RSRV 10-K Annual Report Dec. 31, 2009

RESERVE PETROLEUM CO

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10-K 1 form10k.htm THE RESERVE PETROLEUM COMPANY 10-K 12-31-2009 form10k.htm

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, 2009

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 N. BROADWAY, SUITE 300 OKLAHOMA CITY, OKLAHOMA 73116-9092 (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 þ No 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 o 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):

Large accelerated filer o

Accelerated filer o

Non-accelerated filer o

Smaller reporting company þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

The aggregate market value of the voting and non-voting common stock of the registrant held by non-affiliates of the registrant was $32,633,776, as computed by reference to the last reported sale which was on March 25, 2010.

As of March 26, 2010, there were 161,665.64 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 18, 2010, which will be filed within 120 days of the end of the registrant’s fiscal year ended December 31, 2009, 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	6
Item 1B.	Unresolved Staff Comments	6
Item 2.	Properties	7
Item 3.	Legal Proceedings	8
Item 4.	(Removed and Reserved)	8

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	9
Item 6.	Selected Financial Data	10
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	10
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	24
Item 8.	Financial Statements and Supplementary Data	24
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	48
Item 9A.(T).	Controls and Procedures	48
Item 9B.	Other Information	49

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	49
Item 11.	Executive Compensation	49
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	49
Item 13.	Certain Relationships and Related Transactions and Director Independence	50
Item 14.	Principal Accountant Fees and Services	50

PART IV

Item 15.	Exhibits and Financial Statement Schedules	50

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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”) 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’s 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 259,314 gross acres equivalent to 89,440 net acres. These mineral interests are located in nine different states in the north and south central United States. A total of 63,974 net acres are located in the States of Oklahoma, South Dakota and Texas, the areas of concentration for the Company in its present exploration and development programs.

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

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A substantial amount of the Company’s oil and gas revenue has resulted from its owned mineral property management. In 2009, $3,890,699 (44%) of oil and gas sales was from royalty interests versus $10,406,544 (53%) in 2008. As a result of its mineral ownership, the Company had royalty interests in 28 gross (.71 net) wells, which were drilled and completed as producing wells in 2009. This resulted in an average royalty interest of about 2.5% for these 28 new wells. The Company has very little control over the timing or extent of the operations conducted on its 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; along with a joint interest operator, it may participate in drilling additional wells on its producing leaseholds; or if its exploration program discussed below results in a successful exploratory well, it may participate in the drilling of additional wells on the exploratory prospect. In 2009, the Company participated in the drilling of seventeen development wells with fourteen wells (1.71 net) completed as producers and three wells (.497 net) in progress. The seven wells (1.14 net) that were in progress at the end of 2008 were all completed as producing wells in 2009.

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 its 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’s risk limits, the Company 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 2009, the Company participated in the drilling of sixteen exploration wells with seven wells (1.13 net) completed as producers, six wells (.78 net) completed as dry holes and three wells (.28 net) in progress. Of the nine wells (.987 net) still drilling at the end of 2008, six wells (.75 net) were completed as producing wells in 2009 and three wells (.238 net) were dry holes.

For a summation of exploratory and development wells drilled in 2009 or planned for in 2010, 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, 2008.”

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Customers

In 2009, the Company had four customers whose total purchases were greater than 10% of revenues from oil and gas sales. Redland Resources, Inc. purchases were $1,929,743, or 22% of total oil and gas sales. ConocoPhillips Company purchases were $1,161,915, or 13% of total oil and gas sales. Luff Exploration Company purchases were $1,065,765, or 12% of total oil and gas sales. XTO Energy, Inc. purchases were $883,673, or 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 is a very minor factor in the industry and must compete with other persons and companies having far greater financial and other resources. The Company’s ability to participate in and/or develop viable prospects and secure the financial participation of other persons or companies in exploratory drilling on these prospects is limited.

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 the state and 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, a cost which cannot be estimated with any assurance of certainty.

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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 will allow the EPA to adopt and implement regulations to restrict these emissions under existing provisions of the Federal Clean Air Act. In addition, the United States Congress has been considering legislation that would establish an economy-wide cap-and-trade program to control or reduce U.S. emissions of greenhouse gases.

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 Company 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 its 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's business, we believe that climate change and government laws and regulations related to climate change 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, 2009, the Company had eight employees, including officers. See the Proxy Statement for additional information. During 2009, all the Company’s employees devoted a portion of their time to duties with affiliated companies, and the Company was 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

Smaller reporting companies are not required to provide the information required by this Item.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

Smaller reporting companies are not required to provide the information required by this Item.

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ITEM 2.

PROPERTIES

The Company’s principal properties are oil and natural gas properties. The Company has interests in approximately 610 producing properties with one-third of them being working interest properties, and the remaining two-thirds being royalty interest properties. About 87% of these properties are located in Oklahoma and Texas and account for approximately 78.8% of the Company’s annual oil and gas sales. About 7% of the properties are located in Kansas and South Dakota and account for approximately 20.6% of the Company’s annual oil and gas sales. The remaining 6% of these properties are located in Colorado, Arkansas and Montana and account for less than 1% of the Company’s annual oil and gas sales. No individual property provides more than 7% 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 43 for working interest reserve quantity information.

Since January 1, 2009, 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 2008 annual report on Form 10-K and Federal income tax return for the year ended December 31, 2008. 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, 2009, 2008 and 2007. Equivalent MCF was developed 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

2009	$	53.43	$	3.40	$	51.25	$	3.51	$	1.68
2008	$	96.80	$	8.41	$	91.10	$	7.95	$	2.10
2007	$	67.35	$	6.19	$	65.71	$	6.63	$	1.65

At December 31, 2009, the Company had working interests in 147 gross (17.88 net) wells producing primarily gas and had working interests in 125 gross (11.34 net) wells producing primarily oil. These interests were in 55,481 gross (6,933 net) producing acres. These wells include 51 gross (1.00 net) wells associated with secondary recovery projects.

Seven percent or 5,444 barrels of the Company’s oil production during 2009 was derived from royalty interests in mature West Texas water-floods.

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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, 2009.

	Acreage
	Gross		Net
Non-producing Mineral Interests		259,314		89,440
Undeveloped Leaseholds		83,282		12,232

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, 2007 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 2009 include the sixteen wells still drilling at the end of 2008. As indicated in the “Development Program” and “Exploration Program” on Page 4, three development wells and three exploratory wells were still in process at the time of this Form 10-K.

	Number of Net Working Interest Wells Drilled
	Exploratory				Development
	Productive		Dry		Productive		Dry

2009		1.88		1.02		2.85		---
2008		1.23		.11		2.69		---
2007		---		.20		1.95		---

Recent Activities

See Item 7, under the subheading “Update of Oil and Gas Exploration and Development Activity from December 31, 2008,” 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.

(REMOVED AND RESERVED)

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PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCK-HOLDER M ATTERS 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

03/31/08	$	325	$	260
06/30/08	$	440	$	315
09/30/08	$	412	$	330
12/31/08	$	360	$	225
03/31/09	$	231	$	202
06/30/09	$	250	$	205
09/30/09	$	237	$	205
12/31/09	$	241	$	210

There was limited public trading in the Company’s common stock in 2009 and 2008. In 2009, there were 15 brokered trades appearing in the Company’s transfer ledger versus 36 in 2008.

At March 26, 2010, the Company had approximately 1,500 record holders of its common stock. The Company paid dividends on its common stock in the amount of $10.00 per share in the second quarter of 2009, and $10.00 per share in the second quarter and $30.00 per share in the third quarter of 2008. 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 2010 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 Programs 1		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs 1
Oct 1, 2009 to Oct 31, 2009		5	$	184.00		-		-
Nov 1, 2009 to Nov 30, 2009		8	$	160.00		-		-
Dec 1, 2009 to Dec 31, 2009		159	$	198.00		-		-
Total		172	$	195.83		-		-

1 The 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.

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ITEM 6.

SELECTED FINANCIAL DATA

Smaller reporting companies are not required to provide the information required by this Item.

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’s 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 the Company’s 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 the Company receives for its product is based upon the spot market price, which in the past has experienced significant fluctuations. Management anticipates such 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, to a somewhat lesser degree, 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 the prospect is successful, or charged to operating costs and expenses, if unsuccessful. Estimating the amount of such future costs, which may relate to successful or unsuccessful prospects, is extremely imprecise at best.

	·	The Company has equity investments in organizations over which the Company has limited or no control. The management of these entities could at any time make decisions in their own best interests, which could affect the Company’s net income or the value of the Company’s investments. See “Equity Investments” below in this Item 7 for information regarding these equity investments.

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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 2010 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, the Company has 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 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 leasehold, using a straight line method; however, when leaseholds are impaired or condemned, an appropriate adjustment to the provision is made at that time.

