RESERVE PETROLEUM CO - Annual Report: 2011 (Form 10-K)

rpc_10k-123111.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the Fiscal Year Ended December 31, 2011

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

Commission File Number 0-8157

THE RESERVE PETROLEUM COMPANY

(Exact Name of Registrant as Specified in Its Charter)

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

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

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

COMMON STOCK ($0.50 PAR VALUE)

(Title of Class)

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.

Yes o No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.YesxNoo

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).YesxNoo

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.x

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

Accelerated filer

Non-accelerated filer

Smaller reporting company

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

The aggregate market value of the voting and non-voting common stock of the registrant held by non-affiliates of the registrant was $37,865,264, as computed by reference to the last reported sale which was on March 22, 2012.

As of March 22, 2012, there were 160,957.64 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 15, 2012, which will be filed within 120 days of the end of the registrant’s year ended December 31, 2011, are incorporated by reference into Part III of this Form 10-K to the extent described therein.

TABLE OF CONTENTS

		Page
Forward Looking Statements		3

PART I
Item 1.	Business	3
Item 1A.	Risk Factors	5
Item 1B.	Unresolved Staff Comments	5
Item 2.	Properties	5
Item 3.	Legal Proceedings	7
Item 4.	Mine Safety Disclosures	7

PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and
	Issuer Purchases of Equity Securities	7
Item 6.	Selected Financial Data	7
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	8
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	16
Item 8.	Financial Statements and Supplementary Data	16
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	36
Item 9A.	Controls and Procedures	36
Item 9B.	Other Information	37

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	37
Item 11.	Executive Compensation	37
Item 12.	Security Ownership of Certain Beneficial Owners and Management and
	Related Stockholder Matters	37
Item 13.	Certain Relationships and Related Transactions and Director Independence	37
Item 14.	Principal Accountant Fees and Services	37

PART IV
Item 15.	Exhibits and Financial Statement Schedules	38

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 258,918 gross acres equivalent to 89,121 net acres. These mineral interests are located in nine different states in the north and south central United States. A total of 81,988 net acres are located in the States of Arkansas, Kansas, Oklahoma, South Dakota and Texas, the areas of concentration for the Company in its recent 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.

A substantial amount of the Company’s oil and gas revenue has resulted from its owned mineral property management. In 2011, $4,246,293 (35%) of oil and gas sales was from royalty interests versus $4,693,408 (39%) in 2010. As a result of its mineral ownership, the Company had royalty interests in 22 gross (.36 net) wells, which were drilled and completed as producing wells in 2011. This resulted in an average royalty interest of about 1.6% for these 22 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; 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 2011, the Company participated in the drilling of 27 development wells with 17 wells (2.26 net), including the 6 wells in progress at the end of 2010, completed as producers and 10 wells (1.48 net) in progress at the time of this Form 10-K.

Exploration Program

The Company’s exploration program is normally conducted by purchasing interests in prospects developed by independent third parties; participating in third party exploration of Company-owned non-producing minerals; developing 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 2011, the Company participated in the drilling of 17 exploration wells with 9 wells (1.26 net), including the 2 wells in progress at the end of 2010, completed as producers, 4 wells (.61 net) completed as dry holes and 4 wells (.48 net) in progress at the time of this Form 10-K.

For a summation of exploratory and development wells drilled in 2011 or planned for in 2012, 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, 2010.”

Customers

In 2011, the Company had two customers whose total purchases were greater than 10% of revenues from oil and gas sales. Redland Resources, Inc. purchases were $2,776,801, or 25% of total oil and gas sales. Luff Exploration Company purchases were $1,873,561, or 17% of total oil and gas sales. The Company sells most of its oil and gas under short-term sales contracts that are based on the spot market price. A minor amount of oil and gas sales are made under fixed price contracts having terms of more than one year.

Competition

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

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

Regulation

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

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

Environmental Protection and Climate Change

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

In 2009, the EPA officially published its findings that greenhouse gas emissions present an endangerment to human health and the environment. According to the EPA, these emissions are contributing to global warming and climate change. These findings allowed the EPA to adopt and implement regulations in 2010 to restrict these emissions under existing provisions of the Federal Clean Air Act.

The Company may be, directly and indirectly, subject to the effects of climate change and may, directly or indirectly, be affected by government laws and regulations related to climate change. The 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 said laws and regulations may affect, directly or indirectly, (i) the costs associated with drilling and production operations in which we participate; (ii) the demand for oil and natural gas; (iii) insurance premiums, deductibles, and the availability of coverage; and (iv) the cost of utilities paid by the Company. In addition, climate change may increase the likelihood of property damage and the disruption of operations of wells in which we participate. As a result, our financial condition could be negatively impacted, but we are unable to determine at this time whether that impact would be material.

Other Business

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

Employees

At December 31, 2011, the Company had eight employees, including officers. See the Proxy Statement for additional information. During 2011, 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

Not applicable.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2. PROPERTIES

The Company’s principal properties are oil and natural gas properties. The Company has interests in approximately 700 producing properties with one-third of them being working interest properties and the remaining two-thirds being royalty interest properties. About 84% of these properties are located in Oklahoma and Texas and account for approximately 66.0% of the Company’s annual oil and gas sales. About 12% of the properties are located in Arkansas, Kansas, and South Dakota and account for approximately 33.7% of the Company’s annual oil and gas sales. The remaining 4% of these properties are located in Colorado and Montana and account for less than 1% of the Company’s annual oil and gas sales. No individual property provides more than 10% 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 33 for working interest reserve quantity information.

Since January 1, 2011, 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 2010 Annual Report on Form 10-K and federal income tax return for the year ended December 31, 2010. 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, 2011, 2010, and 2009. Equivalent MCF was calculated using approximate relative energy content.

	Royalties		Working Interests
	Sales Price		Sales Price		Average Production
	Oil	Gas	Oil	Gas	Cost per
	Per Bbl	Per MCF	Per Bbl	Per MCF	Equivalent MCF

2011	$ 91.27	$ 3.83	$ 87.32	$ 4.26	$ 1.98
2010	$ 79.62	$ 4.98	$ 70.05	$ 4.47	$ 1.64
2009	$ 53.43	$ 3.40	$ 51.25	$ 3.51	$ 1.68

At December 31, 2011, the Company had working interests in 158 gross (19.53 net) wells producing primarily gas and 162 gross (15.76 net) wells producing primarily oil. These interests were in 63,170 gross (7,980 net) producing acres. These wells include 51 gross (1.20 net) wells associated with secondary recovery projects.

Undeveloped Acreage

The Company’s undeveloped acreage consists of non-producing mineral interests and undeveloped leaseholds. The following table summarizes the Company’s gross and net acres in each at December 31, 2011.

	Acreage
	Gross	Net

Non-producing Mineral Interests	258,918	89,121
Undeveloped Leaseholds	44,571	6,220

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, 2009 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 2011 include the 8 wells still drilling at the end of 2010. As indicated in the “Development Program” on Page 3 and “Exploration Program” on Page 4, 10 development wells and 4 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

2011	1.26	.61	2.26	---
2010	.82	1.14	2.01	---
2009	1.88	1.02	2.85	---

Recent Activities

See Item 7, under the subheading “Update of Oil and Gas Exploration and Development Activity from December 31, 2010” for a summary of recent activities related to oil and natural gas operations.

