UNITED STATES


SECURITIES AND EXCHANGE COMMISSION


Washington, D.C.  20549





FORM 10-K


(Mark One)


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





For the Fiscal Year Ended December 31, 2012




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





Commission File Number 0-8157




THE RESERVE PETROLEUM COMPANY


(Exact Name of Registrant as Specified in Its Charter)


DELAWARE
73-0237060(State or Other Jurisdiction of Incorporation or Organization)
(I.R.S. Employer Identification No.)6801 BROADWAY EXT., SUITE 300

OKLAHOMA CITY, OKLAHOMA  73116-9037

(405) 848-7551(Address and telephone number, including area code, of registrant’s principal executive offices)





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


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





COMMON STOCK ($0.50 PAR VALUE)(Title of Class)





Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.


Yes o    Noþ





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


Yes o     No þ





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


Yes þNo o





Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).


Yes þNo o





Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.þ





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





Large accelerated filer
o

Accelerated filer
o

Non-accelerated filer
o

Smaller reporting company
þ





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


Yes o    No þ





The aggregate market value of the voting and non-voting common stock of the registrant held by non-affiliates of the registrant was $34,871,649, as computed by reference to the last reported sale which was on March 22, 2013.





As of March 22, 2013, there were 160,714.64 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 30, 2013, which will be filed within 120 days of the end of the registrant’s year ended December 31, 2012, are incorporated by reference into Part III of this Form 10-K to the extent described therein.




TABLE OF CONTENTS




PageForward Looking Statements


3PART IItem 1.
Business


3Item 1A.
Risk Factors


5Item 1B.
Unresolved Staff Comments


5Item 2.
Properties


5Item 3.
Legal Proceedings


7Item 4.
Mine Safety Disclosures


7PART IIItem 5.
Market for Registrant’s Common Equity, Related Stockholder Matters andIssuer Purchases of Equity Securities


7Item 6.
Selected Financial Data


7Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations


8Item 7A.
Quantitative and Qualitative Disclosures about Market Risk


15Item 8.
Financial Statements and Supplementary Data


16Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure


36Item 9A.
Controls and Procedures


36Item 9B.
Other Information


37PART IIIItem 10.
Directors, Executive Officers and Corporate Governance


37Item 11.
Executive Compensation


37Item 12.
Security Ownership of Certain Beneficial Owners and Management andRelated Stockholder Matters


37Item 13.
Certain Relationships and Related Transactions and Director Independence


37Item 14.
Principal Accountant Fees and Services


37PART IVItem 15.
Exhibits and Financial Statement Schedules


38




2




Forward-Looking Statements





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




PART I





ITEM 1.
BUSINESS





Overview




The Reserve Petroleum Company (the “Company”) 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 257,168 gross acres equivalent to 88,612 net acres. These mineral interests are located in nine different states in the north and south central United States. A total of 81,479 (92%) 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 2012, $3,517,635 (27%) of oil and gas sales was from royalty interests versus $4,246,293 (35%) in 2011. As a result of its mineral ownership, the Company had royalty interests in 49 gross (.42 net) wells, which were drilled and completed as producing wells in 2012. This resulted in an average royalty interest of about 0.8% for these 49 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 2012, the Company participated in the drilling of 34 development wells with 26 wells (3.06 net), including the 9 wells in progress at the end of 2011, completed as producers and 8 wells (1.23 net) in progress at the time of this Form 10-K.




3




Exploration Program





The Company’s exploration program is normally conducted by purchasing interests in prospects developed by independent third parties; participating in third party exploration of Company-owned non-producing minerals; developing 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 2012, the Company participated in the drilling of 28 exploration wells with 14 wells (1.75 net), including 4 wells in progress at the end of 2011, completed as producers, 9 wells (1.48 net), including 1 well in progress at the end of 2011, completed as dry holes and 5 wells (.8 net) in progress at the time of this Form 10-K.





For a summation of exploratory and development wells drilled in 2012 or planned for in 2013, 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, 2011.”





Customers





In 2012, the Company had two customers whose total purchases were greater than 10% of revenues from oil and gas sales. Redland Resources, Inc. purchases were $3,743,726 or 29% of total oil and gas sales. Luff Exploration Company purchases were $1,641,275 or 13% 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.




4





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





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





Other Business





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





Employees





At December 31, 2012, the Company had eight employees, including officers. See the Proxy Statement for additional information. During 2012, 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 770 producing properties with 35% of them being working interest properties and the remaining 65% being royalty interest properties. About 81% of all properties are located in Oklahoma and Texas and account for approximately 69% of the Company’s annual oil and gas sales. About 15% of the properties are located in Arkansas, Kansas, and South Dakota and account for approximately 31% 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 8% 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.




5




OIL AND NATURAL GAS OPERATIONS





Oil and Gas Reserves





Reference is made to the Unaudited Supplemental Financial Information beginning on Page 31 for working interest reserve quantity information.





Since January 1, 2012, 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 2011 Annual Report on Form 10-K and federal income tax return for the year ended December 31, 2011. 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, 2012, 2011 and 2010. Equivalent MCF was calculated using approximate relative energy content.





Royalties


Working InterestsSales Price


Sales Price


Average ProductionOil


Gas


Oil


Gas


Cost perPer Bbl


Per MCF


Per Bbl


Per MCF


Equivalent MCF2012

$
91.13


$
2.63


$
86.15


$
3.07


$
1.852011

$
91.27


$
3.83


$
87.32


$
4.26


$
1.982010

$
79.62


$
4.98


$
70.05


$
4.47


$
1.64





At December 31, 2012, the Company had working interests in 169 gross (20.9 net) wells producing primarily gas and 187 gross (18.98 net) wells producing primarily oil. These interests were in 66,834 gross (8,459 net) producing acres. These wells include 46 gross (1.23 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, 2012.





AcreageGross


NetNon-producing Mineral Interests


257,168



88,612Undeveloped Leaseholds


25,191



3,143





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, 2010 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 2012 include the 14 wells still drilling at the end of 2011. As indicated in the “Development Program” on Page 3 and “Exploration Program” on Page 4, 8 development wells and 5 exploratory wells were still in process at the time of this Form 10-K.




Number of Net Working Interest Wells DrilledExploratory


DevelopmentProductive


Dry


Productive


Dry2012

1.75


1.48


3.06


—2011

1.26


.61


2.26


—2010

.82


1.14


2.01


—





Recent Activities





See Item 7, under the subheading “Update of Oil and Gas Exploration and Development Activity from December 31, 2011” for a summary of recent activities related to oil and natural gas operations.