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

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

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

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

	·	The estimation of the amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations as well as the completion of complex calculations, including the determination of the Company’s percentage depletion deduction, if any. To calculate the exact excess percentage depletion allowance, a well-by-well calculation is, and can only be, performed at the end of each fiscal year. During interim periods, a high-level estimate is made taking into account historical data and current pricing. Although the Company’s management believes its 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), Lochbuie Limited Partnership (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, an officer and director of the Company, is an officer and 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 are sons of Mason McLain, who owns more than 5% of the Company, and are officers and directors of the Company. Kyle McLain and Cameron McLain are officers and directors of Mesquite and Mid-American. Mason McLain and Robert T. McLain, who are brothers, each own an approximate 32% limited partner interest in LLTD, and Mason McLain is president of LHC, the general partner of LLTD. Robert T. McLain is not an employee of any of the above entities and devotes only a small amount of time conducting their business.

The above named officers, directors and employees, as a group, beneficially own approximately 29% of the common stock of the Company, approximately 32% of the common stock of Mesquite and approximately 17% 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.

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EQUITY INVESTMENTS

For most of 2008 and all of 2009, the Company had investments in four entities, 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. In June, 2008, the Company purchased a 10% ownership in Bailey Hilltop Pipeline, LLC. The remaining three entities include one Oklahoma limited partnership and two Oklahoma limited liability companies. The Company does not have actual or effective control of any of the entities. The management of these entities could, at any time, make decisions in their own best interests that could materially affect the Company’s net income or the value of the Company’s investments.

The remaining entities are Broadway Sixty-Eight, Ltd. (33% limited partnership interest), OKC Industrial Properties, LLC (10% ownership) and JAR Investments, LLC (25% ownership). These entities, collectively and/or individually, have had a significant effect, both positively and negatively, on the Company’s net income in the past and are expected to in the future. Two of these entities have guarantee arrangements under which the Company is contingently liable. Item 8, Note 7 to the accompanying financial statements includes related disclosures and additional information regarding these entities.

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 2009, 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. Most of the available-for-sale securities are U.S. Treasury Bills.

In 2009, net cash provided by operating activities was $5,304,623. Sales, net of production, exploration, general and administrative costs and income taxes paid were $4,884,441, which accounted for 92% of net cash provided by operations. The remaining components provided $420,182 or 8% of cash flow. In 2009, net cash applied to investing activities was $4,028,723. Net purchases of available-for-sale securities discussed below and capitalized property additions (net of disposals) accounted for $4,095,473 of the total net cash applied to investing activities. Maturing available-for-sale securities provided $32,944,856 of gross cash flow due to their six-month maturities. However, these funds, plus $949,902 of excess cash from operations, were re-invested in the same type of securities.

In 2009, cash utilized for capitalized property additions (net of disposals) was $3,145,571. Dividend payments and treasury stock purchases totaled $1,655,591 and accounted for all of the cash applied to financing activities.

Other than cash, cash equivalents and available-for-sale securities, other significant changes in working capital include the following:

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Trading securities increased $132,144 (61%) to $350,372 in 2009 from $218,228 in 2008. Most of the increase is due to a $90,557 increase in unrealized gains, which represent the change in the fair value of the securities from their original cost. The remaining increase of $41,587 represents the earnings from the securities plus the net realized gains for the year. Net realized gains were reinvested in additional securities.

Receivables decreased $294,099 (17%) to $1,444,757 in 2009 from $1,738,856 in 2008. The decrease was due primarily to declines in four components of the receivables balance as follows: (1) receivables for sales accruals have declined about $135,500 in 2009 from 2008; (2) a receivable of about $62,100 related to the sale of producing properties in June, 2008 was collected in June, 2009; (3) a note receivable declined $50,000 in 2009 from 2008 and (4) accrued interest receivable declined about $45,000 in 2009 from 2008. Additional information about the decline in sales for 2009, properties sold in 2008 and the interest rate decline in 2009 is included in the “Results of Operations” section that follows. Information about the note receivable is included in Item 8, Note 7 to the accompanying financial statements.

Refundable income taxes decreased $685,265 (69%) to $314,308 in 2009 from $999,573 in 2008. This decrease was due entirely to applying the 2009 current Federal tax provision of $695,135 to the refundable income taxes balance.

Prepaid expenses of $197,304 in 2009 were prepaid seismic expenses on the Hodgeman County, Kansas, prospect discussed in the “Update of Oil and Gas Exploration and Development Activity from December 31, 2008” in the “Results of Operations” section below. The seismic survey work was completed in February, 2010. There were no similar prepaid expenses at December 31, 2008.

Accounts payable increased $102,402 (49%) to $310,889 in 2009 from $208,487 in 2008. This increase was primarily due to increased drilling activity at year-end 2009 versus 2008. See the discussion of this activity under “Update of Oil and Gas Exploration and Development Activity from December 31, 2008” in the “Results of Operations” section below.

Deferred income taxes and other decreased $19,472 (9%) to $201,794 in 2009 from $221,266 in 2008. This decrease was primarily due to a decrease of $15,000 in the accrual for some ad valorem tax bills on several Robertson County, Texas, gas wells.

The following is a discussion of material changes in cash flow by activity between the years ending December 31, 2009 and 2008. 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 2009 were $5,304,623 which, when compared to the $13,543,730 provided in 2008, represents a decrease of $8,239,107 or 61%. The decrease was mostly due to a decline in oil and gas sales cash flows of $11,586,529; a decrease in lease bonuses and coal royalties of $660,978; a decline in interest income of $271,729 and increased exploration costs of $879,175. Those decreases in cash flows were partially offset by a decrease in production costs of $658,499 and a decrease in income taxes paid of $4,506,861. Additional discussion of the more significant items follows.

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Discussion of Selected Material Line Items Resulting in a Decrease in Cash Flows. The $11,586,529 (57%) decrease in cash received from oil and gas sales to $8,871,090 in 2009 from $20,457,619 in 2008 was the result of a decrease in both the average oil and gas prices and the volume of oil and gas sales. See “Results of Operations” below for a price/volume analysis and the related discussion of oil and gas sales.

Cash received for lease bonuses and coal royalties declined $660,978 (71%) to $275,707 in 2009 from to $936,685 in 2008. Most of the decrease is due to a decrease in cash received for lease bonuses of about $694,000 in 2009 versus 2008. This decrease was offset by an increase in the cash received for coal royalties of $32,995 to $226,399 in 2009 from $193,404 in 2008.

Cash received for interest earned on cash equivalents and available-for-sale securities decreased $271,729 (70%) to $118,477 in 2009 from $390,206 in 2008. The decrease was the result of a decrease in the average rate of return to 0.73% in 2009 from 2.41% in 2008.

Cash flow decreased due to an increase in cash paid for exploration expenses of $879,175 to $891,221 in 2009 from $12,046 in 2008. About $490,000 of the increase was due to increased geological and geophysical expense in 2009 versus 2008 due partly to the prepaid seismic balance at 2009 year-end. The remaining increase of about $389,000 was due to higher dry hole costs in 2009 versus 2008.

Discussion of Selected Material Line Items Resulting in an Increase in Cash Flows. Cash paid for production costs decreased $658,499 (29%) to $1,590,437 in 2009 from $2,248,936 in 2008. This decline was due to a $123,053 decrease in lease operating and handling expenses and a decrease of $521,623 in production taxes in 2009 versus 2008. Most of the lease operating expense decrease was attributable to lower workover costs in 2009 versus 2008. The decrease in production taxes was due to the decline in sales in 2009 versus 2008.

Income taxes paid decreased $4,506,861 (99%) to $18,476 in 2009 from $4,525,337 in 2008 due to no estimated tax payments in 2009 discussed above and below in “Results of Operations.”

Investing Activities

Net cash applied to investing activities decreased $3,387,434 (46%) to $4,028,723 in 2009 from $7,416,157 in 2008. In 2009, net cash applied to available-for-sale securities decreased to $949,902 in 2009 from $2,675,042 in 2008. This decline was a result of utilizing a smaller portion of the operations cash flow for financing activities in 2009 as discussed below. Cash flows related to property acquisitions resulted in a decrease in cash applications to investing activities in 2009 versus 2008. Cash applied to property acquisitions decreased $1,940,897 (38%) to $3,222,146 in 2009 from $5,163,043 in 2008 due primarily to decreased exploration and development drilling activity. See the “Update of Oil and Gas Exploration and Development Activity from December 31, 2008” under the “Results of Operations” heading below for more information regarding expenditures related to this drilling activity. Cash flow from property dispositions decreased $515,344 to $76,575 in 2009 from $591,919 in 2008 resulting in a decrease of the cash applications to investing activities. Property dispositions in 2008 included proceeds of about $592,000 from the sale of the Company’s ownership interest in a group of Seminole County, Oklahoma producing properties with no similar sales in 2009. The decreases in cash applications for investing activities were offset by an increase in cash distributions from equity investments of $10,200 (156%) to $16,750 in 2009 from $6,550 in 2008. This increase is mostly due to a $10,000 distribution in 2009 from the Bailey Hilltop Pipeline, LLC. There was no similar distribution in 2008.