ITEM 3.

LEGAL PROCEEDINGS

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

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCK-HOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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

	Quarterly Ranges

Quarter Ending	High Bid		Low Bid

03/31/10	$	255	$	236
06/30/10	$	266	$	228
09/30/10	$	320	$	226
12/31/10	$	301	$	270
03/31/11	$	410	$	301
06/30/11	$	405	$	330
09/30/11	$	341	$	275
12/31/11	$	300	$	240

There was limited public trading in the Company’s common stock in 2011 and 2010. There were 20 brokered trades appearing in the Company’s transfer ledger for both 2011and 2010.

At March 23, 2011, the Company had approximately 1,550 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 2011, and $10.00 per share in the second quarter and $30.00 per share in the fourth quarter of 2010. 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 2012 with the Board of Directors for its approval.

ISSUER PURCHASES OF EQUITY SECURITIES
Period	Total Number of Shares Purchased	Average Price Paid Per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs1	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs1
October 1 to October 31, 2011	0	$ 160.00	---	---
November 1 to November 30, 2011	7	$ 160.00	---	---
December 1 to December 31, 2011	2	$ 160.00	---	---
Total	9	$ 160.00	---	---

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.

ITEM 6.

SELECTED FINANCIAL DATA

Not applicable.

ITEM 7.

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

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

Forward-Looking Statements

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

Although management believes that the expectations reflected in such forward-looking statements are based on reasonable assumptions, a variety of factors could cause the Company’s actual results and experience to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance, development, and results of the Company’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 drilling 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 drilling is extremely imprecise at best.

The Company does not undertake any obligation to publicly revise forward-looking statements to reflect events or circumstances that arise after the 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 2012 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 leases using a straight line method; however, when leases are impaired or condemned, an appropriate adjustment to the provision is made at that time.

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

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

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

	·	Oil and natural gas sales revenue accrual is another critical accounting estimate. The Company does not operate any of its oil and natural gas properties. Obtaining timely production data on all wells from the operators is not feasible; therefore, the Company utilizes past production receipts and estimated sales price information to estimate its accrual of revenue on all wells each quarter. The oil and natural gas sales revenue accrual can be impacted by many variables, including rapid production decline rates, production curtailments by operators, and rapidly changing market prices for oil and natural gas. These variables could lead to an over or under accrual of oil and natural gas sales at the end of any particular quarter. Based on past history, 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 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 income tax accruals are adequate, differences may occur in the future depending on the resolution of pending and new tax matters.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The Company is affiliated by common management and ownership with Mesquite Minerals, Inc. (Mesquite), Mid-American Oil Company (Mid-American), 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 33% 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.

EQUITY INVESTMENTS

The Company had investments in two entities in 2010 and one entity in 2011, which it accounted for on the equity method. In using the equity method, the Company records the original investment in an entity as an asset and adjusts the asset balance for the Company’s share of any income or loss, as well as any additional contributions to or distributions from the entity. The entities included an Oklahoma limited partnership and an Oklahoma limited liability company identified below. The Company does not have actual or effective control of either of the entities. The management of these entities could, at any time, make decisions in their own best interests that could affect the Company’s net income or the value of the Company’s investments.

The entities in which the Company had investments in 2010 and 2011 are Broadway Sixty-Eight, Ltd. (33% limited partnership interest) and JAR Investments, LLC (25% ownership). In November, 2010, JAR Investments, LLC sold its remaining real estate investment and distributed the proceeds to all investees. In December 2010, after a final distribution of the remaining funds, JAR Investments, LLC was dissolved. Broadway Sixty-Eight, Ltd. has an indemnity agreement under which the Company is contingently liable. See Item 8, Note 7 to the accompanying financial statements for related disclosures and additional information regarding Broadway Sixty-Eight, Ltd.

LIQUIDITY AND CAPITAL RESOURCES

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

In 2011, 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 2011, net cash provided by operating activities was $7,888,371. Sales (including lease bonuses), net of production, exploration, and general and administrative costs, and income taxes paid were $7,876,833, which accounted for 99% of net cash provided by operations. The remaining components provided less than 1% of cash flow. In 2011, net cash provided by investing activities was $1,007,257. In 2011, dividend payments and treasury stock purchases totaled $1,685,853 and accounted for all of the cash applied to financing activities.

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

Available-for-sale securities decreased $6,483,973 (49%) to $6,654,838 in 2011 from $13,138,811 in 2010. The decrease was partly due to the need for cash to fund the 2011 capitalized property additions and dividend payments which combined were in excess of the cash provided by operations. The main reason for the decrease was the conversion of $5,000,000 cash from Treasury bill maturities into money market funds with better interest rates than the Treasury bills.

Refundable income taxes increased $534,293 (190%) to $816,125 in 2011 from $281,832 in 2010. This increase was due to excess 2011 estimated tax payments being greater than in 2010.

Receivables increased $103,203 (6%) to $1,903,862 in 2011 from $1,800,659 in 2010. The increase was due primarily to receivables for sales accruals that have increased by approximately $150,000 in 2011 from 2010. This increase was offset by a $50,000 decrease in a note receivable in 2011 from 2010. Additional information about the increase in sales for 2011 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.

Accounts payable increased $98,389 (55%) to $276,017 in 2011 from $177,628 in 2010. This increase was primarily due to the increased drilling activity at the end of 2011 compared to 2011 year-end activity.

Deferred income taxes and other accrued liabilities increased $35,812 (14%) to $292,166 in 2011 from $256,354 in 2010. This increase was primarily due to the increase in the current deferred tax accrual due to the increase in the oil and gas sales accrual in 2011.

The following is a discussion of material changes in cash flow by activity between the years ended December 31, 2011 and 2010. 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 2011 were $7,888,371, which, when compared to the $8,343,078 provided in 2010, represents a net decline of $453,707 or 5%. The decrease was mostly due to a decline in lease bonuses and coal royalties of $1,045,102 and an increase in production costs of $77,711. Those decreases in cash flows were partially offset by an increase in oil and gas sales cash flows of $397,234; a decline in exploration costs of $180,110; and a decrease in income taxes paid of $137,425. Additional discussion of the more significant items follows.

Discussion of Selected Material Line Items Resulting in an Increase in Cash Flows. The $397,234 (3%) increase in cash received from oil and gas sales to $12,112,905 in 2011 from $11,715,671 in 2010 was the result of an increase in the average oil price and the volume of oil sales, offset by declines in the gas sales prices and volume. See “Results of Operations” below for a price/volume analysis and the related discussion of oil and gas sales.

Cash paid for production costs increased $77,711 (4%) to $2,014,775 in 2011 from $1,937,064 in 2010. This increase was mostly due to an increase of $63,174 in production taxes in 2011 versus 2010.

Cash flow increased due to a decrease in cash paid for exploration expenses of $180,110 (37%) to $305,762 in 2011 from $485,872 in 2010. All of the decrease was due to decreased geological and geophysical expense in 2011 versus 2010.

Cash flow increased due to a decrease in income taxes paid of $137,425 (10%) to $1,173,329 in 2011 from $1,310,754 in 2010 due to lower estimated tax payments in 2011.