6





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 RangesQuarter Ending

High Bid


Low Bid03/31/11

$
410


$
30106/30/11

$
405


$
33009/30/11

$
341


$
27512/31/11

$
300


$
24003/31/12

$
340


$
29006/30/12

$
335


$
27509/30/12

$
300


$
27512/31/12

$
320


$
288





There was limited public trading in the Company’s common stock in 2012 and 2011. There were 11 brokered trades appearing in the Company’s transfer ledger for 2012 and 20 in 2011.





At March 22, 2013, the Company had approximately 1,590 record holders of its common stock. The Company paid dividends on its common stock in the amount of$20.00 per share in 2012 ($10.00 per share in both the second and fourth quarters of 2012) and $10.00 per share in 2011 (in the second quarter of 2011). 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 2013 with the Board of Directors for its approval.




ISSUER PURCHASES OF EQUITY SECURITIESPeriod
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 Programs1October 1 to October 31, 2012
—
N/A
—
—November 1 to November 30, 2012
—
N/A
—
—December 1 to December 31, 2012
127
$   180.00
—
—Total
127
$   180.00
—
—





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





ITEM 6.
SELECTED FINANCIAL DATA





Not applicable.




7


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 2013 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.




8




·
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 INVESTMENT





The Company had a 33% partnership interest in Broadway Sixty-Eight, Ltd. (the “Partnership”) in 2011 and 2012, which it accounted for on the equity method. In using the equity method, the Company records the original investment in an entity as an asset and adjusts the asset balance for the Company’s share of any income or loss, as well as any additional contributions to or distributions from the entity. The Company does not have actual or effective control of the Partnership. The





9




management of the Partnership could, at any time, make decisions in their own best interests that could affect the Company’s net income or the value of the Company’s investment.





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




LIQUIDITY AND CAPITAL RESOURCES





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





In 2012, as in prior years, the Company funded its business activity through the use of internal sources of capital. For the most part, these internal sources are cash flows from operations, cash, cash equivalents and available-for-sale securities. When cash flows from operating activities are in excess of those needed for other business activities, the remaining balance is used to increase cash, cash equivalents and/or available-for-sale securities. When cash flows from operating activities are not adequate to fund other business activities, withdrawals are made from cash, cash equivalents and/or available-for-sale securities. Cash equivalents are highly liquid debt instruments purchased with a maturity of three months or less. All of the available-for-sale securities are U.S. Treasury Bills.





In 2012, net cash provided by operating activities was $10,454,012. Sales (including lease bonuses), net of production, general and administrative costs, and income taxes paid were $10,421,009, which accounted for 99.7% of net cash provided by operations. The remaining components provided less than 1% of cash flow. In 2012, net cash applied to investing activities was $6,621,668. In 2012, dividend payments and treasury stock purchases totaled $3,140,775 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:





Refundable income taxes decreased $298,048 (37%) to $518,077 in 2012 from $816,125 in 2011. This decrease was due to excess 2012 estimated tax payments being less than in 2011.





Receivables decreased $167,693 (9%) to $1,736,169 in 2012 from $1,903,862 in 2011. The decrease was due primarily to the use of a lower price per barrel for oil sales accrual estimates for year-end 2012 compared to 2011. This decline was partly offset by an increase in the oil sales volume estimates for year-end 2012 compared to 2011. Additional information about oil and natural gas sales for 2012 is included in the “Results of Operations” section that follows.





Accounts payable increased $243,637 (88%) to $519,654 in 2012 from $276,017 in 2011. This increase was primarily due to the increased drilling activity at the end of 2012 compared to 2011.





Deferred income taxes and other accrued liabilities decreased $84,736 (29%) to $207,430 in 2012 from $292,166 in 2011. This decrease was primarily due to the decrease in the current deferred tax accrual due to the decrease in the oil and gas sales accrual in 2012.





The following is a discussion of material changes in cash flow by activity between the years ended December 31, 2012 and 2011. 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 2012 were $10,454,012, which, when compared to the $8,194,133 provided in 2011, represents a net increase of $2,259,879 or 28%. The increase was mostly due to an increase in oil and gas sales cash flows of $892,292 and an increase in lease bonuses and coal royalties of $1,607,593. Those increases in cash flows were partially offset by an increase in production costs of $375,569. Additional discussion of the more significant items follows.





Discussion of Selected Material Line Items Resulting in an Increase in Cash Flows. The $892,292 (7%) increase in cash received from oil and gas sales to $13,005,197 in 2012 from $12,112,905 in 2011 was the result of an increase in the volume of oil and gas sales, partially offset by declines in the oil and gas sales prices. See “Results of Operations” below for a price/volume analysis and the related discussion of oil and gas sales.





Cash received for lease bonuses and coal royalties increased $1,607,593 (234%) to $2,295,880 in 2012 from $688,287 in 2011. Most of the increase is due to an increase in cash received for lease bonuses of $1,524,098 in 2012 versus 2011.




10




Cash flow increased due to a decrease in income taxes paid of $283,979 (24%) to $889,350 in 2012 from $1,173,329 in 2011 due to lower estimated tax payments in 2012. The lower payments were mostly due to lower net income and curent taxable income in 2012.





Discussion of Selected Material Line Items Resulting in a Decrease in Cash Flows. Cash paid for production costs increased $375,569 (19%) to $2,390,344 in 2012 from $2,014,775 in 2011. This increase was mostly due to lease operating and handling expense on new wells of about $284,000. The remaining increase was due to increased operating expense on previous wells and production taxes. The increase in production taxes was due to the increase in sales in 2012 versus 2011.





Cash flow decreased due to an increase in general and administrative and taxes other than income (G&A) of $169,881 (12%) to $1,600,374 in 2012 from $1,430,493 in 2011. The G&A increase was mostly due to higher salaries and benefits of approximately $118,000 and increased legal and accounting expense of about $43,000.





