**UNITED STATES**


**SECURITIES AND EXCHANGE COMMISSION**


Washington, D.C. 20549


**FORM 10-KSB**


(Mark One)


[ X ]
**ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE****SECURITIES EXCHANGE ACT OF 1934**For the fiscal year ended December 31, 2004[ ]
T**RANSITION REPORT UNDER SECTION 13 OR 15 (d) OF THE****SECURITIES EXCHANGE ACT OF 1934**


Commission file number 0-8157


THE RESERVE PETROLEUM COMPANY


(Name of small business issuer in its charter)





Delaware
73-0237060(State or other jurisdiction of
(IRS Employerincorporation or organization)
identification number)6801 N. Broadway, Suite 300, Oklahoma City, Oklahoma
73116-9092(Address of principal executive offices)
(Zip Code)Issuers telephone number:
(405)848-7551


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


Securities registered under Section 12(g) of the Act: Common stock $.50 Par Value (Title of Class)
 
 Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act during the past 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 X  NO _
 
 Check if disclosure of delinquent filers in response to Item 405 of Regulation S-B is not contained in this form, and no disclosure will 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-KSB or any amendment to this Form 10-KSB. [ X ]
 
 Issuers revenues for the fiscal year ended December 31, 2004 were $4,264,546. As of March 18, 2005, there were 165,172.64 common shares outstanding. The aggregate market value of the voting stock held by non-affiliates was $6,458,018 as determined by the last reported sale which was February 17, 2005.
 
 DOCUMENTS INCORPORATED BY REFERENCE
 Items 9, 10 and 11 required by Part III, are incorporated herein by reference to the Companys proxy statement to be mailed to security holders on or about April 22, 2005, in connection with its annual stockholders meeting to be held on May 24, 2005.
 Transitional Small Business Disclosure Format (check one) Yes __   No X
 
 See Exhibit Index on Page 42.


1








TABLE OF CONTENTS








PageForward Looking Statements
3PART IItem 1.
Description of Business
3Item 2.
Description of Properties
5Item 3.
Legal Proceedings
7Item 4.
Submission of Matters to a Vote of Security Holders
7PART IIItem 5.
Market for Common Equity and Related Stockholder Matters
7Item 6.
Managements Discussion and Analysis of Financial Condition andResults of Operations
8Item 7.
Financial Statements
20Item 8.
Changes in and Disagreements with Accountants on Accounting andFinancial Disclosure
41Item 8a.
Controls and Procedures
41PART IIIItem 9.
Directors, Executive Officers, Promoters and Control Persons Compliance with Section 16(a) of the Exchange Act
42Item 10.
Executive Compensation
42Item 11.
Security Ownership of Certain Beneficial Owners and Management
42Item 12.
Certain Relationships and Related Transactions
42Item 13.
Exhibits and Reports on Form 8-K
42Item 14.
Principal Accountant Fees and Services
43







2    Forward-Looking Statements.
 
 This report 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 6, 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.
 
 PART I
 
 Item 1. Description of Business.
 
 The Reserve Petroleum Company (the Company) is engaged principally in 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, Description of 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 6, Managements Discussion and Analysis of Financial Condition and Results of Operations.
 
 Mineral Property Management.
 
 The Company owns non-producing mineral interests in approximately 268,553 gross acres equivalent to 92,606 net acres. These mineral interests are located in nine states with 56,246 net acres in the states of Oklahoma and Texas, the area of concentration for the Company in its present exploration and development programs.
 
 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 costs for any exploration or development drilling.
 
 A substantial amount of the Companys oil and gas revenue has resulted from its mineral property management. In 2004, $2,024,362 (52%) of oil and gas sales were from royalty interests as compared to $1,491,672 (52%) in 2003. As a result of its mineral ownership, in 2004 the Company had royalty interests in 29 gross (.45 net) wells which were drilled and completed as producing wells. See the following paragraphs for a discussion of mineral interests in which the Company chooses to participate as a working interest owner.
 
 3
 Development Program.
  The development of a drilling program is usually initiated in one of three ways. The Company may participate as a working interest owner with a third party operator in the development of non-producing mineral interests which it owns; along with the 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 development of additional wells on the exploratory prospect. In 2004, the Company participated in the drilling of nine development wells with all nine wells (1.01 net) completed as producers.
 
 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.
 
 For a summation of exploratory wells drilled in 2004 or planned for in 2005, see Item 6, Managements Discussion and Analysis of Financial Condition and Results of Operations, subheading, Update of Oil and Gas Exploration Activity from December 31, 2003.
 
 Customers.
 