Discussion of Selected Material Line Items Resulting in a Decrease in Cash Flows. Cash received for lease bonuses and coal royalties decreased $1,045,102 (60%) to $688,287 in 2011 from $1,733,389 in 2010. All of the decrease is due to a decrease in cash received for lease bonuses of $1,063,703 in 2011 versus 2010. The increase in production taxes was due to the increase in sales in 2011 versus 2010.

Investing Activities

Net cash from investing activities increased $1,377,209 to $1,007,257 of cash provided in 2011 from $369,952 of cash applied in 2010. In 2011, net cash flows from available-for-sale securities were $6,483,973 compared to net cash flows of $2,931,664 in 2010. This $3,552,309 increase in net cash flow was used to fund the increased application of cash for property acquisitions discussed below. Cash flows related to property acquisitions resulted in an increase in cash applications to investing activities in 2011 versus 2010. Cash applied to property acquisitions increased $3,254,696 (92%) to $6,789,339 in 2011 from $3,534,643 in 2010 due primarily to increased exploration and development drilling activity. See the “Update of Oil and Gas Exploration and Development Activity from December 31, 2010” under the “Results of Operations” heading below for more information regarding expenditures related to this drilling activity. The remaining significant increase in cash provided by investing activities pertains to the proceeds from property disposals. This line item increased $1,194,071 to $1,259,623 in 2011 from $65,552 in 2010. This increase was the result of sales of several Kansas and Oklahoma nonproducing leaseholds in 2011 with no similar sales in 2010.

Financing Activities

Cash applied to financing activities decreased $4,397,447 (72%) to $1,685,853 in 2011 from $6,083,300 in 2010. Cash applied to financing activities consist of cash dividends on common stock and cash used for the purchase of treasury stock. In 2011, cash dividends paid on common stock amounted to $1,644,413 as compared to $6,017,060 in 2010. Dividends of $10.00 per share were issued for 2011 and $40.00 per share for 2010.

Forward-Looking Summary

The Company’s latest estimate of business to be done in 2012 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 Income in Item 8 of this Form 10-K, in 2011 the Company had net income of $5,279,039 as compared to a net income of $5,250,659 in 2010. Net income per share, basic and diluted, was $32.77 in 2011, an increase of $.26 per share from $32.51 in 2010. Material line item changes in the Statements of Income will be discussed in the following paragraphs.

Operating Revenues

Operating revenues decreased $866,376 (6%) to $12,962,965 in 2011 from $13,829,341 in 2010. Oil and gas sales increased $189,572 (2%) to $12,251,319 in 2011 from $12,061,747 in 2010. Lease bonuses and other revenues decreased $1,055,948 to $711,646 in 2011 from $1,767,594 in 2010. This decrease was the result of a decrease in lease bonuses of $1,063,702 from leases in East Texas and Oklahoma. In addition, coal royalties from North Dakota leases increased $7,754 (3%) to $274,808 in 2011 from $267,054 in 2010. The Company does not anticipate that coal royalties will have a significant impact on its future results of operations. The increase in oil and gas sales is discussed in the following paragraphs.

The $189,572 increase in oil and gas sales was the net result of a $1,453,537 decrease in gas sales, offset by a $1,562,713 increase in oil sales and an $80,396 increase in miscellaneous oil and gas product sales. The following price and volume analysis is presented to explain the changes in oil and gas sales from 2010 to 2011. Miscellaneous oil and gas product sales of $344,897 in 2011 and $264,501 in 2010 are not included in the analysis.

			Variance
Production	2011		Price			Volume			2010
Gas –
MCF (000 omitted)		1,107					(136	)		1,243
$ (000 omitted)	$	4,444	$	(808	)	$	( 646	)	$	5,898
Unit Price	$	4.02	$	(0.72	)				$	4.74
Oil –
Bbls (000 omitted)		85					3			82
$ (000 omitted)	$	7,462	$	1,385		$	178		$	5,899
Unit Price	$	88.17	$	16.36					$	71.81

The $1,453,537 (25%) decrease in natural gas sales to $4,444,479 in 2011 from $5,898,016 in 2010 was the result of a decline 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 $.72 per MCF to $4.02 in 2011 from $4.74 per MCF in 2010, resulting in a negative gas price variance of ($807,762). A negative volume variance of ($645,775) was the result of a decrease in natural gas volumes sold of 136,239 MCF to 1,106,899 MCF in 2011 from 1,243,138 MCF in 2010. The decrease in the volume of gas production was the net result of new 2011 production of about 50,000 MCF, offset by a decline of about 186,000 MCF in production from previous wells. As disclosed in Supplemental Schedule 1 of the Unaudited Supplemental Financial Information included in Item 8 below, working interests in natural gas extensions and discoveries were adequate to replace working interest reserves produced in 2010 and 2011.

The gas production for 2010 and 2011 includes production from several royalty interest properties drilled by various operators in Robertson County, Texas. These properties accounted for approximately 476,000 MCF and $2,450,000 of the 2010 gas sales and approximately 492,000 MCF and $1,830,000 of the 2011 gas sales. These properties accounted for about 41% of the Company’s 2011 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 $1,562,713 (26%) increase in crude oil sales to $7,461,943 in 2011 from $5,899,230 in 2010 was the result of an increase in both the average price per barrel (Bbl) and oil sales volumes. The average price received per Bbl of oil increased $16.36 to $88.17 in 2011 from $71.81 in 2010, resulting in a positive oil price variance of $1,385,045. An increase in oil sales volumes of 2,474 Bbls to 84,629 Bbls in 2011 from 82,155 Bbls in 2010 resulted in a positive volume variance of $177,668. The increase in the oil volume production was the net result of new 2011 production of about 9,800 Bbls, offset by a 7,300 Bbl decline in production from older producing properties. Of the new 2011 production, approximately 3,800 Bbls (39%) was from Woods County, Oklahoma, about 4,900 Bbls (50%) was from new working interest wells in Kansas and Oklahoma (in counties other than Woods), and about 1200 Bbls (12%) was from new royalty interest wells in Texas. As disclosed in Supplemental Schedule 1 of the Unaudited Supplemental Financial Information included below in Item 8, working interests in oil extensions and discoveries were adequate to replace working interest reserves produced in 2011 and 2010.

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

Operating Costs and Expenses

Operating costs and expenses decreased $32,808 to $6,961,852 in 2011 from $6,994,660 in 2010, primarily due to a decrease in exploration costs, offset by an increase in production and depreciation, depletion and amortization expense. The material components of operating costs and expenses are discussed below.

Production Costs. Production costs increased $96,078 (5%) to $2,038,933 in 2011 from $1,942,855 in 2010. The increase was the result of an $63,173 (13%) increase in gross production tax (net of production tax refunds) to $176,590 in 2011 from $468,413 in 2010, plus an increase in lease operating and handling expense of $32,904 (2%) to $1,507,347 in 2011 from $1,474,443 in 2010. Most of the increase in lease operating and handling expense was due to an increase in lease operating expense of $125,069 (2%) to $1,128,495 in 2011 from $1,003,426 in 2010 offset by a decrease in handling expense of $92,165 from $471,017 in 2010 to $378,852 in 2011. 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 Texas properties and are due to a 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 $6,658,584 in 2011 and $3,756,837 in 2010. See Item 8, Note 8 to the accompanying financial statements for additional information regarding a breakdown of these costs. Exploration costs charged to operations were $324,908 in 2011 and $556,636 in 2010, inclusive of unsuccessful exploratory well costs of $319,429 in 2011 and $363,536 in 2010 and geological and geophysical costs of $5,479 in 2011 and $193,100 in 2010.