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Financing Activities

Cash applied to financing activities decreased $4,273,526 (72%) to $1,655,591 in 2009 from $5,929,117 in 2008. Cash applied to financing activities consist of cash dividends on common stock and cash used for the purchase of treasury stock. In 2009, cash dividends paid on common stock amounted to $1,565,551 as compared to $5,857,097 in 2008. The decrease was the result of a decrease in the 2009 dividends per share to $10.00 from $40.00 in 2008. The cash applied to the purchase of treasury stock was $90,040 in 2009 as compared to $72,020 in 2008. The increase in treasury stock purchases in 2009 from 2008 is due to a combination of more shares purchased in 2009 (485 shares) versus 2008 (347 shares), offset by a lower average price paid in 2009 of $186 per share versus $208 per share in 2008. For additional information about treasury stock purchases, see Note 1 at the end of Item 5, "Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” above.

Forward-Looking Summary

Despite the current depressed prices being received for crude oil and natural gas sales, the latest estimate of business to be done in 2010 and beyond indicates the projected activity can be funded from cash flow from operations and other internal sources, including net working capital. The Company is engaged in exploratory drilling. If this drilling is successful, substantial development drilling may result. Also, should other exploration projects, which fit the Company’s risk parameters, become available or other investment opportunities become known, capital requirements may be more than the Company has available. If so, external sources of financing could be required.

RESULTS OF OPERATIONS

As disclosed in the Statements of Operations in Item 8 of this Form 10-K, in 2009, the Company had net income of $1,607,399 as compared to a net income of $9,647,693 in 2008. Net income per share, basic and diluted, was $9.92 in 2009, a decrease of $49.51 per share from $59.43 in 2008. Material line item changes in the Statements of Operations will be discussed in the following paragraphs.

Operating Revenues

Operating revenues decreased $11,692,777 (56%) to $9,013,233 in 2009 from $20,706,010 in 2008. Oil and gas sales decreased $10,962,411 (56%) to $8,755,031 in 2009 from $19,717,442 in 2008. Lease bonuses and other revenues decreased $730,366 (74%) to $258,202 in 2009 from $988,568 in 2008. This decrease was the result of a decline in lease bonuses of $693,972 due to decreased bonuses from East Texas and Colorado leases. In addition, coal royalties from North Dakota leases decreased $36,393 (15%) to $208,894 in 2009 from $245,287 in 2008. The Company does not anticipate that coal royalties will have a significant impact on its future results of operations. The decrease in oil and gas sales will be discussed in the following paragraphs.

The $10,962,411 decrease in oil and gas sales was the result of a $7,575,320 decrease in gas sales, plus a $3,289,663 decrease in oil sales and a $97,428 decrease in miscellaneous oil and gas product sales. The following price and volume analysis is presented to help explain the changes in oil and gas sales from 2008 to 2009. Miscellaneous oil and gas product sales of $192,335 in 2009 and $289,763 in 2008 are not included in the analysis.

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			Variance
Production	2009		Price		Volume		2008

Gas –
MCF (000 omitted)		1,297				(155)		1,452
$(000 omitted)	$	4,454	$	(6,292)	$	(1,283)	$	12,029
Unit Price	$	3.43	$	(4.85)			$	8.28
Oil –
Bbls (000 omitted)		79				(1)		80
$(000 omitted)	$	4,109	$	(3,220)	$	(70)	$	7,399
Unit Price	$	51.64	$	(40.45)			$	92.09

The $7,575,320 (63%) decrease in natural gas sales to $4,453,740 in 2009 from $12,029,060 in 2008 was the result of a decrease in both the average price received per thousand cubic feet (MCF) and gas sales volumes. The average price per MCF of natural gas sales decreased $4.85 per MCF to $3.43 in 2009 from $8.28 per MCF in 2008, resulting in a negative gas price variance of $6,291,637. A negative volume variance of $1,283,683 was the result of a decrease in natural gas volumes sold of 155,034 MCF to 1,297,334 MCF in 2009 from 1,452,368 MCF in 2008. The decrease in the volume of gas production was the net result of new 2009 production of about 247,400 MCF, offset by declines of 402,434 MCF. These declines are a combination of normal declines in production from mature producing properties and some operator curtailments in Robertson County, Texas. These curtailments are discussed below. 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 2009 but not in 2008.

The gas production for 2008 and 2009 includes production from several royalty interest properties drilled by various operators in Robertson County, Texas. The first of these wells began producing in late March 2005, and the most recent one began producing in November 2009. These properties accounted for approximately 845,000 MCF and $7,279,000 of the 2008 gas sales and approximately 729,000 MCF and $2,504,000 of the 2009 gas sales. The production decline of 116,000 MCF was the net result of new 2009 gas production of about 128,000 MCF, offset by a decline in existing gas production of about 244,000 MCF. This decrease was due to a combination of normal production declines plus operator curtailments due to depressed natural gas prices in late 2009. This group of royalty interest properties accounted for about 75% of the 2009 production decline. However, these same properties accounted for about 56% of the Company’s 2009 gas revenues and continue to have a significant impact on our operating income. While the operators are currently drilling and plan more drilling in the future on the acreage in which the Company holds mineral interests, the Company has no control over the timing of such activity.

The $3,289,663 (44%) decrease in crude oil sales to $4,108,956 in 2009 from $7,398,619 in 2008 was the result of a decrease in both the average price per barrel (Bbl) and oil sales volumes. The average price received per Bbl of oil decreased $40.45 to $51.64 in 2009 from $92.09 in 2008, resulting in a negative oil price variance of $3,219,553. A decrease in oil sales volumes of 761 Bbls to 79,576 Bbls in 2009 from 80,337 Bbls in 2008, resulted in a negative volume variance of $70,110. The decrease in the oil volume production was the net result of new 2009 production of about 13,530 Bbls, offset by 14,291 Bbls of normal decline in production from mature producing properties. Of the new 2009 production, approximately 6,750 Bbls (50%) was from Woods County, Oklahoma. Of the remaining new production, about 5,950 Bbls (44%) was from new working interest wells in Kansas and Oklahoma (in counties other than Woods) and about 830 Bbls (6%) was from new royalty interest wells in Texas and Oklahoma. As disclosed in Supplemental Schedule 1 of the Unaudited Supplemental Financial Information included below in Item 8, working interests in oil extensions and discoveries were not adequate to replace working interest reserves produced in 2009 or 2008.

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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. Spot market price declines in 2009 and late 2008 for both crude oil and natural gas provided an excellent example of the fluctuations that can and do occur and the impact they can have on operating results. The decline in average spot market prices in 2009 from 2008 accounted for about $9,510,000 (87%) of the $10,962,000 decrease in oil and gas sales for 2009 from 2008.

Operating Costs and Expenses

Operating costs and expenses decreased $706,218 (9%) to $7,471,313 in 2009 from $8,177,531 in 2008, primarily due to decreases in production costs and depreciation, depletion and amortization, offset by an increase in exploration expense. The material components of operating costs and expenses are discussed below.

Production Costs. Production costs decreased $663,232 (29%) to $1,608,992 in 2009 from $2,272,224 in 2008. The decrease was the result of a $521,623 (58%) decline in gross production tax (net of production tax refunds) to $381,601 in 2009 from $903,224 in 2008, plus a decrease in lease operating and handling expense of $141,609 (10%) to $1,227,391 in 2009 from $1,369,000 in 2008. Most of the decrease in lease operating and handling expense was due to a decrease in handling expense of $85,455 (21%) to $321,438 in 2009 from $406,893 in 2008. Most of the handling expense decline was due to the decreased gas sales from the Robertson County, Texas royalty interest properties. 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. Most of the gross production tax refunds relate to the Robertson County, Texas properties and are due to a Texas program used as an incentive to encourage operators to drill deep or tight sands gas wells. These refunds are not permanent but are for a limited number of months of production.

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 $3,693,128 in 2009 and $4,827,352 in 2008. See Item 8, Note 8 to the accompanying financial statements for additional information regarding a breakdown of these costs. Costs charged to operations were $987,088 in 2009 and $142,550 in 2008, inclusive of geological and geophysical costs of $292,326 in 2009 and $120,446 in 2008.

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Update of Oil and Gas Exploration and Development Activity from December 31, 2008. For the twelve months ended December 31, 2009, the Company participated in the drilling of sixteen gross exploratory and seventeen gross development working interest wells with working interests ranging from a high of 18.0% to a low of 2.7%. Of the sixteen exploratory wells, seven were completed as producing wells, six as dry holes and three were in progress. Of the seventeen development wells, fourteen were completed as producing wells and three 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 March 3, 2010, updating both exploration and development activity from December 31, 2008.