Investing Activities





Net cash applied to investing activities increased $7,323,163 to $6,621,668 in 2012 from $701,495 of cash provided in 2011. In 2012, net cash flows from available-for-sale securities were $2,248 compared to net cash flows of $6,483,973 in 2011. This $6,481,725 decrease in net cash flow was due primarily to the 2011 conversion of $5,000,000 cash from Treasury bill maturities into money market funds with better interest rates than the Treasury bills. Another $1,484,000 of cash from Treasury bill maturities was used for capitalized property additions and dividend payments in excess of 2011 operations cash flow. The remaining significant increase in cash applied to investing activities pertains to the decrease in proceeds from property disposals. This line item decreased $760,070 (60%) to $499,553 in 2012 from $1,259,623 in 2011. This decrease was the result of fewer sales of Kansas and Oklahoma nonproducing leaseholds in 2012 compared to 2011.





Financing Activities





Cash applied to financing activities increased $1,454,922 (86%) to $3,140,775 in 2012 from $1,685,853 in 2011. Cash applied to financing activities consist of cash dividends on common stock and cash used for the purchase of treasury stock. In 2012, cash dividends paid on common stock amounted to $3,100,835 as compared to $1,644,413 in 2011. Dividends of $20.00 per share were paid for 2012 and $10.00 per share for 2011.





Forward-Looking Summary





The Company’s latest estimate of business to be done in 2013 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 2012 the Company had net income of $4,553,845 as compared to a net income of $5,279,039 in 2011. Net income per share, basic and diluted, was $28.30 in 2012, a decrease of $4.47 per share from $32.77 in 2011. Material line item changes in the Statements of Income will be discussed in the following paragraphs.





Operating Revenues





Operating revenues increased $2,171,416 (17%) to $15,134,381 in 2012 from $12,962,965 in 2011. Oil and gas sales increased $697,789 (6%) to $12,949,108 in 2012 from $12,251,319 in 2011. Lease bonuses and other revenues increased $1,473,627 to $2,185,273 in 2012 from $711,646 in 2011. This increase was the result of an increase in lease bonuses of $1,524,099 from leases in Texas and Kansas. In addition, coal royalties from North Dakota leases decreased $50,472 (18%) to $224,336 in 2012 from $274,808 in 2011. The increase in oil and gas sales is discussed in the following paragraphs.





The $697,789 increase in oil and gas sales was the net result of a $1,205,750 decrease in gas sales, offset by a $1,893,583 increase in oil sales and a $9,956 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 2011 to 2012. Miscellaneous oil and gas product sales of $354,853 in 2012 and $344,897 in 2011 are not included in the analysis.





11




VarianceProduction

2012


Price


Volume


2011Gas –MCF (000 omitted)


1,128






21



1,107$ (000 omitted)

$
3,239


$
(1,292
)

$
86


$
4,444Unit Price

$
2.87


$
(1.15
)





$
4.02Oil –Bbls (000 omitted)


107







22



85$ (000 omitted)

$
9,355


$
(115
)

$
2,008


$
7,462Unit Price

$
87.10


$
(1.07
)





$
88.17





The $1,205,750 (27%) decrease in natural gas sales to $3,238,729 in 2012 from $4,444,479 in 2011 was the net result of a decline in the average price received per thousand cubic feet (MCF) and an increase in gas sales volumes. The average price per MCF of natural gas sales decreased $1.15 per MCF to $2.87 in 2012 from $4.02 per MCF in 2011, resulting in a negative gas price variance of $(1,292,124). A positive volume variance of $86,374 was the result of an increase in natural gas volumes sold of 21,486 MCF to 1,128,385 MCF in 2012 from 1,106,899 MCF in 2011. The increase in the volume of gas production was the net result of new 2012 production of about 173,000 MCF, offset by a decline of about 151,000 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 2011 and 2012.





The gas production for 2011 and 2012 includes production from several royalty interest properties drilled by various operators in Robertson County, Texas. These properties accounted for approximately 492,000 MCF and $1,830,000 of the 2011 gas sales and approximately 387,000 MCF and $965,000 of the 2012 gas sales. These properties accounted for about 41% of the Company’s 2011 gas revenues compared to 30% of 2012 gas revenues. Recent depressed natural gas prices have delayed many operators’ current drilling plans. The Company has no control over the timing of future drilling on the acreage in which we hold mineral interests. However, if natural gas prices recover, the Company expects that drilling activity in Robertson County will increase also.





The $1,893,583 (25%) increase in crude oil sales to $9,355,526 in 2012 from $7,461,943 in 2011 was the net result of a decline in the average price per barrel (Bbl) and an increase in oil sales volumes. The average price received per Bbl of oil decreased $1.07 to $87.10 in 2012 from $88.17 in 2011, resulting in a negative oil price variance of $114,726. An increase in oil sales volumes of 22,778 Bbls to 107,407 Bbls in 2012 from 84,629 Bbls in 2011 resulted in a positive volume variance of $2,008,309. The increase in the oil volume production was the net result of new 2012 production of about 33,000 Bbls, offset by a 10,000 Bbl decline in production from previous wells. Of the new 2012 production, approximately 11,000 Bbls (33%) was from Woods County, Oklahoma; about 17,100 Bbls (52%) was from new working interest wells in Oklahoma (in counties other than Woods); 2,900 Bbls (9%) was from new working interest wells in Kansas and Texas; and about 2,000 Bbls (6%) 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 2012.





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





Operating Costs and Expenses





Operating costs and expenses increased $2,531,228 (36%) to $9,493,080 in 2012 from $6,961,852 in 2011, primarily due to 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 $375,828 (18%) to $2,414,761 in 2012 from $2,038,933 in 2011. The increase was the result of a $19,072 (4%) increase in gross production tax (net of production tax refunds) to $550,658 in 2012 from $531,586 in 2011, plus an increase in lease operating and handling expense of $356,756 (24%) to $1,864,103 in 2012 from $1,507,347 in 2011. The increase in lease operating and handling expense was due to an increase in lease operating expense of $336,441 (30%) to $1,464,937 in 2012 from $1,128,495 in 2011, and an increase in handling expense of $20,314 from $378,852 in 2011 to $399,166 in 2012. 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.





12





Exploration and Development Costs. Under the successful efforts method of accounting used by the Company, geological and geophysical costs are expensed as incurred as are the costs of unsuccessful exploratory drilling. The costs of successful exploratory drilling and all development costs are capitalized. Total costs of exploration and development, excluding asset retirement obligations but inclusive of geological and geophysical costs, were $7,197,753 in 2012 and $6,658,584 in 2011. See Item 8, Note 8 to the accompanying financial statements for a breakdown of these costs. Exploration costs charged to operations were $316,465 in 2012 and $324,908 in 2011, inclusive of unsuccessful exploratory well costs of $316,465 in 2012 and $319,429 in 2011 and no geological and geophysical costs in 2012 and $5,479 in 2011.