Update of Oil and Gas Exploration and Development Activity from December 31, 2010. For the year ended December 31, 2011, the Company participated in the drilling of 17 gross exploratory and 27 gross development working interest wells with working interests ranging from a high of 18% to a low of .022%. Of the 17 exploratory wells, 9 were completed as producing wells, 4 as dry holes and 4 were in progress. Of the 27 development wells, 17 were completed as producing wells and 10 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 2, 2012, updating both exploration and development activity from December 31, 2010, for the period ended December 31, 2011.

The Company participated with its 18% working interest in the completion of three development wells on a Barber County, Kansas prospect (these wells were drilled in 2010). Two of the wells were completed as commercial oil and gas producers and the third as a marginal oil and gas producer. The Company also participated in the drilling of six additional development wells on the prospect. Three of these wells were completed as oil and gas producers, two commercial and one marginal. Completion attempts are in progress on the other three wells. A salt water disposal well and two additional development wells will be drilled starting in March 2012. Capitalized costs for the period were $386,431, including $157,057 in prepaid drilling costs.

The Company participated in the drilling of six step-out wells on a Woods County, Oklahoma prospect (12%, 12%, 14%, 14%, 15% and 15% working interests). All six wells were completed as commercial oil and gas producers. Two additional step-out wells (12% and 8% interests) will be drilled starting in March 2012. Capitalized costs for the period were $542,856, including $32,204 in prepaid drilling costs.

The Company participated in the completion of two step-out wells (10.5% and 10.3% working interests) on a Woods County, Oklahoma prospect (these wells were drilled in 2010). Both wells were completed as commercial oil and gas producers. The Company also participated in the drilling of two additional step-out wells (7.4% and 6.5% interests). Both of these wells were completed as a commercial oil and gas producers. The Company is participating with a 4.6% interest in another step-out well that is currently drilling. Total capitalized costs for the period were $184,692, including $2,659 in prepaid drilling costs.

The Company participated with its 16% working interest in the drilling of four step-out wells and six exploratory wells on a Hodgeman County, Kansas prospect. Four of these wells were completed as commercial oil producers, one as a marginal oil producer and four as dry holes. A completion attempt is in progress on one well. Capitalized costs for the period were $398,077, including $188,900 in prepaid drilling costs. Dry hole costs were $83,336 for the period.

The Company participated with its 16% working interest in the drilling of a step-out well on a Ford County, Kansas prospect. Completion attempts have been unsuccessful and the well is currently being evaluated. Capitalized costs for the period were $56,491.

The Company participated with a 9.4% working interest in the drilling of an exploratory well on a Grady County, Oklahoma prospect. A completion attempt is in progress. Capitalized costs for the period were $175,882.

The Company participated in the drilling of two additional horizontal wells and the drilling of additional laterals from two existing horizontal injection wells in a Harding County, South Dakota waterflood unit in which it has an 8.3% working interest. Both new wells were completed as commercial oil producers. One has since been converted to a water injection well. An existing horizontal oil well was also converted. Total capitalized costs for the unit for the period were $704,356.

In May 2011, the Company purchased a 16% interest in 866.67 net acres of leasehold on a Beaver County, Oklahoma prospect for $52,291. The Company participated with a 13% working interest in the drilling of an exploratory well. Completion attempts were unsuccessful and the well will be plugged. Dryhole costs for the period were $209,620.

The Company participated with fee mineral interests in the drilling of two horizontal development wells in Faulkner County, Arkansas. The Company has 3.4% and 2.2% interests in these wells which were completed as commercial gas producers. Capitalized costs for the period were $251,443.

The Company participated with its 16% working interest in the drilling of a step-out well on a Woods County, Oklahoma prospect. The well was completed as a commercial oil and gas producer. Capitalized costs for the period were $112,436.

The Company participated with its 10.5% working interest in the drilling of an exploratory well on a Custer County, Oklahoma prospect. The well was completed as a marginal gas and condensate producer. Capitalized costs for the period were $227,676.

The Company participated with its 18% working interest in the drilling of two exploratory wells on two Rice County, Kansas prospects. Both wells were completed as dry holes. Dry hole costs for the period were $55,305.

In February 2011, the Company purchased 18% interests in two prospects in Ness and Hodgeman Counties, Kansas for $17,798. The Company participated in the drilling of an exploratory well on each prospect. Both wells were completed as oil producers, one commercial and one marginal. An additional well will be drilled on each prospect starting in March 2012. Capitalized costs for the period were $196,039.

In March 2011, the Company purchased a 10.5% interest in 3,197 net acres of leasehold on a Garfield County, Oklahoma prospect for $117,474. The Company participated in the drilling of two exploratory horizontal wells. Both wells were completed as commercial oil and gas producers. The Company is participating in a salt water disposal well that is currently drilling. An additional horizontal well will be drilled starting in March or April 2012. Capitalized costs for the period were $618,424, including prepaid drilling costs of $24,783.

In May 2011, the Company purchased a 7% interest in 640 net acres of leasehold on a Custer County, Oklahoma prospect for $22,400. The Company participated in the drilling of an exploratory horizontal well that was completed as a commercial gas and condensate producer. Capitalized costs for the period were $688,702.

In May 2011, the Company purchased a 7% interest in 2,529 net acres of leasehold on a Grayson County, Texas prospect for $132,782. The Company participated in the drilling of an exploratory horizontal well. The well has been completed and is currently being tested. Capitalized costs for the period were $540,964, including prepaid drilling costs of $143,016.

The Company participated with an 8% working interest in the drilling of a horizontal development well on a Woods County, Oklahoma prospect. The well was completed as a commercial oil and gas producer. Capitalized costs for the period were $294,231.

The Company participated with a 17.5% working interest in the drilling of an exploratory well on a McClain County, Oklahoma prospect. The well was completed as a commercial oil producer. Capitalized costs for the period were $172,323.

The Company participated with its 18% working interest in the drilling of a horizontal development well on a Comanche County, Kansas prospect. A completion attempt is in progress. Capitalized costs for the period were $360,000, including prepaid drilling costs of $152,708.

The Company is participating with a fee mineral interest in the drilling of an exploratory horizontal well in Beaver County, Oklahoma. The Company has a 10.2% interest in the well.

The Company will participate with a 6.2% working interest in the drilling of an exploratory horizontal well in 2012 on a Dewey County, Oklahoma prospect.

Depreciation, Depletion, Amortization and Valuation Provisions (DD&A). Major DD&A components are the provision for impairment of undeveloped leaseholds, provision for impairment of long-lived assets, depletion of producing leaseholds and depreciation of tangible and intangible lease and well costs. Undeveloped leaseholds are amortized over the life of the leasehold (most are 3 years) using a straight line method, except when the leasehold is impaired or condemned by drilling and/or geological interpretation of seismic data; if so, an adjustment to the provision is made at the time of impairment. The provision for impairment of undeveloped leaseholds was $409,045 in 2011 and $313,801 in 2010. Of the 2011 provision, $394,050 was due to the annual amortization of undeveloped leaseholds and $14,995 was due to specific leasehold impairments. The 2010 provision was due to the annual amortization of undeveloped leaseholds of $202,373 and specific leasehold impairments of $111,427.