	The Company participated with its 18% working interest in the drilling of two development wells on a Barber County, Kansas prospect. Both wells were drilled in October 2009 and completed in January 2010. Both appear to be commercial oil wells. Capitalized costs as of December 31, 2009, were $141,576, including $34,423 in prepaid drilling costs.

	The Company participated with its 18% working interest in the drilling of two step-out wells on a Barber County, Kansas prospect. Both wells were started in November 2008 and completed in July 2009 as commercial oil and gas producers. Total capitalized costs were $199,778 at December 31, 2009.

	The Company participated in the drilling of three exploratory wells on a Grady County, Oklahoma prospect in which it has a 10% interest. The first well was started in July 2008 and completed in March 2009 as a commercial gas and condensate producer. The second well was started in August 2008 and completed in April 2009, flowing gas and condensate at a commercial rate. Sales commenced in June 2009. The third well, a re-entry and sidetrack of a 2007 exploratory dry hole, was started in December 2008 and completed in January 2009 as a dry hole. The Company also participated in a step-out well, which was started in September 2009 and completed in December 2009 as a commercial gas and condensate producer. In July 2009, the Company participated in the acquisition of additional 3-D seismic data over a portion of the prospect. Potential drilling locations have been identified and acreage is currently being acquired. Total capitalized costs for the period ended December 31, 2009, were $191,403, including $32,860 in prepaid drilling costs. Dry hole costs of $125,874 and seismic costs of $45,811 were expensed as of December 31, 2009.

	The Company participated with its 16.2% working interest in the drilling of an exploratory well on a Comanche County, Kansas prospect. The well was started in November 2008 and completed in March 2009 as a marginal oil and gas producer. It has subsequently been re-completed in another zone but remains a marginal well. Total capitalized costs as of December 31, 2009, were $120,511.

	The Company participated with its 18% working interest in the drilling of an exploratory well on a Kiowa County, Kansas prospect. The well was started in November 2008 and completed in February 2009 as a commercial oil and gas producer. The Company also participated in the drilling of two exploratory step-out wells. The first was started in October 2009 and completed in December 2009. The well was non-commercial and will be plugged. The second was drilled in November 2009 and completed as a dry hole. Total capitalized costs were $156,680 at December 31, 2009, including $31,239 in prepaid drilling costs. Total dry hole costs were $101,063 for the same period.

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	The Company participated with its 18% working interest in the drilling of two exploratory wells on a Comanche County, Kansas prospect. The first was started in April 2009 and completed in June 2009 as a commercial oil and gas well. The second was drilled in April 2009 and completed as a dry hole. The Company also participated in the drilling of two step-out wells. The first was started in November 2009 and completed in February 2010. It appears to be a marginal well. The second was started in November 2009 and a completion attempt is currently in progress. As of December 31, 2009, capitalized costs were $269,519, including prepaid drilling costs of $109,001, and dry hole costs were $31,477.

	The Company participated with its 18% working interest in the drilling of an exploratory well on a Comanche County, Kansas prospect. The well was started in May 2009 and completed in July 2009 as a marginal oil and gas producer. Capitalized costs at December 31, 2009, were $98,023.

	The Company participated with its 18% working interest in the drilling of two exploratory wells on a Comanche County, Kansas prospect. One was drilled in May 2009 and the other in June 2009. Both were completed in October 2009, the first as a marginal oil and gas well and the second as a commercial gas well. Capitalized costs at December 31, 2009, were $185,184, including $39,595 in prepaid drilling costs.

	The Company participated with its 16% working interest in the drilling of two step-out wells on a Harper County, Kansas prospect. Both wells were started in June 2009 and completed in October 2009 as commercial oil and gas wells. Two additional wells, one exploratory and one a step-out, will be drilled starting in March 2010. Total capitalized costs at December 31, 2009, were $155,663.

	The Company participated with an 18% interest in the development of a McClain County, Oklahoma prospect. Acreage has been acquired and an exploratory well will be drilled in 2010. Leasehold costs at December 31, 2009, were $10,606.

	The Company participated with a 50% interest in the development of another McClain County, Oklahoma prospect. Acreage was acquired and agreements negotiated to sell part of the Company’s interest and to obtain access to a 3-D seismic survey which covered the prospect area. The Company retained a 16% interest in the prospect acreage. An exploratory well was started in December 2009 and a completion attempt is currently in progress. Capitalized costs at December 31, 2009, were $105,019, including leasehold costs of $31,382 and prepaid drilling costs of $38,369.

	The Company is participating with a 21% interest in the development of a Lincoln County, Oklahoma prospect. Acreage has been acquired and the prospect is under evaluation for the possible drilling of an exploratory horizontal well in 2010. Leasehold costs were $44,124 as of December 31, 2009.

	The Company participated with a 12% working interest in the drilling of two step-out wells on a Woods County, Oklahoma prospect. Both wells were started in June 2009. The first well was completed in July 2009 and the second well in August 2009. Both are commercial oil and gas wells. The Company participated with a 14% working interest in the drilling of two additional step-out wells. Both were started in February 2010 and are currently awaiting completion attempts. Capitalized costs as of December 31, 2009, were $129,600, including $19,761 in prepaid drilling costs.

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	The Company participated with its 10.5% working interest in the drilling of two exploratory wells on a Woods County, Oklahoma prospect. Both wells were started in November 2008. The first was completed in March 2009 as a commercial oil well. The second was completed in April 2009 as a commercial oil and gas well, although it also produces large quantities of water. The Company also participated in the drilling of three step-out wells. Two were started in November 2009 and completed in February 2010. The third, in which the Company has a reduced interest (2.7%), was started in November 2009 and completed in January 2010. All three appear to be commercial oil and gas wells. Total capitalized costs were $366,060 at December 31, 2009, including $578 in prepaid drilling costs.

	The Company participated with its 8% working interest in the drilling of a step-out well on a Woods County, Oklahoma prospect. The well was started in December 2008 and completed in March 2009 as a commercial oil and gas producer. Total capitalized costs were $58,804 at December 31, 2009.

	The Company participated in the drilling of two development wells (18% and 13.7% working interests) on a Woods County, Oklahoma prospect. The first well was started in December 2009 and completed in February 2010 as a commercial oil and gas producer. The second well was started in December 2009 and a completion attempt is currently in progress. Capitalized costs as of December 31, 2009, were $152,001, including $82,402 in prepaid drilling costs.

	In January 2009, the Company purchased a 16% interest in 18,343 net acres of leasehold on a Ford County, Kansas prospect for $176,094. A 3-D seismic survey of the prospect acreage was conducted. An exploratory well was started in August 2009 and completed in September 2009 as a commercial oil well. A step-out well and a second exploratory well were started in December 2009 and completed in February 2010. Both appear to be commercial oil wells. Two additional exploratory wells will be drilled starting in March 2010. Capitalized costs as of December 31, 2009, were $185,984, including $79,622 in prepaid drilling costs. Seismic costs were $219,429.

	In March 2009, the Company purchased a 7% interest in 3,262 net acres of leasehold on a Williams and Defiance Counties, Ohio prospect for $15,702, including $3,889 expensed for seismic. Two exploratory wells were drilled starting in April 2009. Completion attempts on both wells were unsuccessful and the operator has recommended that both be plugged. Costs expensed to dry hole were $59,208 for the period ended December 31, 2009.

	The Company participated with a fee mineral interest in the drilling of two step-out horizontal wells in Van Buren County, Arkansas. The Company has a 9.3% interest in the wells, one of which was started in October 2009 and the other in November 2009. Both were completed in January 2010 as commercial gas wells. Total capitalized costs as of December 31, 2009, were $520,206, including $416,543 in prepaid drilling costs.

	In June 2009, the Company purchased a 10% interest in 315 net acres of leasehold on a Grayson County, Texas prospect for $7,875. An exploratory well was drilled and completed in September 2009 as a dry hole. No additional drilling is planned. Dry hole expenses were $67,478.

	In July 2009, the Company purchased a 6% interest in 10,142 net acres of leasehold on a Ford and Kiowa Counties, Kansas prospect for $18,255. An exploratory horizontal well was started in July 2009 and completed in October 2009. In August and September 2009, an old dry hole was re-entered, washed down, deepened and completed as a salt water disposal well. A second exploratory horizontal well was started in September 2009 and completed in December 2009. Testing of both wells has failed to indicate commercial production and both are currently shut in. The prospect is being re-evaluated. Total capitalized costs as of December 31, 2009, were $247,083, including $65,762 in prepaid drilling costs. An impairment provision of $217,083 has been made as of December 31, 2009.