Update of Oil and Gas Exploration and Development Activity from December 31, 2011. For the year ended December 31, 2012, the Company participated in the drilling of 28 gross exploratory and 34 gross development working interest wells with working interests ranging from a high of 18% to a low of 2.2%. Of the 28 exploratory wells, 14 were completed as producing wells, 9 as dry holes and 5 were in progress. Of the 34 development wells, 26 were completed as producing wells and 8 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 5, 2013, updating both exploration and development activity from December 31, 2011, for the period ended December 31, 2012.





The Company participated with its 18% working interest in the completion of three development wells as commercial oil and gas producers on a Barber County, Kansas prospect (these wells were drilled in 2011). The Company participated in six additional development wells on the prospect and in the drilling of a salt water disposal well. Four of these wells were completed as commercial oil and gas producers and two as marginal gas producers. Two additional development wells will be drilled starting in March 2013 and five more are planned for the remainder of 2013. Capitalized costs for the period were $567,966, including $41,668 in prepaid drilling costs.





The Company participated in the drilling of seven step-out wells on a Woods County, Oklahoma prospect (12%, 8%, 16%, 16%, 16%, 16% and 8% working interests). Six of these wells were completed as commercial oil and gas producers and a completion is in progress on the seventh. The Company will participate with a 14% working interest in the drilling of two additional step-out wells starting in March or April 2013. Capitalized costs for the period were $662,094, including $122,515 in prepaid drilling costs.





The Company participated with a 4.6% 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. Total capitalized costs for the period were $38,543.





The Company participated in the drilling of a development well (17.3% working interest) and an exploratory well (18% interest) on a Woods County, Oklahoma prospect. The development well was completed as a marginal oil and gas producer and the exploratory well as a dry hole. The Company is participating with a 13.7% working interest in the drilling of two additional development wells. One has been drilled and is awaiting completion and the other will be drilled in March 2013. Capitalized costs for the period were $127,913 and dry hole costs were $49,303.





The Company participated with its 16% working interest in a step-out well on a Woods County, Oklahoma prospect. The well has been drilled and is awaiting completion. Prepaid drilling costs were $49,600 for the period.





The Company participated with its 16% working interest in the completion of a step-out well and an exploratory well as commercial oil producers on a Hodgeman County, Kansas prospect (these wells were drilled in 2011). The Company also participated in the drilling of ten additional wells on the prospect (three step-out and seven exploratory). Four of these wells were completed as commercial oil producers, five as dry holes and a completion is in progress on the tenth. Capitalized costs for the period were $301,908, including $12,577 in prepaid drilling costs. Dry hole costs were $108,430 for the period.





The Company participated with a 10% working interest in the completion as a marginal gas producer of an exploratory well on a Grady County, Oklahoma prospect (the well was drilled in 2011). Capitalized costs for the period were $124,118.




13




The Company participated with its 4.1% working interest in the drilling of an additional horizontal well in a Harding County, South Dakota waterflood unit. It was completed as an oil well but will eventually be converted to a water injection well. Capitalized costs for the period were $122,522.





The Company participated with its 18% working interest in the drilling of an exploratory well on a Ness County, Kansas prospect. Completion attempts have been unsuccessful and $65,525 was charged to dry hole costs.





The Company participated with its 18% working interest in the drilling of two exploratory wells on a Ness and Hodgeman Counties, Kansas prospect. Both wells were completed as commercial oil producers. The Company also participated in the drilling of a salt water disposal well. Capitalized costs for the period were $216,301, including $59,395 in prepaid drilling costs.





The Company participated with 10.5%, 6.6% and 10.5% working interests in the drilling of three step-out horizontal wells on a Garfield County, Oklahoma prospect. The first two wells were completed as commercial oil and gas producers and a completion is in progress on the third. The Company also participated in the drilling of a salt water disposal well. Capitalized costs for the period were $1,087,305, including $304,562 in prepaid drilling costs.





The Company participated with its 7% interest in the re-entry and conversion to salt water disposal of a plugged well on a Custer County, Oklahoma prospect. Capitalized costs for the period were $75,223.





The Company participated with a 9.3% working interest in the completion of an exploratory horizontal well as a marginal oil producer on a Grayson County, Texas prospect (the well was drilled in 2011). The Company is participating with its 7% working interest in the drilling of two additional exploratory horizontal wells on the prospect, the first of which is in progress. Capitalized costs for the period were $92,214.





The Company participated with its 18% 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 $221,970.





The Company participated with its 18% working interest in the completion of a horizontal development well as a marginal oil producer on a Comanche County, Kansas prospect (the well was drilled in 2011). The Company also participated in the fracking of a marginal well on the prospect, which remained marginal, in the drilling of a salt water disposal well and in the drilling of a vertical development well, which was completed as a marginal oil producer. Capitalized costs for the period were $323,930, including $40,065 in prepaid drilling costs, and an impairment of $304,870 was taken on the horizontal well.





The Company participated with fee mineral interests in the drilling of three exploratory horizontal wells in Beaver County, Oklahoma. The Company has interests of 10.2%, 12.6% and 10.2% in the three wells, which were all completed as commercial oil producers. Capitalized costs for the period were $704,980.





The Company participated with 6.2%, 5.7% and 5.2% working interests in the drilling of three exploratory horizontal wells on a Dewey County, Oklahoma prospect. All three of these wells were completed as commercial oil and gas producers. The Company will participate (5.7% interest) in a horizontal development well that will be drilled in the second quarter of 2013. Capitalized costs for the period were $931,881.





The Company participated with a fee mineral interest in six horizontal development wells in Van Buren County, Arkansas (6.7%, 7.1%, 7%, 3.1%, 9.3% and 9.3% interests). All six of these wells were completed as commercial gas wells. Capitalized costs for the period were $1,101,614.





In December 2012, the Company purchased a 16% interest in 960 net acres of leasehold on a Hodgeman County, Kansas prospect for $14,592. A 3-D seismic survey will be conducted starting in March 2013.





In December 2012, the Company purchased a 10.5% interest in 8,882.56 net acres of leasehold on a Cimarron County, Oklahoma prospect for $116,584 and prepaid an additional $8,400 for the acquisition of additional acreage. A 3-D seismic survey is in progress on the prospect.