 In 2004, the Company had one customer whose total purchases were greater than 10% of revenues from oil and gas sales. The purchases were $760,446 or 19.4% of total oil and gas sales. The Company sells most of its oil and gas under short-term sales contracts that are based on the spot market price. A minor amount of oil and gas sales are made under fixed price contracts having terms of more than one year.
 
 Competition.
 
 The oil and gas industry is highly competitive in all of its phases. There are numerous circumstances within the industry and related market place that are out of the Companys control such as cost and availability of alternative fuels, the level of consumer demand, the extent of other domestic production of oil and gas, the price and extent of importation of foreign oil and gas, the cost of and proximity of pipelines and other transportation facilities, the cost and availability of drilling rigs, regulation by state and Federal authorities and the cost of complying with applicable environmental regulations. The Company is a very minor factor in the industry and must compete with other persons and companies having far greater financial and other resources. The Companys ability to participate in and/or develop viable prospects, and secure the financial participation of other persons or companies in exploratory drilling on these prospects is limited.
 
 4
 Regulation.
 
 The Companys operations are affected in varying degrees by political developments and Federal and state laws and regulations. Although released from Federal price controls, interstate sales of natural gas are subject to regulation by the Federal Energy Regulatory Commission (FERC). Oil and gas operations are affected by environmental laws and other laws relating to the petroleum industry and both are affected by constantly changing administrative regulations. Rates of production of oil and gas have for many years been subject to a variety of conservation laws and regulations, and the petroleum industry is frequently affected by changes in the Federal tax laws.
 
 Generally, the respective state regulatory agencies supervise various aspects of oil and gas operations within the state and transportation of oil and gas sold intrastate.
 
 Environmental Protection.
 
 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 as well as the contamination of subsurface formations. The Companys lease operations and exploratory activity have been and will continue to be affected by regulation in future periods. However, the known effect to date has not been material as to capital expenditures, earnings or industry competitive position nor are estimated expenditures for environmental compliance expected to be material in the coming year. Such expenditures produce no increase in productive capacity or revenue and require more of managements time and attention, a cost which cannot be estimated with any assurance of certainty.
 
 Other Business.
 
 See Item 6, Managements Discussion and Analysis of Financial Conditions and Results of Operations, subheading, Equity Investments and Item 7, Notes to Financial Statements, Note 2, for a discussion of other business including guarantees.
 
 Employees.
 
 At December 31, 2004, the Company had eight employees, including officers. See Proxy Statement for Annual Stockholders Meeting for additional information. During 2004, 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 6, Managements Discussion and Analysis of Financial Conditions and Results of Operations, subheading Certain Relationships and Related Transactions and Item 7, Notes to Financial Statements, Note 12, for additional information.
 
 Item 2. Description of Properties.
 
 The Companys principal properties are oil and natural gas properties as described below.
 
 Oil and Natural Gas Operations.
 Oil and Gas Reserves.
 
 Reference is made to the unaudited supplemental financial information beginning on Page 37 for working interest reserve quantity information.
 
 5
 
 Since January 1, 2004, the Company has filed no reports with any Federal authority or agency which included estimates of total proved net oil or gas reserves, except for its 2003 annual report on Form 10-KSB and Federal income tax return for the year ended December 31, 2003. 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, 2004, 2003 and 2002. Equivalent MCF was developed 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 MCF2004

$
38.79

$
5.42

$
40.47

$
5.65

$
1.612003

$
28.72

$
4.82

$
28.54

$
4.81

$
1.562002

$
24.59

$
2.86

$
24.22

$
2.70

$
1.41
 
 At December 31, 2004, the Company had working interests in 104 gross (12.08 net) wells producing primarily gas and/or gas liquids (condensates) and had working interests in 74 gross (4.65 net) wells producing primarily oil. These interests were in 39,465 gross (4,371 net) producing acres. These wells include 39 gross (.20 net) wells associated with secondary recovery projects.
 
 Twenty-seven percent, or 6,700 barrels of the Companys oil production during 2004 was derived from royalty interests in mature West Texas water-floods.
 
 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, 2004.
 
 AcreageGross


NetNon-producing Mineral Interests


268,553


92,606Undeveloped Leaseholds


13,914


3,859
 
  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, 2002 and thereafter, as to net productive and dry exploratory wells drilled and net productive and dry development wells drilled.
  6
 
 Number of Net Working Interest Wells DrilledExploratory

DevelopmentProductive

Dry

Productive

Dry2004


1.03


.50


1.01


----2003


.46


.16


.19


.282002


.96


.47


.01


----
 
 Recent Activities.
 
 See Item 6, under the subheading, Update of Oil and Gas Exploration Activity from December 31, 2003 for a summary of recent activities related to oil and natural gas operations.
 