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	In November 2009, the Company purchased a 16% interest in 20,928 net acres of leasehold on a Hodgeman County, Kansas prospect for $200,904 and paid $219,947 in estimated seismic costs. A 3-D seismic survey was conducted in January and February 2010. The data set is currently being processed, after which, it will be evaluated to find exploratory drilling locations.

	In November 2009, four wells in Harding County, South Dakota, in which the Company had working interests of 10.9%, 25%, 14.6% and 18.8%, were unitized into a secondary recovery unit. The Company has an 8.3% working interest in the unit. Two of the nine unit wells have been converted from oil producers to water injectors. Two additional water injection wells will be drilled in 2010. Total capitalized costs for the unit for the period ended December 31, 2009, were $83,669.

	In November 2009, the Company agreed to participate with its 4.8% working interest in the drilling of a horizontal development well on a Dewey County, Oklahoma prospect. The well will be drilled in the second quarter of 2010.

Depreciation, Depletion, Amortization and Valuation Provisions (DD&A). Major 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 $369,915 in 2009 and $140,562 in 2008. The increase in the provision for impairment is directly related to the exploration activity discussed under “Exploration and Development Costs,” above. Of the 2009 provision, $327,528 was due to the annual amortization of undeveloped leaseholds and $42,387 was due to specific leasehold impairments. The 2008 provision was entirely due to the annual amortization of undeveloped leaseholds with none due to specific leasehold impairments.

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 and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amounts. Evaluation for impairment was performed in both 2009 and 2008. The 2009 impairment loss of $1,353,020 and the 2008 impairment loss of $1,924,219 were partly the result of reserve adjustments on wells which first produced in 2006, 2007 and 2008 and partly due to wells completed in 2009, 2008, 2007 and 2006 for which the estimated fair value of future production was less than the Company’s carrying amount in the well. The depressed oil and natural gas prices at 2008 year-end and the average prices for 2009 had a significant impact on the fair value of future production, and accordingly, the impairment loss for both 2009 and 2008.

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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 totaled $1,700,964 in 2009 and $2,204,069 in 2008. Most of the decrease of $503,105 is due to lower oil and gas property additions in 2009 and changes in reserve estimates. It also includes $80,636 for 2009 and $99,116 for 2008 for the amortization of the Asset Retirement Obligation. See Item 8, Note 2 to the accompanying financial statements for additional information regarding the Asset Retirement Obligation.

General, Administrative and Other Expenses (G&A). G&A decreased $25,061 (2%) to $1,434,068 in 2009 from $1,459,130 in 2008. The decrease was primarily due to a decrease in real estate taxes, offset partly by an increase in accounting and legal fees.

Equity Income in Investees. The following is an analysis of equity income in investees by entity for the years ended December 31, 2009 and 2008. See Item 8, Note 7 to the accompanying financial statements for more information about these investments.

	Net Income				2009 Income
	2009		2008		Over/(Under) 2008

Broadway Sixty-Eight, Ltd.	$	27,482	$	73,030	$	(45,548	)
OKC Industrial Properties, LLC		1,518		3,043		(1,525	)
Bailey Hilltop Pipeline, LLC		18,962		9,692		9,270
JAR Investment, LLC		7,514		8,450		(936	)
Total	$	55,476	$	94,215	$	(38,739	)

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 the years ended December 31, 2009 and 2008. Other income, net declined $450,882 (67%) to $223,978 in 2009 from $674,860 in 2008.

Net realized and unrealized gains (losses) on trading securities increased $250,040 to a net gain of $129,441 in 2009 from a net loss of $(120,599) in 2008. 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 2009, the Company had realized gains of $38,884 and unrealized gains of $90,557. In 2008, the Company had realized gains of $43,719 and unrealized losses of $(164,318).

Interest income decreased $265,598 (78%) to $73,528 in 2009 from $339,126 in 2008. This decrease was the result of a decrease in the average rate of return on cash equivalents and available-for-sale securities from which most of interest income is derived. The average rate of return decreased 1.68% to 0.73% in 2009 from 2.41% in 2008. An increase of only $62,514 in the average balance outstanding to $16,281,663 from $16,219,149 in 2008 had almost no impact on the average rate of return.

Most of the remaining decrease in this line item was due to the decrease in gains on asset sales of $439,526 to $12,950 in 2009 from $452,475 in 2008. The decrease in the gains on asset sales was due primarily to a $449,516 gain on the sale of the Company’s ownership interest in a group of Seminole County, Oklahoma producing properties in 2008, most of which were acquired in 2003. There were no similar sales in 2009.

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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 2009, the Company had an estimated provision for income taxes of $213,975 as the result of a current tax provision of $703,741 plus a deferred tax benefit of $(489,766). In 2008, the Company had an estimated provision for income taxes of $3,649,861 as the result of a current tax provision of $3,372,669 plus a deferred tax provision of $277,192.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Smaller reporting companies are not required to provide the information required by this Item.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Financial Statements

	Page
Report of Independent Registered Public Accounting Firms
HoganTaylor LLP – 2009	25
Eide Bailly LLP – 2008	26
Balance Sheets - December 31, 2009 and 2008	27
Statements of Income - Years Ended December 31, 2009 and 2008	29
Statements of Stockholders’ Equity – Years Ended December 31, 2008 and 2009	30
Statements of Cash Flows – Years Ended December 31, 2009 and 2008	31
Notes to Financial Statements	33
Unaudited Supplemental Financial Information	43

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

The Reserve Petroleum Company

We have audited the accompanying balance sheet of The Reserve Petroleum Company as of December 31, 2009, and the related statements of income, stockholders’ equity and cash flows for the year ended December 31, 2009. 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 audit.

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, 2009, and the results of its operations and its cash flows for the year ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

We were not engaged to examine management's assessment of the effectiveness of The Reserve Petroleum Company's internal control over financial reporting as of December 31, 2009, included in the accompanying Management's Annual Report on Internal Control Over Financial Reporting and, accordingly, we do not express an opinion thereon.

/s/ HoganTaylor LLP

Oklahoma City, Oklahoma

March 31, 2010

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and

Stockholders of The Reserve Petroleum Company

We have audited the accompanying balance sheet of The Reserve Petroleum Company as of December 31, 2008, and the related statements of income, stockholders’ equity and cash flows for the year ended December 31 , 2008. The Reserve Petroleum Company’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit 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 audit 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 of the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides 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, 2008, and the results of its operations and its cash flows for the year ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

/s/ Eide Bailly LLP

Greenwood Village, Colorado

March 29, 2009

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THE RESERVE PETROLEUM COMPANY

BALANCE SHEETS

ASSETS

	December 31,
	2009		2008
Current Assets:
Cash and Cash Equivalents (Note 2)	$	1,051,141	$	1,430,832
Available-for-Sale Securities (Notes 2 & 5)		16,070,475		15,120,573
Trading Securities (Notes 2 & 5)		350,372		218,228
Refundable Income Taxes		314,308		999,573
Receivables (Notes 2 & 7)		1,444,757		1,738,856
Prepaid Expenses		197,304		----
		19,428,357		19,508,062
Investments:
Equity Investments (Notes 2 & 7)		601,309		562,584
Other		15,298		15,298
		616,607		577,882
Property, Plant and Equipment (Notes 2, 8 & 10):
Oil & Gas Properties, at Cost Based on the
Successful Efforts Method of Accounting
Unproved Properties		1,391,539		1,029,500
Proved Properties		23,317,446		20,543,660
		24,708,985		21,573,160
Less - Valuation Allowance & Accumulated
Depreciation, Depletion and Amortization		16,305,361		12,932,782
		8,403,624		8,640,378
Other Property and Equipment, at Cost		376,734		375,544
Less - Accumulated Depreciation & Amortization		290,044		272,779
		86,690		102,765
Total Property, Plant & Equipment		8,490,314		8,743,143
Other Assets		350,389		325,744
Total Assets	$	28,885,667	$	29,154,831

See Accompanying Notes

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THE RESERVE PETROLEUM COMPANY

BALANCE SHEETS

LIABILITIES AND STOCKHOLDERS’ EQUITY

	December 31,
	2009		2008

Current Liabilities:
Accounts Payable (Note 2)	$	310,889	$	208,487
Other Current Liabilities -
Deferred Income Taxes and Other		201,794		221,266
		512,683		429,753
Long Term Liabilities:
Asset Retirement Obligation (Note 2)		699,392		516,054
Dividends Payable (Note 3)		1,015,095		959,319
Deferred Tax Liability (Note 6)		1,125,923		1,613,163
		2,840,410		3,088,536
Total Liabilities		3,353,093		3,518,289

Commitments & 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		26,100,088		26,114,016
		26,257,456		26,271,384
Less - Treasury Stock, at Cost		724,882		634,842
Total Stockholders’ Equity		25,532,574		25,636,542
Total Liabilities and Stockholders’ Equity	$	28,885,667	$	29,154,831