In January 2013, The Company purchased a 14% interest in 11,647.61 net acres of leasehold on a Ford and Gray Counties, Kansas prospect for $154,913. A 3-D seismic survey is in progress on the prospect.




14




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 $136,456 in 2012 and $409,045 in 2011. Of the 2012 provision, $101,596 was due to the annual amortization of undeveloped leaseholds and $34,860 was due to specific leasehold impairments. The 2011 provision was due to the annual amortization of undeveloped leaseholds of $394,050 and specific leasehold impairments of $14,995.





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 2012 and 2011. The 2012 impairment loss was $1,811,732 and the 2011 impairment loss was $828,071. The $983,661 increase in impairments in 2012 was mainly due to the Company’s increased participation in the drilling of horizontal wells. In 2012, approximately 40% of the working interest wells in which the Company participated were horizontal wells. A horizontal well may cost five to eight times as much as a vertically drilled well. The increased investment in the costlier horizontal wells results in larger impairments when the oil and gas wells are only marginally economic.





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 $3,169,827 in 2012 and $1,909,307 in 2011. The provision also includes $116,048 for 2012 and $82,852 for 2011 for the amortization of the Asset Retirement Costs. See Item 8, Note 2 to the accompanying financial statements for additional information regarding the Asset Retirement Obligation.





Other Income (Loss), Net. See Item 8, Note 11 to the accompanying financial statements for an analysis of the components of this line item for 2012 and 2011. Other income, net decreased $566,542 (54%) to $491,362 in 2012 from $1,057,904 in 2011. The line items responsible for this decrease are described below.





Gains on sales or disposals of assets decreased $638,634 (59%) to $452,590 in 2012 from gains of $1,091,224 in 2011. This was due to lower 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 $7,276 to a net loss of $(11,296) in 2012 from a net loss of $(18,572) in 2011. 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 2012, the Company had realized gains of $6,359 and unrealized losses of $(17,655). In 2011, the Company had realized gains of $73,334 and unrealized losses of $(91,906).





Interest income increased $9,660 (42%) to $32,434 in 2012 from $22,774 in 2011. This increase was the result of an increase in the average rate of return on and a decrease in the 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 increased 0.10% to 0.26% in 2012 from 0.16% in 2011. The average balance outstanding decreased $1,434,008 to $12,489,520 in 2012 from $13,923,528 in 2011.





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 2012, the Company had an estimated provision for income taxes of $1,651,821 as the result of a current tax provision of $1,187,398 and a deferred tax provision of $464,423. 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.





ITEM 7A.
QUANTITATIVEAND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS





Not applicable.




15




ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA




Index to Financial Statements




PageReport of Independent Registered Public Accounting FirmHoganTaylor LLP


17Balance Sheets – December 31, 2012 and 2011


18Statements of Income – Years Ended December 31, 2012 and 2011


20Statements of Stockholders’ Equity – Years Ended December 31, 2012 and 2011


21Statements of Cash Flows – Years Ended December 31, 2012 and 2011


22Notes to Financial Statements


24Unaudited Supplemental Financial Information


31


16




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, 2012 and 2011, and the related statements of income, stockholders’ equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.




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




In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of The Reserve Petroleum Company as of December 31, 2012 and 2011, and the results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.




/s/ HoganTaylor LLP




Oklahoma City, Oklahoma


March 27, 2013




17




THE RESERVE PETROLEUM COMPANYBALANCE SHEETSASSETS
  December 31,2012


2011Current Assets:Cash and Cash Equivalents (Note 2)

$
10,842,311


$
10,150,742Available-for-Sale Securities (Notes 2 & 5)


6,652,590



6,654,838Trading Securities (Notes 2 & 5)


389,335



398,964Refundable Income Taxes


518,077



816,125Receivables (Note 2)


1,736,169



1,903,86220,138,482



19,924,531Investments:Equity Investment (Notes 2 & 7)


594,855



521,852Other


151,839



151,839746,694



673,691Property, Plant and Equipment (Notes 2, 8 & 10):Oil and Gas Properties, at Cost,Based on the Successful Efforts Method of Accounting –Unproved Properties


874,367



1,179,882Proved Properties


39,329,747



32,441,40340,204,114



33,621,285Less – Accumulated Depreciation, Depletion, Amortization andValuation Allowance


25,726,672



21,177,54114,477,442



12,443,744Other Property and Equipment, at Cost


425,024



417,526Less – Accumulated Depreciation and Amortization


268,095



227,895156,929



189,631Total Property, Plant and Equipment


14,634,371



12,633,375Other Assets


363,722



361,802Total Assets

$
35,883,269


$
33,593,399
  18




THE RESERVE PETROLEUM COMPANYBALANCE SHEETSLIABILITIES AND STOCKHOLDERS’ EQUITYDecember 31,2012


2011Current Liabilities:Accounts Payable

$
519,654


$
276,017Other Current Liabilities – Deferred Income Taxes and Other


207,430



292,166727,084



568,183Long-Term Liabilities:Asset Retirement Obligation (Note 2)


1,162,078



990,074Dividends Payable (Note 3)


1,535,568



1,419,884Deferred Tax Liability, Net (Note 6)


3,274,807



2,726,9785,972,453



5,136,936Total Liabilities


6,699,537



5,705,119Commitments and Contingencies (Notes 2 & 7)Stockholders’ Equity (Notes 3 & 4):Common Stock


92,368



92,368Additional Paid-in Capital


65,000



65,000Retained Earnings


29,898,866



28,563,47430,056,234



28,720,842Less – Treasury Stock, at Cost


872,502



832,562Total Stockholders’ Equity


29,183,732



27,888,280Total Liabilities and Stockholders’ Equity

$
35,883,269


$
33,593,399
  19


THE RESERVE PETROLEUM COMPANYSTATEMENTS OF INCOMEYear Ended December 31,2012


2011Operating Revenues:Oil and Gas Sales

$
12,949,108


$
12,251,319Lease Bonuses and Other


2,185,273



711,64615,134,381



12,962,965Operating Costs and Expenses:Production


2,414,761



2,038,933Exploration


316,465



324,908Depreciation, Depletion, Amortization and Valuation Provisions (Note 10)