As discussed in Item 8, Note 10 to the accompanying financial statements, accounting principles require the recognition of an impairment loss on long-lived assets used in operations when indicators of impairment are present. Impairment evaluation is a two-step process. The first step is to measure when the undiscounted cash flows estimated to be generated by those assets, determined on a well basis, is less than the assets’ carrying amounts. Those assets meeting the first criterion are adjusted to estimated fair value. Evaluation for impairment was performed in both 2011 and 2010. The 2011 impairment loss was $828,071 and the 2010 impairment loss was $703,645.

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 $1,909,307 in 2011 and $2,051,253 in 2010. The provision also includes $82,852 for 2011 and $72,212 for 2010 for the amortization of the Asset Retirement Costs. See Item 8, Note 2 to the accompanying financial statements for additional information regarding the Asset Retirement Obligation.

Equity Income in Investees. The following is an analysis of equity income in investees by entity for 2011 and 2010. See Equity Investments discussion above and Item 8, Note 7 to the accompanying financial statements for more information about these investments.

	Net Income				2011 Income
	2011		2010		Over/(Under) 2010
Broadway Sixty-Eight, Ltd.	$	35,884	$	6,832	$	29,052
JAR Investment, LLC		---		122,312		(122,312	)
Total	$	35,884	$	129,144	$	(93,260	)

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 2011 and 2010. Other income, net increased $905,181 (592%) to $1,057,904 in 2011 from $152,723 in 2010. The line items responsible for this increase are described below.

Gains on sales or disposals of assets increased $1,046,889 to $1,091,224 in 2011 from gains of $44,335 in 2010. This was due almost entirely from sales of the Company’s interests in certain non-producing leaseholds in Oklahoma and Kansas.

Net realized and unrealized gains (losses) on trading securities decreased $80,897 to a net loss of ($18,572) in 2011 from a net gain of $62,325 in 2010. 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 2011, the Company had realized gains of $73,334 and unrealized losses of $(91,906). In 2010, the Company had realized gains of $19,100 and unrealized gains of $43,225.

Interest income decreased $13,487 (37%) to $22,774 in 2011 from $36,261 in 2010. This decrease was the result of a decrease in both the average rate of return on and average balance of cash equivalents and average balance of available-for-sale securities from which most of interest income is derived. The average rate of return decreased 0.07% to 0.16% in 2011 from 0.23% in 2010. The average balance outstanding decreased $1,814,253 to $13,923,528 in 2011 from $15,737,781 in 2010.

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 2011, the Company had an estimated provision for income taxes of $1,815,862 as the result of a current tax provision of $639,036 and a deferred tax provision of $1,176,826. In 2010, the Company had an estimated provision for income taxes of $1,865,889 as the result of a current tax provision of $1,343,230 and a deferred tax provision of $522,659.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Not applicable.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Financial Statements

	Page
Report of Independent Registered Public Accounting Firm
HoganTaylor LLP	17
Balance Sheets – December 31, 2011 and 2010	18
Statements of Income – Years Ended December 31, 2011 and 2010	20
Statements of Stockholders’ Equity – Years Ended December 31, 2011 and 2010	21
Statements of Cash Flows – Years Ended December 31, 2011 and 2010	22
Notes to Financial Statements	24
Unaudited Supplemental Financial Information	31

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

The Reserve Petroleum Company

We have audited the accompanying balance sheets of The Reserve Petroleum Company as of December 31, 2011 and 2010, and the related statements of income, stockholders’ equity and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of The Reserve Petroleum Company as of December 31, 2011 and 2010, and the results of its operations and its cash flows for the years then ended, 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, 2011, 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 28, 2012

THE RESERVE PETROLEUM COMPANY
BALANCE SHEETS
ASSETS
	December 31,
	2011		2010
Current Assets:
Cash and Cash Equivalents (Note 2)	$	10,150,742	$	2,940,967
Available-for-Sale Securities (Notes 2 & 5)		6,654,838		13,138,811
Trading Securities (Notes 2 & 5)		398,964		414,124
Refundable Income Taxes		816,125		281,832
Receivables (Notes 2 & 7)		1,903,862		1,800,659
		19,924,531		18,576,393

Investments:
Equity Investment (Notes 2 & 7)		521,852		485,968
Other		151,839		151,839
		673,691		637,807
Property, Plant and Equipment (Notes 2, 8 & 10):
Oil and Gas Properties, at Cost,
Based on the Successful Efforts Method of Accounting –
Unproved Properties		1,179,882		1,222,333
Proved Properties		32,441,403		26,323,648
		33,621,285		27,545,981
Less – Accumulated Depreciation, Depletion, Amortization and
Valuation Allowance		21,177,541		18,709,551
		12,443,744		8,836,430
Other Property and Equipment, at Cost		417,526		404,194
Less – Accumulated Depreciation and Amortization		227,895		225,708
		189,631		178,486
Total Property, Plant and Equipment		12,633,375		9,014,916
Other Assets		361,802		355,959
Total Assets	$	33,593,399	$	28,585,075

See Accompanying Notes

THE RESERVE PETROLEUM COMPANY
BALANCE SHEETS
LIABILITIES AND STOCKHOLDERS’ EQUITY

	December 31,
	2011		2010
Current Liabilities:
Accounts Payable (Note 2)	$	276,017	$	177,628
Other Current Liabilities – Deferred Income Taxes and Other		292,166		256,354
		568,183		433,982

Long-Term Liabilities:
Asset Retirement Obligation (Note 2)		990,074		848,631
Dividends Payable (Note 3)		1,419,884		1,453,070
Deferred Tax Liability (Note 6)		2,726,978		1,587,434
		5,136,936		3,889,135
Total Liabilities		5,705,119		4,323,117

Commitments and Contingencies (Notes 2 & 7)

Stockholders’ Equity (Notes 3 & 4):
Common Stock		92,368		92,368
Additional Paid-in Capital		65,000		65,000
Retained Earnings		28,563,474		24,895,712
		28,720,842		25,053,080

Less – Treasury Stock, at Cost		832,562		791,122
Total Stockholders’ Equity		27,888,280		24,261,958
Total Liabilities and Stockholders’ Equity	$	33,593,399	$	28,585,075

See Accompanying Notes

THE RESERVE PETROLEUM COMPANY
STATEMENTS OF INCOME



	Year Ended December 31,
	2011		2010

Operating Revenues:
Oil and Gas Sales	$	12,251,319	$	12,061,747
Lease Bonuses and Other		711,646		1,767,594
		12,962,965		13,829,341

Operating Costs and Expenses:
Production		2,038,933		1,942,855
Exploration		324,908		556,636
Depreciation, Depletion, Amortization and Valuation Provisions		3,179,534		3,084,876
General, Administrative and Other		1,418,477		1,410,293
		6,961,852		6,994,660
Income from Operations		6,001,113		6,834,681
Equity Income in Investees (Note 7)		35,884		129,144
Other Income, Net (Note 11)		1,057,904		152,723
Income Before Income Taxes		7,094,901		7,116,548
Provision for Income Taxes (Notes 2 & 6)		1,815,862		1,865,889
Net Income	$	5,279,039	$	5,250,659