See Accompanying Notes

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THE RESERVE PETROLEUM COMPANY

STATEMENTS OF INCOME

	Year Ended December 31,
	2009		2008

Operating Revenues:
Oil & Gas Sales	$	8,755,031	$	19,717,442
Lease Bonuses & Other Revenues		258,202		988,568
		9,013,233		20,706,010
Operating Costs and Expenses:
Production		1,608,992		2,272,224
Exploration		987,088		142,550
Depreciation, Depletion, Amortization & Valuation Provisions		3,441,165		4,303,627
General, Administrative and Other		1,434,068		1,459,130
		7,471,313		8,177,531
Income from Operations		1,541,920		12,528,479
Equity Income in Investees (Note 7)		55,476		94,215
Other Income, Net (Note 11)		223,978		674,860
Income before Income Taxes		1,821,374		13,297,554
Provision for Income Taxes (Notes 2 & 6)		213,975		3,649,861
Net Income	$	1,607,399	$	9,647,693

Per Share Data (Note 2):
Net Income, Basic and Diluted	$	9.92	$	59.43
Cash Dividends	$	10.00	$	40.00
Weighted Average Shares Outstanding, Basic and Diluted		162,040		162,325

See Accompanying Notes

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THE RESERVE PETROLEUM COMPANY

STATEMENTS OF STOCKHOLDERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2008 AND 2009

			Additional
	Common		Paid-in		Retained			Treasury
	Stock		Capital		Earnings			Stock


Balance at January 1, 2008	$	92,368	$	65,000	$	22,957,809		$	(562,822	)

Net Income		---		---		9,647,693			---

Dividends Declared		---		---		(6,491,486	)		---

Purchase of Treasury Stock		---		---		---			(72,020	)

Balance at December 31, 2008	$	92,368	$	65,000	$	26,114,016		$	(634,842	)

Net Income		---		---		1,607,399			---

Dividends Declared		---		---		(1,621,327	)		---

Purchase of Treasury Stock		---		---		---			(90,040	)

Balance at December 31, 2009	$	92,368	$	65,000	$	26,100,088		$	(724,882	)

See Accompanying Notes

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THE RESERVE PETROLEUM COMPANY

STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2009			2008

Cash Flows from Operating Activities:
Cash Received-
Oil and Gas Sales	$	8,871,090		$	20,457,619
Lease Bonuses and Coal Royalties		275,707			936,685
Agricultural Rentals & Other		4,900			5,118
Cash Paid-
Production Costs		(1,590,437	)		(2,248,936	)
Exploration Costs		(891,221	)		(12,046	)
General Suppliers, Employees and Taxes,
Other than Income Taxes		(1,486,515	)		(1,456,691	)
Interest Received		118,477			390,206
Interest Paid		(3,877	)		(3,866	)
Settlement of Class Action Lawsuits		24,946			1,674
Dividends Received on Trading Securities		2,732			931
Purchase of Trading Securities		(1,047,123	)		(529,178	)
Sale of Trading Securities		1,044,420			527,551
Income Taxes Paid, net		(18,476	)		(4,525,337	)
Net Cash Provided by Operating Activities	$	5,304,623		$	13,543,730

Cash Flows from Investing Activities:
Maturity of Available-for-Sale Securities		32,944,856			26,632,838
Purchase of Available-for-Sale Securities		(33,894,758	)		(29,307,880	)
Proceeds from Disposal of Property		76,575			591,919
Purchase of Property, Plant and Equipment		(3,222,146	)		(5,163,043	)
Cash Distributions from Equity Investments		16,750			6,550
Repayments from/(Advances to) Equity Investees		50,000			(176,541	)
Net Cash Applied to Investing Activities	$	(4,028,723	)	$	(7,416,157	)

See Accompanying Notes

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THE RESERVE PETROLEUM COMPANY

STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2009			2008

Cash Flows Applied to Financing Activities:
Dividends Paid to Shareholders	$	(1,565,551	)	$	(5,857,097	)
Purchase of Treasury Stock		(90,040	)		(72,020	)
Total Cash Applied to Financing Activities	$	(1,655,591	)	$	(5,929,117	)
Net Change in Cash and Cash Equivalents		(379,691	)		198,456
Cash and Cash Equivalents at Beginning of Year		1,430,832			1,232,376
Cash and Cash Equivalents at End of Year	$	1,051,141		$	1,430,832
Reconciliation of Net Income to Net
Cash Provided by Operating Activities:
Net Income	$	1,607,399		$	9,647,693
Net Income Increased (Decreased) by -
Net Change in -
Unrealized Holding (Gains) Losses on Trading Securities		(90,557	)		164,318
Accounts Receivable		63,998			709,001
Interest and Dividends Receivable		118,004			51,079
Income Taxes (Refundable) Payable		105,006			(1,152,667	)
Accounts Payable		125,440			14,739
Trading Securities		(41,587	)		(45,345	)
Other Assets		(221,949	)		98,297
Deferred Taxes		90,493			277,192
Other Liabilities		3,696			8,720
Equity Income in Investees		(55,476	)		(94,215	)
Disposition of Property & Equipment		158,991			(438,709	)
Depreciation, Depletion, Amortization and Valuation Provisions		3,441,165			4,303,627
Net Cash Provided by Operating Activities	$	5,304,623		$	13,543,730

See Accompanying Notes

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THE RESERVE PETROLEUM COMPANY

NOTES TO FINANCIAL STATEMENTS

Note 1 – NATURE OF OPERATIONS

The Company is principally engaged in oil and natural gas exploration and development and minerals management with areas of concentration in Texas, Oklahoma, Kansas 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 equity securities in one of three categories: trading, available-for-sale and held-to-maturity. Trading securities are bought and held principally for the purposes of selling them in the near term. Held-to-maturity securities are those securities in which the Company has both the ability and intent to hold the security until maturity. All other securities not included in trading or held-to-maturity 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 almost entirely of U.S. Government securities, are reported as a component of other comprehensive income, when significant to the financial statements.

Equity Investments:

The Company accounts for its investments in a partnership and limited liability companies on the equity basis and adjusts the investment balance to agree with its equity in the underlying assets of the entities. 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.

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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 exploration, 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 are 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.

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

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

Office furniture & fixtures	5 to 10 years
Automotive equipment	5 to 8 years

Impairment losses are recorded on long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. See Note 10 for discussion of impairment losses.

Income Taxes

The Company utilizes a 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 return for 2008 is subject to examination. An audit of the Company’s 2007 Federal income tax return was conducted in 2009 by the Internal Revenue Service. There were no changes to the income tax return as originally filed, nor any changes to the 2007 income tax provision.

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 the years ended December 31, 2009 and 2008, the Company had no dilutive shares outstanding, therefore basic and diluted earnings per share are the same.

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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 four purchasers in 2009 and 2008 whose purchases were in excess of 10% 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 exceeds its estimated remaining recoverable reserves (over produced). No receivables are recorded for those wells where the Company has taken less than its ownership share of gas production (under produced).

Guarantees

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

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 and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset is amortized to expense over the life of the property. The liability is accreted annually at 3.25%.

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The following table summarizes the asset retirement obligation for the years ended December 31:

	2009		2008
Beginning balance at January 1	$	516,054	$	---
Liabilities incurred		108,024		505,733
Liabilities settled		---		---
Accretion expense		20,642		10,321
Revision to estimate		54,672		---
Ending balance at December 31	$	699,392	$	516,054

New Accounting Pronouncements

In June 2009, the FASB issued Accounting Standards Update 2009-01, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles (FASB ASC) — a replacement of FASB Statement No. 162” (“ASU 2009-01”). The FASB ASC is intended to be the source of authoritative GAAP and reporting standards as issued by the FASB. The primary purpose of the FASB ASC is to improve clarity and use of existing standards by grouping authoritative literature under common topics. ASU 2009-01 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Codification does not change or alter existing GAAP. The implementation of ASU 2009-01 had no impact to the Company’s financial position or results of operations.

In January 2010, the FASB issued Accounting Standards Update 2010-03 (“ASU 2010-03”) to align the oil and gas reserve estimation and disclosure requirements of ASC Topic 932, Extractive Industries — Oil and Gas, with the requirements in the Securities and Exchange Commission’s final rule, Modernization of the Oil and Gas Reporting Requirements, which was issued on December 31, 2008, and was effective for the year ended December 31, 2009. The Modernization of the Oil and Gas Reporting Requirements was designed to modernize and update the oil and gas disclosure requirements to align with current practices and changes in technology. Key provisions of ASU 2010-03 affecting the Company are as follows:

The new rules require reserve estimates to be calculated using a 12-month average price. The use of a 12-month average price rather than a single-day price is intended to reduce the impact on reserve estimates due to short-term volatility and seasonality of prices.

The new rules require the qualifications of any employee, primarily responsible for preparing or auditing the reserve estimates, to be reported.