5,158,215



3,179,534General, Administrative and Other


1,603,639



1,418,4779,493,080



6,961,852Income from Operations


5,641,301



6,001,113Equity Income in Investee (Note 7)


73,003



35,884Other Income, Net (Note 11)


491,362



1,057,904Income Before Income Taxes


6,205,666



7,094,901Provision for Income Taxes (Notes 2 & 6)


1,651,821



1,815,862Net Income

$
4,553,845


$
5,279,039Per Share Data (Note 2):Net Income, Basic and Diluted

$
28.30


$
32.77Cash Dividends

$
20.00


$
10.00Weighted Average Shares Outstanding, Basic and Diluted


160,933



161,117
  20




THE RESERVE PETROLEUM COMPANYSTATEMENTS OF STOCKHOLDERS’ EQUITYFOR THE YEARS ENDED DECEMBER 31, 2012 AND 2011
  AdditionalCommon


Paid-in


Retained


TreasuryStock


Capital


Earnings


Stock


TotalBalance at December 31, 2010

$
92,368


$
65,000


$
24,895,712


$
(791,122
)

$
24,261,958Net Income


—



—



5,279,039



—



5,279,039Dividends Declared


—



—



(1,611,277
)


—



(1,611,277
)Purchase of Treasury Stock


—



—



—



(41,440
)


(41,440
)Balance at December 31, 2011


92,368



65,000



28,563,474



(832,562
)


27,888,280Net Income


—



—



4,553,845



—



4,553,845Dividends Declared


—



—



(3,218,453
)


—



(3,218,453
)Purchase of Treasury Stock


—



—



—



(39,940
)


(39,940
)Balance at December 31, 2012

$
92,368


$
65,000


$
29,898,866


$
(872,502
)

$
29,183,732
 
 See Accompanying Notes
  21




THE RESERVE PETROLEUM COMPANYSTATEMENTS OF CASH FLOWS
  Year Ended December 31,2012


2011Cash Flows from Operating Activities:Cash Received –Oil and Gas Sales

$
13,005,197


$
12,112,905Lease Bonuses and Coal Royalties


2,295,880



688,287Sale of Trading Securities


733,913



886,263Interest Received


31,476



29,462Agricultural Rentals and Other


6,318



5,781Dividends Received on Trading Securities


1,678



3,878Cash Paid –Production Costs


(2,390,344
)


(2,014,775
)General Suppliers, Employees and Taxes, Other than Income Taxes


(1,600,374
)


(1,430,493
)Interest Paid


(4,432
)


(3,854
)Purchase of Trading Securities


(735,580
)


(889,675
)Income Taxes Paid, Net


(889,350
)


(1,173,329
)Farm Expense


(370
)


(20,317
)Net Cash Provided by Operating Activities


10,454,012



8,194,133Cash Flows Provided by/(Applied to) Investing Activities:Maturity of Available-for-Sale Securities


13,307,033



26,032,687Purchase of Available-for-Sale Securities


(13,304,785
)


(19,548,714
)Proceeds from Disposal of Property, Plant and Equipment


499,553



1,259,623Purchase of Property, Plant and Equipment


(7,167,669
)


(7,095,101
)Cash Distributions from Equity and Other Investments


44,200



3,000Repayments from Equity Investee


—



50,000Net Cash Provided by/(Applied to) Investing Activities


(6,621,668
)


701,495
  See Accompanying Notes
 22




THE RESERVE PETROLEUM COMPANYSTATEMENTS OF CASH FLOWS
  Year Ended December 31,2012


2011Cash Flows Applied to Financing Activities:Dividends Paid to Stockholders

$
(3,100,835
)

$
(1,644,413
)Purchase of Treasury Stock


(39,940
)


(41,440
)Total Cash Applied to Financing Activities


(3,140,775
)


(1,685,853
)Net Change in Cash and Cash Equivalents


691,569



7,209,775Cash and Cash Equivalents at Beginning of Year


10,150,742



2,940,967Cash and Cash Equivalents at End of Year

$
10,842,311


$
10,150,742Reconciliation of Net Income to Net Cash Provided by Operating Activities:Net Income

$
4,553,845


$
5,279,039Net Income Increased (Decreased) by Net Change in –Net Unrealized Holding Losses on Trading Securities


17,655



91,906Accounts Receivable


168,652



(159,942
)Interest and Dividends Receivable


(958
)


6,688Refundable Income Taxes


298,048



(534,293
)Accounts Payable


118,146



36,768Trading Securities


(8,028
)


(76,745
)Other Assets


(1,920
)


(5,842
)Deferred Taxes


464,423



1,176,826Other Liabilities


(1,330
)


24,540Income from Equity and Other Investments


(117,203
)


(38,884
)Exploratory Costs


228,405



305,762Gain on Disposition of Property, Plant and Equipment


(452,590
)


(1,091,224
)Depreciation, Depletion, Amortization and Valuation Provisions


5,186,867



3,179,534Net Cash Provided by Operating Activities

$
10,454,012


$
8,194,133
  See Accompanying Notes
 23


THE RESERVE PETROLEUM COMPANY


NOTES TO FINANCIAL STATEMENTS







Note 1 – NATURE OF OPERATIONS





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




Note 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES





Cash and Cash Equivalents





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





Investments





Marketable Securities:


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





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





Unrealized gains and losses on available-for-sale securities, which consist entirely of U.S. Government securities, are reported as a component of other comprehensive income when significant to the financial statements.





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.




24





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





Office furniture and fixtures
5 to 10 yearsAutomotive 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 an asset/liability approach to calculating deferred income taxes. Deferred income taxes are provided to reflect temporary differences in the basis of net assets and liabilities for income tax and financial reporting purposes. Deferred tax assets are reduced by a valuation allowance if a determination is made that it is more likely than not that some or all of the deferred assets will not be realized based on the weight of all available evidence.





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





The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense. The federal income tax returns for 2009, 2010 and 2011 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 2012 and 2011, 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 2012 and 2011 whose purchases were 42% 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).




25




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 2012 and 2011:





2012


2011Beginning balance at January 1

$
990,074


$
848,631Liabilities incurred


126,551



116,487Liabilities settled (wells sold or plugged)


(4,116
)


(4,569
)Accretion expense


29,761



26,010Revision to estimate


19,808



3,515Ending balance at December 31

$
1,162,078


$
990,074





New Accounting Pronouncements





No new accounting standards that were issued or became effective during 2012 have had or are expected to have a material impact on the Company’s financial statements.





