financial statements have been reclassified to conform to the 20132014 presentation. The amounts were not material to the financial statements and had no effect on previously reported net income.

Note 3 –DIVIDENDS PAYABLE

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

Note 4 –COMMON STOCK

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