The Company implemented ASU 2010-03, prospectively, as a change in accounting principle inseparable from a change in accounting estimate at December 31, 2009. The Company has not determined reserve levels at December 31, 2009, under the previous accounting rules due to the operational and technical challenges of preparing reserve reports under two sets of rules; and therefore, it is not practicable to determine the impact of adopting this accounting principle.

Reclassifications

Certain amounts in the 2008 financial statements have been reclassified to conform to the 2009 presentaion. The amounts were not material to the financial statements and had no effect on previously reported net income.

Note 3 – DIVIDENDS PAYABLE

Dividends payable include amounts that are due to stockholders whom the Company has been unable to locate and uncashed dividend checks of other stockholders.

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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, 2008, $.50 par value stock, 400,000 shares authorized		184,735.28		22,209.64		162,525.64
Purchase of stock		---		347.00		(347.00	)
December 31, 2008, $.50 par value stock 400,000 shares authorized		184,735.28		22,556.64		162,178.64
Purchase of stock		---		485.00		(485.00	)
December 31, 2009, $.50 par value stock 400,000 shares authorized		184,735.28		23,041.64		161,693.64

Note 5 – MARKETABLE SECURITIES

Available-for-sale securities, consisting almost entirely of U.S. government securities by contractual maturity are as follows at December 31, 2009:

Due within one year or less

16,070,475

For trading securities, during 2009, the Company recorded realized gains of $38,884 and unrealized gains of $90,557. During 2008, the Company recorded realized gains of $43,719 and unrealized losses of $(164,318).

Note 6 – INCOME TAXES

Components of deferred taxes follow:

	December 31,
	2009			2008
Assets
Leasehold Costs (net of impairment reserves)	$	230,736		$	64,774
Gas Balancing Receivable		52,379			52,379
Long-Lived Asset Impairment		905,701			835,711
Marketable Securities		2,284			33,123
Other		153,187			73,764
Total Assets		1,344,287			1,059,751
Liabilities
Receivables		165,377			198,742
Intangible Drilling Costs		2,035,500			2,248,349
Depletion, Depreciation and Other		432,426			391,441
Total Liabilities		2,633,303			2,838,532
Net Deferred Tax Liability	$	(1,289,016	)	$	(1,778,781	)

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

	Year Ended December 31,
	2009			2008
Current Tax Provision:
Federal	$	695,139		$	3,337,569
State		8,602			35,100
		703,741			3,372,669
Deferred Provision/(Benefit)		(489,766	)		277,192
Total Provision	$	213,975		$	3,649,861

The total provision for income tax expressed as a percentage of income before income tax was 12% in 2009 and 27% in 2008. These amounts differ from the amounts computed by applying the statutory U.S. Federal income tax rate of 34% for 2009 and 2008 to income before income tax as summarized in the following reconciliation:

	Year Ended December 31,
	2009			2008
Computed Federal Tax Provision	$	619,267		$	4,521,168
Increase (Decrease) in Tax From:
Allowable Depletion in Excess of Basis		(407,974	)		(942,714	)
Dividend Received Deduction		(650	)		(222	)
State Income Tax Provision		8,602			35,100
Other		(5,270	)		36,529
Provision for Income Tax	$	213,975		$	3,649,861
Effective Tax Rate		12	%		27	%

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Note 7 – EQUITY INVESTMENTS

The carrying values of Equity Investments consist of the following at December 31:

	Ownership %	2009			2008
Broadway Sixty-Eight, Ltd.	33%	$	479,136		$	451,654
JAR Investment, LLC	25%		(2,738	)		(5,001	)
Bailey Hilltop Pipeline, LLC	10%		70,195			61,233
OKC Industrial Properties, LLC	10%		54,716			54,698
		$	601,309		$	562,584

Broadway Sixty-Eight, Ltd. (the “Partnership”), an Oklahoma limited partnership, owns and operates an office building in Oklahoma City, Oklahoma. Although the Company invested as a limited partner, it agreed, jointly and severally, with all other limited partners to reimburse the general partner for any losses suffered from operating the Partnership. The indemnity agreement provides no limitation to the maximum potential future payments. To date, no monies have been paid with respect to this agreement.

The Company leases its corporate office from the Partnership. The operating lease, under which the space was rented, expired December 31, 1995, and the space is currently rented on a year-to-year basis under the terms of the expired lease. Rent expense for lease of the corporate office from the Partnership was approximately $28,000 for each of the years ended December 31, 2009 and 2008.

Included with Receivables is a Note receivable in the amount of $75,000 from the Partnership bearing 3.5% interest and due December 31, 2009. On December 31, 2009, the interest due on this note was received along with a new Note receivable from the Partnership bearing 3.5% interest and due June 30, 2010. The Note receivable and interest rate included with Receivables at December 31, 2008, was $125,000 with a 5% rate. This related party transaction is connected to the construction of a new office building.

JAR Investment, LLC (JAR), an Oklahoma limited liability company, previously held Oklahoma City metropolitan area real estate that was sold in June 2005 (see below). JAR also owns a 70% management interest in Main-Eastern, LLC (M-E), an Oklahoma limited liability company. M-E was formed in 2002 to establish a joint venture to develop a retail/commercial center on a portion of JAR’s real estate.

The Company has a guarantee agreement limited to 25% of JAR’s 70% interest in M-E’s outstanding loan, plus all costs and expenses related to enforcement and collection or $133,409 at December 31, 2009. This loan matures December 27, 2013. The Company has evaluated its guarantee related to this obligation and believes it is unlikely to have to make any payments under the provisions of the guarantee agreement.

In June 2008, the Company purchased a 10% ownership in Bailey Hilltop Pipeline, LLC (the “Pipeline”) for $51,541. The Pipeline was constructed for the transportation of gas from wells in the Bailey Hilltop prospect.

OKC Industrial Properties, LLC, an Oklahoma limited liability company, holds certain Oklahoma City metropolitan area real estate as an investment.

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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,
	2009		2008
Acquisition of Properties:
Unproved	$	496,586	$	361,685
Proved	$	---	$	---
Exploration Costs	$	1,618,080	$	981,032
Development Costs	$	2,075,048	$	3,846,320
Asset Retirement Obligation	$	162,696	$	516,054

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 for similar assets that are observable. Level 3 inputs are unobservable inputs.

Recurring Fair Value Measurements

Certain of the Company’s assets are reported at fair value in the accompanying balance sheets on a recurring basis. At December 31, 2009 and 2008, the Company’s assets reported at fair value on a recurring basis are summarized as follows:

	2009

	Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
Financial Assets:
Available-for-sale securities	$	---	$	16,070,475	$	---
Trading securities	$	350,372	$	---	$	---

	2008

	Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
Financial Assets:
Available-for-sale securities	$	---	$	15,120,573	$	---
Trading securities	$	218,228	$	---	$	---

Non-recurring Fair Value Measurements

The Company’s asset retirement obligations incurred annually represent non-recurring fair value liabilities. The fair value of these non-financial liabilities incurred was $108,024 in 2009 and $505,733 in 2008 and was calculated using Level 3 inputs. See Note 2 above for more information about this liability and the inputs used for calculating fair value.

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Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, trade receivables, marketable securities, trade payables and dividends payable. As of December 31, 2009 and 2008, the historical cost of cash and cash equivalents, trade receivables, trade payables and dividends payable are considered to be representative of their respective fair values due to the short-term maturities of these items.

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 $1,353,020 for the year ended December 31, 2009, and $1,924,219 for the year ended December 31, 2008, are included in the Statements of Income in the line item, Depreciation, Depletion, Amortization and Valuation Provisions. The impairments for 2009 and 2008 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. An average monthly price was used for calculating future revenue and cash flow.

Note 11 – OTHER INCOME, NET

The following is an analysis of the components of Other Income, Net for the years ended December 31, 2009 and 2008:

	2009			2008
Net Realized and Unrealized Gain (Loss) on Trading Securities	$	129,441		$	(120,599	)
Gain on Asset Sales		12,950			452,476
Interest Income		73,528			339,126
Settlements of Class Action Lawsuits		24,946			1,674
Agricultural Rental Income		5,600			5,600
Dividend and Other Income		2,732			931
Interest and Other Expenses		(25,219	)		(4,348	)
Other Income, Net	$	223,978		$	674,860

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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), Lochbuie Limited Partnership (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.

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 during 2009 by payment to the Company in the amount of $146,217 by Mesquite, $146,217 by Mid-American and $146,217 by LLTD. Reimbursements for 2008 were $149,195 by Mesquite, $149,195 by Mid-American and $149,195 by LLTD. Included in the 2009 amounts, Mesquite paid $106,528, Mid-American $106,528 and LLTD $106,528 for their share of salaries. In 2008, the share of salaries paid by Mesquite was $108,794, Mid-American $108,794 and LLTD $108,794.