Per Share Data (Note 2):
Net Income, Basic and Diluted	$	32.77	$	32.51
Cash Dividends	$	10.00	$	40.00
Weighted Average Shares Outstanding, Basic and Diluted		161,117		161,493

See Accompanying Notes

THE RESERVE PETROLEUM COMPANY
STATEMENTS OF STOCKHOLDERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010



			Additional
	Common		Paid-in		Retained			Treasury
	Stock		Capital		Earnings			Stock

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

Net Income		---		---		5,250,659			---
Dividends Declared		---		---		(6,455,035	)		---
Purchase of Treasury Stock		---		---		---			(66,240	)

Balance at December 31, 2010		92,368		65,000		24,895,712			(791,122	)

Net Income		---		---		5,279,039			---
Dividends Declared		---		---		(1,611,277	)		---
Purchase of Treasury Stock		---		---		---			(41,440	)

Balance at December 31, 2011	$	92,368	$	65,000	$	28,563,474		$	(832,562	)

See Accompanying Notes

THE RESERVE PETROLEUM COMPANY
STATEMENTS OF CASH FLOWS



	Year Ended December 31,
	2011			2010

Cash Flows from Operating Activities:
Cash Received –
Oil and Gas Sales	$	12,112,905		$	11,715,671
Lease Bonuses and Coal Royalties		688,287			1,733,389
Sale of Trading Securities		886,263			873,022
Interest Received		29,462			36,253
Agricultural Rentals and Other		5,781			5,323
Dividends Received on Trading Securities		3,878			1,506
Cash Paid –
Production Costs		(2,014,775	)		(1,937,064	)
Exploration Costs		(305,762	)		(485,872	)
General Suppliers, Employees and Taxes, Other than Income Taxes		(1,430,493	)		(1,410,083	)
Interest Paid		(3,854	)		(3,863	)
Purchase of Trading Securities		(889,675	)		(874,450	)
Income Taxes Paid, Net		(1,173,329	)		(1,310,754	)
Farm Expense		(20,317	)		---
Net Cash Provided by Operating Activities		7,888,371			8,343,078

Cash Flows Applied to Investing Activities:
Maturity of Available-for-Sale Securities		26,032,687			31,896,399
Purchase of Available-for-Sale Securities		(19,548,714	)		(28,964,735	)
Proceeds from Disposal of Property, Plant and Equipment		1,259,623			65,552
Purchase of Property, Plant and Equipment		(6,789,339	)		(3,534,643	)
Cash Distributions from Equity and Other Investments		3,000			142,475
Repayments from Equity Investees		50,000			25,000
Net Cash Provided by/(Applied to) Investing Activities		1,007,257			(369,952	)

See Accompanying Notes

THE RESERVE PETROLEUM COMPANY
STATEMENTS OF CASH FLOWS



	Year Ended December 31,
	2011			2010

Cash Flows Applied to Financing Activities:
Dividends Paid to Stockholders	$	( 1,644,413	)	$	( 6,017,060	)
Purchase of Treasury Stock		(41,440	)		(66,240	)
Total Cash Applied to Financing Activities		(1,685,853	)		(6,083,300	)

Net Change in Cash and Cash Equivalents		7,209,775			1,889,826

Cash and Cash Equivalents at Beginning of Year		2,940,967			1,051,141
Cash and Cash Equivalents at End of Year	$	10,150,742		$	2,940,967


Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	$	5,279,039		$	5,250,659
Net Income Increased (Decreased) by Net Change in –
Unrealized Holding Gains on Trading Securities		91,906			(43,225	)
Accounts Receivable		(159,942	)		(379,211	)
Interest and Dividends Receivable		6,688			(8	)
Refundable Income Taxes		---			32,476
Accounts Payable		36,768			(113,405	)
Trading Securities		(76,745	)		(20,527	)
Other Assets		(5,842	)		191,734
Deferred Taxes		642,533			522,659
Other Liabilities		24,540			21,105
Income from Equity and Other Investments		(38,884	)		(163,674	)
Disposition of Property, Plant and Equipment		(1,091,224	)		(40,381	)
Depreciation, Depletion, Amortization and Valuation Provisions		3,179,534			3,084,876
Net Cash Provided by Operating Activities	$	7,888,371		$	8,343,078

See Accompanying Notes

THE RESERVE PETROLEUM COMPANY

NOTES TO FINANCIAL STATEMENTS

Note 1 – NATURE OF OPERATIONS

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

Note 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash and Cash Equivalents

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

Investments

Marketable Securities:

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

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

Unrealized gains and losses on available-for-sale securities, which consist 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 non-marketable investment in a partnership on the equity basis. See Note 7 for additional information.

Receivables and Revenue Recognition

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

Property and Equipment

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

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

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

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

Office furniture and fixtures	5 to10 years
Automotive equipment	5 to 8 years

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

Income Taxes

The Company utilizes 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 returns for 2008, 2009 and 2010 are subject to examination.

Earnings Per Share

Accounting guidance for Earnings Per Share (EPS) establishes the methodology of calculating basic earnings per share and diluted earnings per share. The calculations of basic earnings per share and diluted earnings per share differ in that instruments convertible to common stock (such as stock options, warrants, and convertible preferred stock) are added to weighted average shares outstanding when computing diluted earnings per share. For 2011 and 2010, the Company had no dilutive shares outstanding; therefore, basic and diluted earnings per share are the same.

Concentrations of Credit Risk and Major Customers

The Company’s receivables relate primarily to sales of oil and natural gas to purchasers with operations in Texas, Oklahoma, Kansas, and South Dakota. The Company had two purchasers in 2011 and 2010 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 exceed our estimated remaining recoverable reserves (over produced). No receivables are recorded for those wells where the Company has taken less than our ownership share of gas production (under produced).

Guarantees

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

Asset Retirement Obligation

The Company records the fair value of its estimated liability to retire its oil and natural gas producing properties in the period in which it is incurred (typically the date of first sales). The estimated liability is calculated by obtaining current estimated plugging costs from the well operators and inflating it over the life of the property. Current year inflation rate used is 4.06%. When the liability is first recorded, a corresponding increase in the carrying amount of the related long-lived asset is also recorded. Subsequently, the asset is amortized to expense over the life of the property and the liability is increased annually for the change in its present value which is currently 3.25%.

The following table summarizes the asset retirement obligation for 2011 and 2010:

	2011			2010
Beginning balance at January 1	$	848,631		$	699,392
Liabilities incurred		116,487			122,104
Liabilities settled (wells sold or plugged)		(4,569	)		(5,070	)
Accretion expense		26,010			27,693
Revision to estimate		3,515			4,512
Ending balance at December 31	$	990,074		$	848,631

New Accounting Pronouncements

In June 2011, the FASB issued Accounting Standards Update 2011-05, Presentation of Comprehensive Income. This update provides the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The Company does not believe that this will materially impact the presentation of its financial statements.