In February 2013, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update (“ASU” or “Update”) 2013-02, Comprehensive Income: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, which adds new disclosure requirements for items reclassified out of accumulated other comprehensive income (“AOCI”). The Update requires that the Company present either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of AOCI based on its source and the income statement line items affected by the reclassification. The guidance is effective for interim and annual reporting periods beginning on or after December 15, 2012. The Company does not anticipate that this guidance will have any impact on its financial statements.





In May 2011, the FASB issued ASU 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 ASU requires certain additional disclosures related to fair value measurements. The Company adopted this Update as of January 1, 2012 and the adoption did not materially impact its financial statement disclosures.





Reclassifications





Certain amounts in the 2011 financial statements have been reclassified to conform to the 2012 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.





26




Note 4 – COMMON STOCK





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





Shares ofShares


Treasury


SharesIssued


Stock


OutstandingJanuary 1, 2011, $.50 par value stock,400,000 shares authorized


184,735



23,456



161,279Purchase of stock


—



259



(259
)December 31, 2011, $.50 par value stock,400,000 shares authorized


184,735



23,715



161,020Purchase of stock


—



232



(232
)December 31, 2012, $.50 par value stock, 200,000 shares authorized


184,735



23,947



160,788





In June 2012, the Company amended its Certificate of Incorporation to change its shares authorized from 400,000 shares to 200,000 shares.





Note 5 – MARKETABLE SECURITIES





At December 31, 2012, 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 2012 the Company recorded realized gains of $6,359 and unrealized losses of $17,655. In 2011 the Company recorded realized gains of $73,334 and unrealized losses of $91,906.





Note 6 – INCOME TAXES





Components of deferred taxes are as follows:





December 31,2012


2011Assets:Net Leasehold Impairment Reserves

$
254,045


$
280,554Gas Balance Receivable


52,379



52,379Long-Lived Asset Impairment


1,293,338



940,713Other


211,091



173,286Total Assets


1,810,853



1,446,932Liabilities:Receivables


201,436



278,839Intangible Drilling Costs


4,000,766



3,308,603Depletion, Depreciation and Other


1,061,574



847,990Total Liabilities


5,263,776



4,435,432Net Deferred Tax Liability

$
(3,452,923
)

$
(2,988,500
)





The increase in the deferred tax liability for 2012 reflected in the above table is primarily the result of the Company’s increased current year drilling activity, which resulted in an increase in the intangible drilling costs. The lower bonus depreciation rate in 2012 on the lease and well equipment for successful wells (50% compared to 100% in 2011) resulted in a decrease in the 2012 deferred tax provision compared to 2011.




27




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





Year Ended December 31,2012


2011Current Tax Provision:Federal

$
1,153,057


$
620,591State


34,341



18,4451,187,398



639,036Deferred Provision


464,423



1,176,826Total Provision

$
1,651,821


$
1,815,862





The total provision for income tax expressed as a percentage of income before income tax was 27% for 2012 and 26% for 2011. These amounts differ from the amounts computed by applying the statutory U.S. federal income tax rate of 34% for 2012 and 2011 to income before income tax as summarized in the following reconciliation:





Year Ended December 31,2012


2011Computed Federal Tax Provision

$
2,109,926


$
2,412,266Increase (Decrease) in Tax From:Allowable Depletion in Excess of Basis


(540,969
)


(580,488
)Dividend Received Deduction


(136
)


(359
)State Income Tax Provision


34,341



18,445Other


48,659



(34,002
)Provision for Income Tax

$
1,651,821


$
1,815,862Effective Tax Rate


27
%


26
%





Note 7 – EQUITY INVESTMENT AND RELATED COMMITMENTS AND CONTINGENT LIABILITIES INCLUDING GUARANTEES





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 2012 and 2011.





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:





28





Year Ended December 31,2012


2011Acquisition of Properties:Unproved

$
227,050


$
476,658Proved


—



—Exploration Costs


2,713,181



2,953,503Development Costs


4,484,572



3,705,081Asset Retirement Obligation


146,359



120,002





Note 9 – FAIR VALUE MEASUREMENTS





Inputs used to measure fair value are organized into a fair value hierarchy based on how observable the inputs are. Level 1 inputs consist of quoted prices in active markets for identical assets. Level 2 inputs are inputs, other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs. During 2012 and 2011 there were no transfers into or out of Level 2 or Level 3.





Recurring Fair Value Measurements





Certain of the Company’s assets are reported at fair value in the accompanying balance sheets on a recurring basis. The Company determined the fair value of the available-for-sale securities using quoted market prices for securities with similar maturity dates and interest rates. At December 31, 2012 and 2011, the Company’s assets reported at fair value on a recurring basis are summarized as follows:





2012Level 1 Inputs


Level 2 Inputs


Level 3 InputsFinancial Assets:Available-for-Sale Securities –U.S. Treasury Bills Maturing in 2013

$
—


$
6,652,590


$
—Trading Securities:Domestic Equities


211,103



—



—International Equities


115,106



—



—Others


63,126



—



—
  2011Level 1 Inputs


Level 2 Inputs


Level 3 InputsFinancial 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



—



—





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 $126,551 in 2012 and $116,487 in 2011 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 $1,811,732 for 2012 and $828,071 for 2011 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, 2012 and 2011, 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.





29







Note 10 – LONG-LIVED ASSETS IMPAIRMENT LOSS





Certain oil and gas producing properties have been deemed to be impaired because the assets, evaluated on a property-by-property basis, are not expected to recover their entire carrying value through future cash flows. Impairment losses totaling $1,811,732 for 2012 and $828,071 for 2011 are included in the Statements of Income in the line item Depreciation, Depletion, Amortization and Valuation Provisions. The impairments for 2012 and 2011 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 2012 and 2011:




2012


2011Net Realized and Unrealized Gain (Loss) onTrading Securities

$
(11,296
)

$
(18,572
)Gains on Asset Sales


452,590



1,091,224Interest Income


32,434



22,774Settlements of Class Action Lawsuits


718



181Agricultural Rental Income


5,600



5,600Dividend Income


1,678



3,878Income from Other Investments


44,200



3,000Interest and Other Expenses


(34,562
)


(50,181
)Other Income, Net

$
491,362


$
1,057,904





Note 12 – CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS





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





Mesquite, Mid-American and LLTD share facilities and employees including executive officers with the Company. The Company has been reimbursed for services, facilities, and miscellaneous business expenses incurred in 2012 in the amount of $174,589 each by Mesquite, Mid-American and LLTD. Reimbursements in 2011 were $155,048 each by Mesquite, Mid-American and LLTD. Included in the 2012 amounts, Mesquite, Mid-American and LLTD each paid $124,988 for their share of salaries. In 2011, the share of salaries paid by Mesquite, Mid-American and LLTD was $113,873 each.