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UNAUDITED SUPPLEMENTAL FINANCIAL INFORMATION

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SUPPLEMENTAL SCHEDULE 1

THE RESERVE PETROLEUM COMPANY

WORKING INTERESTS RESERVE QUANTITY INFORMATION

(Unaudited)

	Year Ended December 31,
	2009			2008
Oil & Natural Gas Liquids (Bbls)
Proved Developed and Undeveloped Reserves:
Beginning of Year		266,865			290,989
Revisions of Previous Estimates		16,320			(1,829	)
Extensions and Discoveries		42,411			45,035
Sales of Reserves		---			(996	)
Production		(65,432	)		(66,334	)
End of Year		260,164			266,865
Proved Developed Reserves:
Beginning of Year		266,865			290,989
End of Year		260,164			266,865
Gas (MCF)
Proved Developed and Undeveloped Reserves:
Beginning of Year		1,555,422			1,664,360
Revisions of Previous Estimates		179,859			119,180
Extensions and Discoveries		475,205			291,743
Sales of Reserves		---			(123,902	)
Production		(399,946	)		(395,959	)
End of Year		1,810,540			1,555,422
Proved Developed Reserves
Beginning of Year		1,555,422			1,664,360
End of Year		1,810,540			1,555,422

See notes on next page.

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SUPPLEMENTAL SCHEDULE 1

THE RESERVE PETROLEUM COMPANY

WORKING INTERESTS RESERVE QUANTITY INFORMATION

(Unaudited)

Notes:

Estimates of royalty interests’ reserves have not been included because the information required for the estimation of said reserves is not available. The Company’s share of production from its net royalty interests was 14,145 Bbls of oil and 897,388 MCF of gas for the year ended December 31, 2009, and 14,004 Bbls of oil and 1,056,409 MCF of gas for the year ended December 31, 2008.

The preceding table sets forth estimates of the Company’s proved developed oil and gas reserves, together with the changes in those reserves, as prepared by the Company’s engineer, for the years ended December 31, 2009 and 2008. The Company engineer’s qualifications in the Proxy Statement are incorporated herein by reference. All reserves are located within the United States.

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.

As of the date of this Form 10-K, the Company has limited internal controls relating to the calculation of its working interests' reserves estimates. However, management reviewed internal controls relative to accounting data flowing into the calculation of the reserves estimates. Management concluded the existing internal controls were effective enough to ensure the weakness indentified was not material, was mitigated, and was not significant enough to cause a material misstatement in the financial statements. Management will review our internal controls and consider possibly strengthening our internal controls in 2010 relative to the reserves estimation process.

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SUPPLEMENTAL SCHEDULE 2

THE RESERVE PETROLEUM COMPANY

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

RELATING TO PROVED WORKING INTERESTS

OIL AND GAS RESERVES

(Unaudited)

	At December 31,
	2009			2008

Future Cash Inflows	$	19,706,075		$	15,536,365

Future Production and Development Costs		(7,793,116	)		(6,406,107	)

Future Income Tax Expense		(2,135,115	)		(1,695,833	)
Future Net Cash Flows		9,777,844			7,434,425

10% Annual Discount for Estimated Timing of Cash Flows		(2,636,067	)		(2,157,644	)
Standardized Measure of Discounted Future Net Cash Flows	$	7,141,777		$	5,276,781

Estimates of future net cash flows from the Company’s proved working interests in oil and gas reserves are shown in the table above. For 2008, these estimates, which by their nature are subject to revision in the near term, were based on prices in effect at December 31, 2008, with no escalation. For 2009, these estimates were based on an average monthly product price received by the Company for the twelve months ended December 31, 2009, 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 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.

The change in method of calculating the estimated product prices in 2009 from 2008 is due to the Company adopting the reserve estimation and disclosure requirements of ASC Topic 932, Extractive Industries – Oil and Gas, prospectively, on December 31, 2009. See Item 8, Note 2 to the accompanying financial statements for additional information on this matter.

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SUPPLEMENTAL SCHEDULE 3

THE RESERVE PETROLEUM COMPANY

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE

NET CASH FLOWS FROM PROVED WORKING INTERESTS RESERVE QUANTITIES

(Unaudited)

	Year Ended December 31,
	2009			2008

Standardized Measure, Beginning of Year	$	5,276,781		$	12,802,235

Sales and Transfers, Net of Production Costs		(3,530,056	)		(7,642,024	)

Net Change in Sales and Transfer Prices, Net of Production Costs		1,971,696			(7,179,892	)

Extensions, Discoveries and Improved Recoveries, Net of Future Production and Development Costs		1,978,755			1,401,574

Revisions of Quantity Estimates		714,279			212,149

Accretion of Discount		648,048			1,687,571

Sales of Reserves in Place		---			(394,649	)

Net Change in Income Taxes		(355,786	)		2,869,772

Changes in Production Rates (Timing) and Other		438,060			1,520,045

Standardized Measure, End of Year	$	7,141,777		$	5,276,781

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ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None .

ITEM 9A.(T).

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.

The Company's 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, 2009.

Changes in Internal Control over Financial Reporting

There were no changes in the Company’s internal control over financial reporting during the quarter ended December 31, 2009, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

Management's Annual Report on Internal Control over Financial Reporting

The management of The Reserve Petroleum 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.

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With the participation of the Chief Executive Officer and Chief 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 , 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, 2009.

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. Management’s report was not subject to attestation by the Company’s independent registered public accounting firms pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report on Form 10-K.

/s/ Cameron R. McLain		/s/ James L. Tyler
Cameron R. McLain, President		James L. Tyler, 2 nd Vice President
Principal Executive Officer		Principal Financial Officer
March 31, 2010		March 31, 2010

ITEM 9B.

OTHER INFORMATION

None.

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information regarding directors and executive officers, compliance with Section 16(a) of the Exchange Act, the Company’s Code of Ethics and Corporate Governance in the Proxy Statement is incorporated herein by reference.

ITEM 11.

EXECUTIVE COMPENSATION

Information regarding executive compensation in the Proxy Statement is incorporated herein by reference.

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 in the Proxy Statement is incorporated herein by reference.

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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 in the Proxy Statement is incorporated herein by reference.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

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

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 November 1, 1988, is incorporated by reference to Exhibit 3.1 of The Reserve Petroleum Company’s Annual Report on Form 10-KSB (Commission File No. 0-8157) filed March 28, 1997.

	3.2	Amended By-Laws dated November 16, 2004, are incorporated by reference to Exhibit 3.2 of The Reserve Petroleum Company’s Annual Report on Form 10-KSB (Commission File No. 0-8157) filed March 30, 2006.

	14	Code of Ethics incorporated by reference to Exhibit 14 of The Reserve Petroleum Company’s Annual Report on Form 10-KSB (Commission File No. 0-8157) filed March 30, 2006.

	31.1*	Certification of Principal Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as amended.

	31.2*	Certification of Principal Financial Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as amended.

	32*	Certification of Principal Executive Officer and Principal Financial Officer Pursuant to 18 U.S.C. Section 1350.

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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/	James L. Tyler
	By:	James L. Tyler, 2 nd Vice President
		(Principal Financial Officer)

Date: March 31, 2010

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/ Mason McLain		/s/ Jerry L. Crow
Mason W. McLain (Director)		Jerry L. Crow (Director)
March 31, 2010		March 31, 2010

/s/ Robert L. Savage		/s/ William M. Smith
Robert L. Savage (Director)		William M. Smith (Director)
March 31, 2010		March 31, 2010

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Part I Item 1. Business Item 1A. Risk Factors Item 1B. Unresolved Staff Comments Item 2. Properties Item 3. Legal Proceedings Item 4. (removed and Reserved)Part II Item 5. Market For Registrant S Common Equity, Related Stock-holder M Atters and Issuer Purchases Of Equity Securities Item 6. Selected Financial Data Item 7. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 7A. Quantitative and Qualitative Disclosures About Market Risks Item 8. Financial Statements and Supplementary Data Note 1 Nature Of Operations Note 2 Summary Of Significant Accounting Policies Note 3 Dividends Payable Note 4 Common Stock Note 5 Marketable Securities Note 6 Income Taxes Note 7 Equity Investments Note 8 Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Note 9 Fair Value Measurements Note 10 Long-lived Assets Impairment Loss Note 11 Other Income, Net Note 12 Certain Relationships and Related Transactions Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Item 9A. (t). Controls and Procedures Item 9A. (t)Item 9B. Other Information Part III Item 10. Directors, Executive Officers and Corporate Governance Item 11. Executive Compensation Item 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder Matters Item 13. Certain Relationships and Related Transactions and Director Independence Item 14. Principal Accountant Fees and Services Part IV Item 15. Exhibits and Financial Statement Schedules

Exhibits

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.

RSRV 10-K Fiscal year ended Dec. 31, 2009

Exhibits