 Item 3. Legal Proceedings.
 There are no material pending legal proceedings affecting the Company or any of its properties.
 Item 4. Submission of Matters to a Vote of Security Holders.
 
 Not Applicable.
 
 
 PART II
 
 Item 5. Market for Common Equity and Related Stockholder Matters.
 
 The Companys stock is traded over the counter in the United States. The following high and low bid information is quoted on the pink sheets OTC Market Report. Prices do not include retail markup, markdown or commission.
 
 Quarterly RangesQuarter Ending
High Bid
Low Bid03/31/03
32.65
32.6006/30/03
33.25
32.6509/30/03
35.00
33.2512/31/03
35.00
35.0003/31/04
35.30
35.0006/30/04
39.00
35.3009/30/04
41.25
36.0012/31/04
55.00
42.50
 
 There was limited public trading in the Companys common stock in 2004 and 2003. In 2004, there were 9 brokered trades appearing in the Companys transfer ledger, and in 2003, there were 12.
 
 At March 18, 2005, the Company had approximately 1,458 record holders of its common stock. The Company paid dividends on its common stock in the amount of $1.00 per share in the second quarter of 2004 and $1.00 per share in 2003. Management will review the amount of the annual dividend to be paid in 2005 with the board of directors; however, it intends to recommend a dividend of at least $1.00 per share.
 
 7
 
 Item 6. Managements Discussion and Analysis of Financial Condition and Results of Operations.
 
 Please refer to the financial statements and related notes in Item 7 of this Form 10-KSB 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 give 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.
 
 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.
 
 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 the most significant component of the Companys capital expenditures and are expected to remain so, at least in the near term. Under the successful efforts method of accounting for oil and gas properties which the Company uses, these costs are capitalized if the prospect is successful, or charged to operating costs and expenses if unsuccessful. Estimating the amount of such future costs which may relate to successful or unsuccessful prospects is extremely imprecise, at best.
 
 8
 The provisions for depreciation, depletion and amortization of oil and gas properties constitute a particularly sensitive accounting estimate. Non-producing leaseholds are amortized over the life of the leasehold using a straight line method; however, when a leasehold is impaired or condemned, an appropriate adjustment to the provision is made at that time. Forward-looking estimates of such adjustments are very imprecise. 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 unforecasted change in the estimated depletion and depreciation provisions.
 
 Income from available for sale securities and trading securities have made substantial contributions to net income in certain prior periods. Available for sale securities and trading securities are used to invest funds until needed in the Companys capital investing and financing activities. Net income has been materially affected in past and current years and could be in the future years by utilization of those funds in operations as well as significant fluctuation in the interest rates and/or quoted market values applicable to the Companys available for sale securities and trading securities.
 
 The Companys trading securities consist primarily of equity securities. These securities are carried at fair value with unrealized gains and losses included in earnings. The equity securities are traded on various stock exchanges and/or the NASDAQ and over the counter markets. Therefore, these securities are market-risk sensitive instruments. The stock market is subject to wide price swings in short periods of time.
 
 The Company has equity investments in organizations over which the Company has limited or no control. These equity investments have in the past made substantial contributions to the Companys net income. The management of these entities could at any time make decisions in their own best interests which could materially affect the Companys net income, or the value of the Companys investments. See Equity Investments, below, in this Item 6 for information regarding these equity investments.
 
 The Reserve Petroleum Company undertakes no 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-QSB to be filed by the Company in 2005 and any Current Reports on Form 8-K filed by the Company. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements.
 
 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 and Robert T. McLain, Directors and officers of the Company, are directors and officers of Mesquite and Mid-American. Jerry Crow, a Director of the Company, is a director of Mesquite and Mid-American. Kyle McLain and Cameron R. McLain are sons of Mason McLain, who is a more than 5% owner of the Company, and are advisory directors and employees of the Company. Kyle McLain is a director and employee of Mesquite and an advisory director and employee of Mid-American. Cameron R. McLain is a director and employee of Mid-American and an advisory director and employee of Mesquite. 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.
 
 9
 The above named officers, directors and employees as a group beneficially own approximately 34% of the common stock of The Reserve Petroleum Company, approximately 30% 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. Item 7, Notes to Financial Statements, Note 12 includes additional disclosures regarding these relationships.
  Equity Investments
 
 The Company has investments in four entities which it accounts 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 four entities include one Oklahoma limited partnership, and three Oklahoma limited liability companies. The Company does not have actual or effective control of any of the entities. The management of these entities could at any time make decisions in their own best interests which could materially effect the Companys net income, or the value of the Companys investments.
 