In May 2011, the FASB issued Accounting Standards Update 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. This update does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. This update may require certain additional disclosures related to fair value measurements. The Company does not expect the adoption of this update will materially impact its financial statement disclosures.

Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the financial statements upon adoption.

Reclassifications

Certain amounts in the 2010 financial statements have been reclassified to conform to the 2011 presentation. The amounts were not material to the financial statements and had no effect on previously reported net income.

Note 3 – DIVIDENDS PAYABLE

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

Note 4 – COMMON STOCK

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

			Shares of
	Shares		Treasury		Shares
	Issued		Stock		Outstanding
January 1, 2010, $.50 par value stock,
400,000 shares authorized		184,736		23,042		161,694
Purchase of stock		---		414		(414	)
December 31, 2010, $.50 par value stock,
400,000 shares authorized		184,736		23,456		161,280
Purchase of stock		---		259		(259	)
December 31, 2011, $.50 par value stock,
400,000 shares authorized		184,736		23,715		161,021

Note 5 – MARKETABLE SECURITIES

At December 31, 2011, available-for-sale securities, consisting entirely of U.S. government securities, are due within one year or less by contractual maturity.

For trading securities in 2011, the Company recorded realized gains of $73,334 and unrealized losses of $91,906. In 2010, the Company recorded realized gains of $19,100 and unrealized gains of $43,225.

Note 6 – INCOME TAXES

Components of deferred taxes are as follows:

	December 31,
	2011			2010
Assets
Net Leasehold Impairment Reserves	$	280,554		$	239,115
Gas Balance Receivable		52,379			52,379
Long-Lived Asset Impairment		940,713			882,857
Other		173,286			162,845
Total Assets		1,446,932			1,337,196
Liabilities
Receivables		278,839			211,138
Intangible Drilling Costs		3,308,603			2,304,642
Depletion, Depreciation and Other		847,990			633,090
Total Liabilities		4,435,432			3,148,870
Net Deferred Tax Liability	$	(2,988,500	)	$	(1,811,674	)

The increase in the deferred tax liability for 2011 reflected in the above table, as well as the increase in the deferred tax provision in the table that follows, are primarily the result of the Company’s increased current year drilling activity. The increased drilling activity resulted in an increase in the intangible drilling costs and bonus depreciation on the lease and well equipment for successful wells. This also resulted in a decrease in the current tax provision.

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

	Year Ended December 31,
	2011		2010
Current Tax Provision:
Federal	$	620,591	$	1,312,235
State		18,445		30,995
	$	639,036	$	1,343,230
Deferred Provision		1,176,826		522,659
Total Provision	$	1,815,862	$	1,865,889

The total provision for income tax expressed as a percentage of income before income tax was 26% for 2011 and 2010. These amounts differ from the amounts computed by applying the statutory U.S. federal income tax rate of 34% for 2011 and 2010 to income before income tax as summarized in the following reconciliation:

	Year Ended December 31,
	2011			2010

Computed Federal Tax Provision	$	2,412,266		$	2,419,626

Increase (Decrease) in Tax From:
Allowable Depletion in Excess of Basis		(580,488	)		(553,127	)
Dividend Received Deduction		(359	)		(350	)
State Income Tax Provision		18,445			30,995
Other		(34,002	)		(31,255	)
Provision for Income Tax	$	1,815,862		$	1,865,889
Effective Tax Rate		26%			26%

Note 7 – EQUITY INVESTMENT

The Company’s Equity Investment consists of 33% ownership in Broadway Sixty-Eight, Ltd. (the “Partnership”), an Oklahoma limited partnership that 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 indemnify the general partner for any losses suffered from operating the Partnership. The indemnity agreement provides no limitation to the maximum potential future reimbursements. To date, no payments have been made with respect to this agreement.

The Company leases its corporate office from the Partnership. The operating lease, under which the space was rented, expired February 28, 1994, and the space is currently rented on a year-to-year basis under the terms of the expired lease. Rent expense for lease of the corporate office from the Partnership was approximately $29,500 for 2011 and 2010.

Included with Receivables at December 31, 2010 was a Note receivable in the amount of $50,000 from the Partnership bearing 3.5% interest and due June 30, 2011. On June 30, 2011, the interest due on this note and $16,750 of the principal were received along with a new Note receivable in the amount of $33,250 from the Partnership bearing 3.5% interest and due December 31, 2011. The principal and interest due on this note were received on December 16, 2011 and the note was not renewed. This related party transaction was connected to the construction of a new office building.

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,
	2011		2010
Acquisition of Properties:
Unproved	$	476,658	$	156,799
Proved	$	---	$	13,440
Exploration Costs	$	2,953,503	$	1,247,683
Development Costs	$	3,705,081	$	2,509,154
Asset Retirement Obligation	$	120,002	$	121,546

Note 9 – FAIR VALUE MEASUREMENTS

Inputs used to measure fair value are organized into a fair value hierarchy based on how observable the inputs are. Level 1 inputs consist of quoted prices in active markets for identical assets. Level 2 inputs are inputs, other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs.

Recurring Fair Value Measurements

Certain of the Company’s assets are reported at fair value in the accompanying balance sheets on a recurring basis. The Company determined the fair value of the available-for-sale securities using quoted market prices for securities with similar maturity dates and interest rates. At December 31, 2011 and 2010, the Company’s assets reported at fair value on a recurring basis are summarized as follows:

	2011
	Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
Financial Assets:
Available-for-Sale Securities –
U.S. Treasury Bills Maturing in 2012	$	---	$	6,654,838	$	---
Trading Securities:
Domestic Equities	$	275,516	$	---	$	---
International Equities	$	95,223	$	---	$	---
Others	$	28,225	$	---	$	---


		2010
	Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
Financial Assets:
Available-for-Sale Securities –
U.S. Treasury Bills Maturing in 2011	$	---	$	13,138,811	$	---
Trading Securities:
Domestic Equities	$	256,030	$	---	$	---
International Equities	$	25,320	$	---	$	---
Others	$	132,774	$	---	$	---

Non-recurring Fair Value Measurements

The Company’s asset retirement obligation incurred annually represents non-recurring fair value liabilities. The fair value of the non-financial liabilities incurred was $116,487 in 2011 and $122,104 in 2010 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.

The impairment losses of $828,071 for 2011 and $703,645 for 2010 also represent non-recurring fair value expenses. See Note 10 below for the inputs that are used for calculating these expenses.

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, trade receivables, marketable securities, trade payables, and dividends payable. As of December 31, 2011 and 2010, 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 $828,071 for 2011 and $703,645 for 2010 are included in the Statements of Income in the line item Depreciation, Depletion, Amortization and Valuation Provisions. The impairments for 2011 and 2010 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 2011 and 2010:

	2011			2010
Net Realized and Unrealized Gain (Loss) on
Trading Securities	$	( 18,572	)	$	62,325
Gains on Asset Sales		1,091,224			44,335
Interest Income		22,774			36,261
Settlements of Class Action Lawsuits		181			107
Agricultural Rental Income		5,600			5,600
Dividend and Other Income		6,878			36,036
Interest and Other Expenses		(50,181	)		(31,941	)
Other Income, Net	$	1,057,904		$	152,723

Note 12 – CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Mesquite, Mid-American and LLTD share facilities and employees including executive officers with the Company. The Company has been reimbursed for services, facilities, and miscellaneous business expenses incurred in 2011 in the amount of $155,048 each by Mesquite, Mid-American and LLTD. Reimbursements in 2010 were $158,537 each by Mesquite, Mid-American and LLTD. Included in the 2011 amounts, Mesquite, Mid-American and LLTD each paid $113,873 for their share of salaries. In 2010, the share of salaries paid by Mesquite, Mid-American and LLTD was $110,533 each.