30







UNAUDITED SUPPLEMENTAL FINANCIAL INFORMATION








31




SUPPLEMENTAL SCHEDULE 1THE RESERVE PETROLEUM COMPANYWORKING INTEREST RESERVE QUANTITY INFORMATION(Unaudited)Year Ended December 31,2012


2011Oil and Natural Gas Liquids (Bbls)Proved Developed and Undeveloped Reserves:Beginning of Year


370,322



303,779Revisions of Previous Estimates


25,072



41,727Extensions and Discoveries


146,358



91,248Purchase of Reserves


—



—Production


(86,801
)


(66,432
)End of Year


454,951



370,322Proved Developed Reserves:Beginning of Year


370,322



303,779End of Year


454,951



370,322Gas (MCF)Proved Developed and Undeveloped Reserves:Beginning of Year


2,588,974



2,052,075Revisions of Previous Estimates


(111,215
)


501,889Extensions and Discoveries


1,766,753



504,193Purchase of Reserves


—



—Production


(610,032
)


(469,183
)End of Year


3,634,480



2,588,974Proved Developed Reserves:Beginning of Year


2,588,974



2,052,075End of Year


3,634,480



2,588,974See notes on next page.




32




SUPPLEMENTAL SCHEDULE 1




THE RESERVE PETROLEUM COMPANY


WORKING INTEREST RESERVE QUANTITY INFORMATION


(Unaudited)




Notes:





1.
Estimates of royalty interests’ reserves, on properties in which the Company does not own a working interest, have not been included because the information required for the estimation of such reserves is not available. The Company’s share of production from its net royalty interests was 20,606 Bbls of oil and 518,353 MCF of gas for 2012 and 18,198 Bbls of oil and 637,717 MCF of gas for 2011.





2.
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 2012 and 2011. 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.





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





4.
The Company’s internal controls relating to the calculation of its working interests’ reserve estimates include review and testing of the accounting data flowing into the calculation of the reserve estimates. In addition, the average oil and natural gas product prices calculated in the engineer’s 2012 summary reserve report was tested by comparison to 2012 average sales price information from the accounting records.




33




SUPPLEMENTAL SCHEDULE 2THE RESERVE PETROLEUM COMPANYSTANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWSRELATING TO PROVED WORKING INTERESTOIL AND GAS RESERVES(Unaudited)At December 31,2012


2011Future Cash Inflows

$
47,594,837


$
44,049,488Future Production and Development Costs


(14,711,266
)


(13,259,160
)Future Asset Retirement Obligation


(1,499,238
)


(1,340,919
)Future Income Tax Expense


(6,744,346
)


(6,677,879
)Future Net Cash Flows


24,639,987



22,771,53010% Annual Discount for Estimated Timing of Cash Flows


(7,621,558
)


(6,716,410
)Standardized Measure of Discounted Future Net Cash Flows

$
17,018,429


$
16,055,120





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 2011 and 2012, 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.





34




SUPPLEMENTAL SCHEDULE 3THE RESERVE PETROLEUM COMPANYCHANGES IN STANDARDIZED MEASURE OFDISCOUNTED FUTURE NET CASH FLOWS FROMPROVED WORKING INTEREST RESERVE QUANTITIES(Unaudited)Year Ended December 31,2012


2011Standardized Measure, Beginning of Year

$
16,055,120


$
10,429,195Sales and Transfers, Net of Production Costs


(7,431,704
)


(6,217,245
)Net Change in Sales and Transfer Prices, Net of Production Costs


(2,076,678
)


2,785,761Extensions, Discoveries and Improved Recoveries,Net of Future Production and Development Costs


9,250,745



5,751,088Revisions of Quantity Estimates


184,782



2,997,976Accretion of Discount


2,020,364



1,325,458Purchases of Reserves in Place


—



—Net Change in Income Taxes


(217,583
)


(1,648,334
)Net Change in Asset Retirement Obligation


(142,243
)


(115,433
)Changes in Production Rates (Timing) and Other


(624,374
)


746,654Standardized Measure, End of Year

$
17,018,429


$
16,055,120





35




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, 2012.





Management's Annual Report on Internal Control over Financial Reporting





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





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





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





With the participation of the Principal Executive Officer and Principal Financial Officer, the Company’s management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting, based on the framework and criteria established in Internal Control-Integrated Framework 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, 2012.




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. TylerCameron R. McLain, President

James L. Tyler, 2nd Vice PresidentPrincipal Executive Officer

Principal Financial OfficerMarch 28, 2013

March 28, 2013
  36
  Changes in Internal Control over Financial Reporting





Management of the Company, with the participation of the Principal Executive Officer and Principal Financial Officer, evaluated the internal control over financial reporting and concluded that no change in the Company’s internal control over financial reporting occurred during the fourth quarter ended December 31, 2012 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.





ITEM 9B.
OTHER INFORMATION





None.




PART III




ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE





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





ITEM 11.
EXECUTIVE COMPENSATION





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





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





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





ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE





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





ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES





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




37




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.





ExhibitNumber

Description3.1*

Restated Certificate of Incorporation dated June 1, 2012.3.2

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 Document101.SCH*#

XBRL Taxonomy Extension Schema Document101.CAL*#

XBRL Taxonomy Calculation Linkbase Document101.LAB*#

XBRL Taxonomy Label Linkbase Document101.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.





38





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. McLainBy:
Cameron R. McLain, President(Principal Executive Officer)/s/ James L. TylerBy:
James L. Tyler, 2nd Vice President(Principal Financial Officer)





Date:  March 28, 2013








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




/s/ Kyle L. McLain

/s/ Jerry L. CrowKyle L. McLain (Director)

Jerry L. Crow (Director)March 28, 2013

March 28, 2013






/s/ Robert L. Savage

/s/ William M. SmithRobert L. Savage (Director)

William M. Smith (Director)March 28, 2013

March 28, 2013
   39