 These entities are Broadway Sixty-Eight, Ltd. (33% limited partnership interest), Millennium Golf Properties, LLC (9% ownership), OKC Industrial Properties, LLC (10% ownership) and JAR Investments, LLC (25% ownership). These entities collectively and/or individually have had a significant effect, both positively, and negatively, on the Companys net income in the past and are expected to in the future. Two of these entities have guarantee arrangements under which the Company is contingently liable. Item 7, Note 7 to the accompanying financial statements includes related disclosures.
 
 Liquidity and Capital Resources
 
 To supplement the following discussion please refer to the Balance Sheets on Pages 22 and 23, and the Statements of Cash Flows beginning on page 26 of this Form 10-KSB.
 
 In 2004, 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. Available for sale securities are primarily US Treasury Bills and bank certificates of deposits.
 
 In 2004, net cash provided by operating activities was $2,876,698. Settlements of class action lawsuits of $297,196 represent 10% of the net cash provided by operations. Sales, net of production, exploration and general and administrative costs of $2,549,608 accounted for 89% operations net cash flow. The remaining components provided $29,894 or 1% of cash flow. In 2004, net cash applied to investing and financing activities was $2,652,368. Net purchases of available for sale securities discussed below, capitalized property additions (net of disposals) of $2,102,080 and dividend payments and treasury stock purchases of $168,972 accounted for most of the net cash applied. Maturing available for sale securities provided $7,880,588 of gross cash flow due to their six month maturities. However, these funds plus $452,816 of excess cash from operations were re-invested in the same type of securities.
 
 10
 In 2003, cash utilized for capitalized property additions of $1,283,344 and dividend payments and treasury stock purchases of $181,664 were $14,537 less than cash provided by operating activities.
 
 Other than cash, cash equivalents and available for sale securities, other significant changes in working capital include the following:
 
 Receivables increased $232,305 (53%) to $669,008 in 2004 from $436,703 in 2003. For the most part, the increase was the result of increased oil and gas product prices and volumes used for the Companys accrual estimates at year end.
 
 Refundable income taxes decreased $34,685 (100%) to $ -0- in 2004 from $34,685 in 2003. This was due to the offset of prior year estimated income tax over-payments against 2004 current tax liabilities.
 
 Accounts payable increased $130,961 (337%) to $169,823 in 2004 from $38,862 in 2003. This increase was primarily due to costs associated with increased drilling activity at year end 2004 versus 2003. See the discussion of this activity under Update of Oil and Gas Exploration and Development Activity from December 31, 2003 in the Results of Operations section below.
 
 The following is a discussion of material changes in cash flow by activity between the years ending December 31, 2004 and 2003. Also see the discussion of changes in operating results under Results of Operations below in this Item 6.
 
 Operating Activities.
 
 As noted above, net cash flows provided by operating activities in 2004 were $2,876,698, which when compared against the $1,479,545 provided in 2003, represents an increase of $1,397,153 or a 94% increase in net cash flows provided by operating activities from 2003 to 2004. For the most part, the increase resulted because of an increase in oil and gas sales of $1,071,389, an increase in lease bonuses and rentals of $273,934, a decrease in exploration costs charged to expense of $46,547, and an increase in class action lawsuit settlements of $288,872. Those increases in cash flows were partially offset by increased production costs of $97,587, a decrease in interest income of $16,922, and a decrease in refunds of income taxes of $205,743. Additional discussion of the more significant items follows.
 
 Discussion of Selected Material Line Items Resulting in an Increase in Cash Flows. The $1,071,389 (40%) increase in cash received from oil and gas sales to $3,762,604 in 2004 from $2,691,215 in 2003 was the result of an increase of both the price and volume of both oil and gas sales. See Results of Operations, below, for a price/volume analysis and the related discussion of oil and gas sales.
 
 Lease bonuses and rentals increased $273,934 (771%) to $309,451 in 2004 from $35,517 in 2003. This increase was primarily due to lease bonuses received in 2004 for leases located in Tyler and Robertson Counties in East Texas for longer term leases. There were no similar bonuses in 2003 as most leases were for six months.
  11
 Cash paid for exploration costs charged to expense decreased $46,547 (25%) to $139,151 in 2004 from $185,698 in 2003. This decrease is related to an increase in successful exploration activity in 2004 over 2003. This item consists of unsuccessful exploratory drilling expenditures as well as geological and geophysical costs that are directly related to the Companys oil and gas exploration drilling activity. That drilling activity also includes substantially all of the Companys property additions discussed below under the subheading Investing Activities. In addition to the $139,151 classified as operating activities, $2,183,687 was classified as investing activities for a total of $2,322,838. This compares to 2003 cash applied to property additions which included $185,698 classified as operating activities and $1,317,192 classified as investing activities for a total of $1,502,890.
 