UNAUDITED SUPPLEMENTAL FINANCIAL INFORMATION

SUPPLEMENTAL SCHEDULE 1



THE RESERVE PETROLEUM COMPANY
WORKING INTERESTS RESERVE QUANTITY INFORMATION
(Unaudited)


	Year Ended December 31,
	2011			2010
Oil and Natural Gas Liquids (Bbls)
Proved Developed and Undeveloped Reserves:
Beginning of Year		303,779			260,164
Revisions of Previous Estimates		41,727			34,343
Extensions and Discoveries		91,248			76,270
Purchase of Reserves		---			76
Production		(66,432	)		(67,074	)
End of Year		370,322			303,779
Proved Developed Reserves:
Beginning of Year		303,779			260,164
End of Year		370,322			303,779

Gas (MCF)
Proved Developed and Undeveloped Reserves:
Beginning of Year		2,052,075			1,810,540
Revisions of Previous Estimates		501,889			91,654
Extensions and Discoveries		504,193			718,547
Purchase of Reserves		---			4,402
Production		(469,183	)		(573,068	)
End of Year		2,588,974			2,052,075
Proved Developed Reserves:
Beginning of Year		2,052,075			1,810,540
End of Year		2,588,974			2,052,075



See notes on next page.

SUPPLEMENTAL SCHEDULE 1

THE RESERVE PETROLEUM COMPANY

WORKING INTERESTS RESERVE QUANTITY INFORMATION

(Unaudited)

Notes:

Estimates of royalty interests’ reserves, on properties in which the Company does not own a working interest, have not been included because the information required for the estimation of such reserves is not available. The Company’s share of production from its net royalty interests was 18,198 Bbls of oil and 637,717 MCF of gas for 2011 and 15,082 Bbls of oil and 670,070 MCF of gas for 2010.

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 2011 and 2010. The Company engineer’s qualifications in the Proxy Statement and as incorporated into Item 10 of this Form 10-K, are incorporated herein by reference. All reserves are located within the United States.

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. An independent consulting reservoir engineer tested his reserve estimates and calculations. The consultant’s testing included a review of the reserve calculations for ten properties comprising approximately 50% of the discounted future net cash flow of the Company’s proved working interests oil and gas reserves.

The Company’s internal controls relating to the calculation of its working interests’ reserve estimates include review and testing of the accounting data flowing into the calculation of the reserve estimates. In addition, the average oil and natural gas product prices calculated in the engineer’s 2011 summary reserve report was tested by comparison to 2011 average sales price information from the accounting records. And as indicated in 3. above, his reserve estimates were tested by an outside independent reservoir engineer.

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,
	2011			2010
Future Cash Inflows	$	44,049,488		$	30,117,834
Future Production and Development Costs		(13,259,160	)		(9,826,204	)
Future Asset Retirement Obligation		(1,340,919	)		(1,118,224	)
Future Income Tax Expense		(6,677,879	)		(4,047,155	)
Future Net Cash Flows		22,771,530			15,126,251
10% Annual Discount for Estimated Timing of Cash Flows		(6,716,410	)		(4,697,056	)
Standardized Measure of Discounted Future Net Cash Flows	$	16,055,120		$	10,429,195

Estimates of future net cash flows from the Company’s proved working interests in oil and gas reserves are shown in the table above. These estimates, which by their nature are subject to revision in the near term, were based on an average monthly product price received by the Company for 2010 and 2011, with no escalation. The development and production costs are based on year-end cost levels, assuming the continuation of existing economic conditions. Cash flows are further reduced by estimated future asset retirement obligations and estimated future income tax expense calculated by applying the current statutory income tax rates to the pretax net cash flows, less depreciation of the tax basis of the properties and depletion applicable to oil and gas production.

SUPPLEMENTAL SCHEDULE 3



THE RESERVE PETROLEUM COMPANY
CHANGES IN STANDARDIZED MEASURE OF
DISCOUNTED FUTURE NET CASH FLOWS FROM
PROVED WORKING INTERESTS RESERVE QUANTITIES
(Unaudited)


	Year Ended December 31,
	2011			2010
Standardized Measure, Beginning of Year	$	10,429,195		$	6,706,743
Sales and Transfers, Net of Production Costs		(6,217,245	)		(5,748,274	)
Net Change in Sales and Transfer Prices, Net of Production Costs		2,785,761			4,806,101
Extensions, Discoveries and Improved Recoveries,
Net of Future Production and Development Costs		5,751,088			4,508,515
Revisions of Quantity Estimates		2,997,976			1,098,241
Accretion of Discount		1,325,458			803,200
Purchases of Reserves in Place		---			11,257
Net Change in Income Taxes		(1,648,334	)		(1,472,538	)
Net Change in Asset Retirement Obligation		(115,433	)		(121,546	)
Changes in Production Rates (Timing) and Other		746,654			(162,504	)
Standardized Measure, End of Year	$	16,055,120		$	10,429,195

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (the "Exchange Act"), the term "disclosure controls and procedures" means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Management of the Company, with the participation of the Principal Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Company's disclosure controls and procedures and concluded that the Company's disclosure controls and procedures were effective as of December 31, 2011.

Management's Annual Report on Internal Control over Financial Reporting

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

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

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

With the participation of the 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, 2011.

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

/s/ Cameron R. McLain		/s/ James L. Tyler
Cameron R. McLain, President		James L. Tyler, 2nd Vice President
Principal Executive Officer		Principal Financial Officer
March 28, 2012		March 28, 2012

Changes in Internal Control over Financial Reporting

Management of the Compnay, with the participation of the Chief Executive Officer and Chief Financial Officer, evaluated the internal control over financial reporting and concluded that no change in the Company’s internal control over financial reporting occurred during the fourth quarter ended December 31, 2011 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.

ITEM 9B.

OTHER INFORMATION

Not applicable.

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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

ITEM 11.

EXECUTIVE COMPENSATION

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

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

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

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

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

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

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

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.
101 INS*#		XBRL INSTANCE DOCUMENT

101.SCH*#		XBRL TAXONOMY EXTENSION SCHEMA DOCUMENT

101.CAL*#		XBRL TAXONOMY CALCULATION LINKBASE DOCUMENT

101.LAB*#		XBRL TAXONOMY LABEL LINKBASE DOCUMENT

101.PRE*#		XBRL TAXONOMY PRESENTATION LINKBASE DOCUMENT

		____________________________
		*	Filed electronically herewith.
		#	Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

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
			(Signature of Subscriber or Authorized Signatory)
			By. Cameron R. McLain, President
			(Principal Executive Officer)


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

Date: March 28, 2012

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 28, 2012			March 28, 2012

/s/ Robert L. Savage			/s/ William M. Smith
Robert L. Savage (Director)			William M. Smith (Director)
March 28, 2012			March 28, 2012