 Cash received for class action lawsuit settlements increased $288,872 (3,470%) to $297,196 in 2004 from $8,324 in 2003. The increase was due entirely to the settlement of a class action lawsuit filed in 1995 relating to revenues received after 1982 from Company owned minerals in Texas County, Oklahoma.
  Discussion of Selected Material Line Items Resulting in an Decrease in Cash Flows. Production costs increased $97,587 (19%) to $602,551 in 2004 from $504,964 in 2003. Part of the increase was due to a $41,274 increase in production taxes which increase as oil and gas sales increase. The remaining increase of $56,313 was due to increased lease operating expenses in 2004 versus 2003.
  Cash received for interest earned on cash equivalents and available for sale securities decreased $16,922 (30%) to $39,500 in 2004 from $56,422 in 2003. The decrease was primarily the result of a decline in the average rate of return to 0.88% in 2004 from 1.28% in 2003 with an average balance of cash equivalents and available for sale securities outstanding of $4,475,655 in 2004 and $4,423,599 in 2003.
 
 Income taxes refunded decreased $205,743 (100%) to $-0- in 2004 from $205,743 in 2003. The 2003 refunds were the result of net capital and operating losses from 2002 carried back to offset prior years taxable income.
  Investing Activities.
  Net cash applied to investing activities increased $1,217,206 (96%) to $2,483,396 in 2004 from $1,266,190 in 2003. In 2004, net cash flows from available for sale securities decreased $460,420 from cash provided of $7,604 in 2003 to cash applied of $452,816 in 2004, as a result of cash invested from excess 2004 cash flows provided by operations. Withdrawals of $7,604 were minimal in 2003 since 2003 operations provided all necessary cash flows as discussed above. Most of the additional net cash applied to investing activities is due to a $866,495 net increase in the application of cash to capitalized property additions, discussed above. In 2004, net cash flows applied to capitalized property were $2,102,080 as compared to $1,283,344 in 2003.
  Financing Activities.
  Cash applied to financing activities decreased $12,692 (7%) to $168,972 in 2004 from $181,664 in 2003. Cash flows applied to financing activities consist of cash dividends on common stock and cash used for the purchase of treasury stock. In 2004, cash dividends paid on common stock amounted to $155,052 as compared to $157,597 in 2003. The decrease was the result of a decrease in the shares of stock outstanding in 2004 from 2003 as the 2004 dividends per share of $1.00 remained unchanged from 2003. Cash applied to the purchase of treasury stock was $13,920 in 2004 as compared to $24,067 in 2003.
  12
 Forward-Looking Summary.
  The latest estimate of business to be done in 2005 and beyond indicates the projected activity can be funded from cash flow from operations and other internal sources including net working capital. The Company is engaged in exploratory drilling. If this drilling is successful, substantial development drilling may result. Also, should other exploration projects which fit the Companys risk parameters become available, or other investment opportunities become known, capital requirements may be more than the Company has available. If so, external sources of financing could be required.
  Results of Operations
  As disclosed in the Statements of Operations in Item 7, of this Form 10-KSB, in 2004 the Company had net income of $1,748,991 as compared to a net income of $499,886 in 2003. Net income per share, basic and diluted was $10.56 in 2004, an increase of $7.56 per share from $3.00 in 2003. Material line item changes in the Statements of Operations will be discussed in the following paragraphs.
  Operating Revenues.
  Operating revenues increased $1,354,764 (47%) to $4,264,546 in 2004 from $2,909,782 in 2003. Oil and gas sales increased $1,068,538 (37%) to $3,921,384 in 2004 from $2,852,846 in 2003. In addition lease bonuses and other increased $286,226 (503%) to $343,162 in 2004 from $56,936 in 2003. The increase in lease bonuses and other was, for the most part, the result of the 2004 lease bonuses received on Robertson and Tyler County, Texas, minerals which the Company owns with no similar lease bonuses in 2003. The increase in oil and gas sales will be discussed in the following paragraphs.
  The $1,068,538 increase in oil and gas sales was the net result of a $674,598 increase in gas sales plus a $344,357 increase in oil sales and a $49,583 increase in miscellaneous oil and gas product sales. The following price and volume analysis is presented to help explain the changes in oil and gas sales from 2003 to 2004. Miscellaneous oil and gas product sales of $64,694 in 2004 and $15,111 in 2003 are not included in the analysis.
  VarianceProduction

2004

Price

Volume

2003Oil -Bbls (000 omitted)


25





3


22$(000 omitted)

$
983

$
272

$
72

$
639Unit Price

$
39.62

$
10.97




$
28.65Gas -MCF (000 omitted)


519





63


456$(000 omitted)

$
2,873

$
372

$
303

$
2,198Unit Price

$
5.53

$
.71




$
4.82
 
 The $674,598 (31%) increase in natural gas sales to $2,873,036 in 2004 from $2,198,438 in 2003 was the result of an increase in both the price and volume of sales. A positive price variance of $371,973 resulted because the average price received per thousand cubic feet (MCF) of natural gas sales increased $.71 per MCF to $5.53 in 2004 from $4.82 in 2003. A positive volume variance of $302,625 resulted from an increase in volume sold of 62,786 MCF to 519,198 MCF in 2004 from 456,412 in 2003. The increase in the volume of production was the net result of production of 183,506 MCF from properties which first produced in 2004 as partially offset by a 120,721 MCF normal decline in production from mature producing properties. As disclosed in Supplemental Schedule 1 of the Unaudited Supplemental Financial Information included in Item 7, below, working interests in natural gas extensions and discoveries were adequate to replace reserves produced in 2004 but not 2003. However, purchases of reserves in place in 2003 when added to extensions and discoveries for 2003 were adequate to replace reserves produced in 2003.
 
 13
 The $344,357 (54%) increase in crude oil sales to $983,653 in 2004 from $639,296 in 2003 was the result of an increase in both the average price per barrel and oil sales volumes. The average price received per barrel (Bbl) of oil increased $10.97 (38%) to $39.62 per Bbl in 2004 from $28.65 per Bbl in 2003 resulting in an increase in oil sales of $272,383. An increase in oil sales volumes of 2,512 Bbls to 24,827 Bbls in 2004 from 22,315 Bbls in 2003 resulted in a positive volume variance of $71,974. The positive volume variance was the net result of production of 6,976 Bbls from properties which first produced in 2004 as partially offset by a 4,464 Bbls normal decline in production from mature producing properties. As disclosed in Supplemental Schedule 1 of the Unaudited Supplemental Financial Information included in Item 7 below, working interests in oil extensions and discoveries were adequate to replace reserves produced in 2004 and 2003.
 
 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 $174,385 (8%) to $2,462,437 in 2004 from $2,288,052 in 2003, primarily due to increases in production costs and depreciation, depletion and amortization. The material components of operating costs and expenses will be discussed below.
 
 Production Costs. Production costs increased $111,010 (22%) to $620,492 in 2004 from $509,482 in 2003. For the most part, the increase was the net result of a $41,274 (26%) increase in gross production tax to $200,906 in 2004, from $159,632 in 2003, plus an increase in lease operating expense of $59,148 (19%) to $368,445 in 2004 from $309,297 in 2003. The increase in lease operating expense was the result of the additional costs of wells which first produced in late 2003 or in 2004. Gross production taxes are state taxes which are calculated as a percentage of gross proceeds from the sale of products from each producing oil and gas property; therefore, they fluctuate with the change in the dollar amount of revenues from oil and gas sales.
 
 Exploration 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 are capitalized. Total costs of exploration, inclusive of geological and geophysical costs were $2,322,918 in 2004 and $1,474,140 in 2003. Costs charged to operations were $139,231 in 2004 and $156,948 in 2003 inclusive of geological and geophysical costs of $36,420 in 2004 and $41,645 in 2003.
 
 Update of Oil and Gas Exploration and Development Activity from December 31, 2003.  For the twelve months ended December 31, 2004, the Company participated in the drilling of 14 gross exploratory and 9 gross development working interest wells with net working interests ranging from a high of 18% to a low of 2.5%. Of the fourteen exploratory wells, two were plugged, abandoned and charged to expense and eleven were completed as producers. The well bore and downhole equipment of the remaining dry hole were sold to a third party with the mineral rights to a potentially productive zone in which the Company had no mineral rights. The difference between the sales price and the Companys costs to drill the well were expensed in 2004. Of the nine development wells, all were completed as producers. In managements opinion, the exploratory drilling summarized above has produced some possible development drilling opportunities which could increase the Companys oil and gas reserves.
 
 14
 The following is a summary as of March 10, 2005, updating both exploration and development activity from December 31, 2003.
 
 In 2001 the Company purchased an 18% working interest in a Barber County, Kansas prospect. Two exploratory wells were drilled in 2002. The first was completed as a commercial oil well and the second as a marginal gas well. Following a 3-D seismic survey, a third well was drilled and completed as a commercial gas well in 2003 and a pipeline was constructed to gather the gas. Also in 2003, an offset to the third well was drilled and completed as a commercial oil and gas producer and a second 3-D seismic survey was conducted on land adjoining the original survey. A fifth well was commenced in May 2004 and completed in June 2004 as a commercial oil and gas well. A sixth well was drilled and completed in September 2004 as a commercial gas well. Two or three additional wells will be drilled in 2005. Capitalized costs for the year ended December 31, 2004 were $125,157.
 
 The Company participated in the development of a Bryan County, Oklahoma prospect with a 50% interest in 656 net acres of leasehold. In October 2004 the Company sold a portion of its interest and will participate with a 9% working interest in the drilling of an exploratory well in the second or third quarter of 2005.
 
 The Company participated in the development of a Woods County, Oklahoma prospect retaining a 16% working interest in the initial drillsite section and a 17.5% interest in offsetting acreage. An exploratory well was drilled and completed in 2003 as a commercial oil and gas producer. An offset well was commenced in March 2004 and completed in April 2004. The zone was non-commercial, but a sale of the well in November 2004 allowed the Company to recover most of its costs.
 
 In 2003 the Company purchased a 5% working interest in 1,415 net acres of leasehold outside of the initial drillsite section on a Dewey County, Oklahoma prospect. The Company owns approximately 28 net acres of minerals in the drillsite section with which it participated in the drilling and completion of the initial test well, resulting in a marginal oil and gas producer. A second well was started in February 2004 and completed in April 2004 as a marginal oil well. Drilling costs of $115,819 for both wells were capitalized as of December 31, 2004. However, an impairment expense of approximately $69,000 has been charged against these wells in 2004.
 
 In 2003 the Company participated with a 14.44% working interest in the drilling of an exploratory well on a Coal County, Oklahoma prospect. The well was completed in February 2004 and swab tested for oil production. In September 2004 a pumping unit and surface production facilities were installed. The well is a marginal oil producer, and an impairment expense of $121,526 has been charged against the well. Capitalized costs for the year ended December 31, 2004 were $163,690.
 
 In 2003 the Company agreed to participate with a fee mineral interest in a proposed waterflood unit in Harding County, South Dakota. The unit became effective on June 1, 2003, with the Company having a 0.96% working interest during Phase I and a 4.32% interest during Phase II. Opposing horizontal laterals were drilled from an existing vertical wellbore and the well began producing oil in July 2003. It was to be produced for several months and then converted to water injection. Another horizontal well was started in October 2003. It was completed and began pumping oil at a high rate in January 2004. It was also to be produced for several months and then converted to water injection; however, the high oil production rate led to a decision to postpone the conversion indefinitely. In April 2004 a vertical wellbore was drilled and casing was set. In May 2004 operations were commenced to drill opposing horizontal laterals from that wellbore and to drill a second lateral from an existing horizontal well. This work was successfully completed in June 2004 and by July 2004 there were six horizontal oil producers in the unit. Water injection into one of the wells should commence in June 2005. Capitalized costs for the year ended December 31, 2004 were $23,960.
 
 15
 In 2003 the Company purchased an interest in a Dewey County, Oklahoma prospect. It participated with an 8% working interest in the drilling of an exploratory well which was successfully completed as a commercial gas and gas condensate producer. An offset well, in which the Company has a 5.48% working interest, was started in March 2004 and completed in April 2004 as a commercial gas and gas condensate producer. An offset to the second well (Company working interest 2.49%) was started in November 2004 and completed in December 2004 as a commercial gas and gas condensate producer. An offset to the first well (Company working interest 6%) will be commenced in March 2005 and a fifth well (Company working interest 5.4%) will be drilled later in 2005. Drilling costs of $104,061 were capitalized as of December 31, 2004.
 
 In February 2005 the Company participated in the drilling of a step-out well in Morton County, Kansas with a 19.6% working interest. Casing was set and a completion attempt is currently in progress.
 
 In 2003 the Company agreed to farm out 75% of its 16% working interest in a marginal producing gas well in Hansford County, Texas and to participate with its remaining 4% interest in the drilling of a horizontal lateral from that wellbore. Drilling commenced in January 2004 and the well began producing gas in February 2004 at a marginal rate. Drilling costs of $8,951 were capitalized as proved properties in 2004, and an impairment expense of $5,766 was charged against the well.
 
 In March 2004 the Company agreed to participate in the drilling of two step-out wells on a Woods County, Oklahoma prospect in which it has an 18% working interest. Both wells were drilled and completed in June and July 2004 and sales commenced in September 2004. Both are commercial gas producers. The Company participated with an 11.7% working interest in the acquisition of additional acreage and the drilling and completion of another step-out well in September and October 2004. The current zone appears to be non-commercial and a completion will be attempted in another zone. The Company also participated in the recompletion of the original prospect well in October 2004, resulting in improved production. An impairment expense of $23,388 was charged against the original well. Two additional development wells will be drilled in 2005. Drilling costs total $224,771 as of December 31, 2004.
 
 In January 2004 the Company agreed to purchase for $94,960 a 7% interest in leases covering 54,263 mineral acres in Gentry, Harrison, Nodaway and Worth Counties, Missouri and to participate in the drilling of three stratigraphic tests and one core test in an effort to develop the area for coalbed methane production. The three stratigraphic tests were drilled in July 2004 and the core test was drilled in November 2004. The coals encountered did not contain commercial quantities of gas and the project will not be pursued at this time. Drilling costs of $25,760 were charged to exploration expense as of December 31, 2004.
 
 16
 In January 2004 the Company purchased a 15% interest in 1,397 net acres of leasehold on a Canadian County, Oklahoma prospect for $94,536 (including prospect and geological fees) and agreed to participate in the drilling of five exploratory wells. The five wells, in which the Company has working interests of 7.3%, 8.5%, 6.1%, 15% and 8.5% respectively, have been drilled and completed. The first and third wells are producing oil and gas at marginal rates. The other three wells are commercial oil and gas producers. A development well (Company working interest 7.3%) was drilled in November 2004 and completed in December 2004 for marginal production. This well was recompleted in February 2005 and appears to be a commercial oil and gas producer. Two more development wells (Company working interests 6.1% and 3.8%) were drilled in January and February 2005. Both are awaiting completion attempts. Three additional development wells will be drilled in 2005 (Company working interests 7.5%, 8.5% and 15%). Drilling costs total $695,438 as of December 31, 2004, including prepaid drilling costs, and an impairment expense for the marginal wells of $44,393.
 
 In January 2004 the Company purchased a 16% interest in 1,450 net acres of leasehold on an Alfalfa County, Oklahoma prospect for $17,400. An exploratory well was started in January 2004 and completed in February 2004 testing water and a small amount of gas. An attempt to remediate formation damage and a poor cement job was unsuccessful and the well was temporarily abandoned. A replacement well was drilled in May 2004 to test the prospect. It was plugged and abandoned. No further drilling is planned. Drilling costs of $79,408 have been charged as exploration expense as of December 31, 2004.
 
 In January 2004 the Company purchased a 16% interest in 442 net acres of leasehold on a Creek County, Oklahoma prospect for $7,076. An exploratory well was commenced in January 2004 and casing was set. A completion attempt in one zone resulted in marginal gas production. A second completion attempt in a shallower zone appeared to result in commercial gas production. However, after commencing sales in May 2004, gas volumes declined rapidly. The two zones were commingled in October 2004 and the well is now a marginal producer, and an impairment expense of $20,282 was charged against the well. An offset well was drilled and completed in February 2005 and is currently being tested. Drilling costs of $104,010 have been capitalized as of December 31, 2004.
 
 In June 2004 the Company purchased a 16% interest in a Cleveland County, Oklahoma prospect for $20,000. An exploratory well was commenced in June 2004 and completed in August 2004. It is producing oil at good rates from two zones. Drilling costs of $213,868 have been capitalized as of December 31, 2004.
 
 In July 2004 the Company participated with a fee mineral interest in a McIntosh County, Oklahoma exploratory well. The Companys working interest is 3.13%. The well was completed in September 2004 testing gas at marginal rates. It is currently shut in awaiting pipeline connection. Estimated drilling costs were $4,385 as of December 31, 2004.
 
 In August 2004 the Company participated in the drilling of an exploratory well on a Stephens County, Oklahoma prospect with a 2.9% working interest. The well was completed in September 2004 as a commercial oil and gas producer. An offset well was drilled and completed in December 2004, recompleted in February 2005 and is currently being tested. An exploratory well (Company working interest 2.8%) was started in November 2004. Casing was set in February 2005 and a completion attempt is pending. Another exploratory well (Company working interest 3.5%) was started in February 2005 and is currently drilling. Drilling costs as of December 31, 2004 total $34,757.
 
 17
 In October 2004 the Company purchased a 16% interest in a McClain County, Oklahoma prospect for $20,000. An exploratory well was started in October 2004 and completed in January 2005. Sales commenced in February 2005 and the well appears to be a commercial oil and gas producer. Drilling costs, including prepayments, were $185,016 as of December 31, 2004.
 
 The Company agreed to participate with a fee mineral interest in the drilling of an exploratory horizontal well in Harding County, South Dakota. The Company has a 10.9% interest in the well which was started in February 2005 and is currently drilling.
 
 In February 2005 the Company purchased a 16% interest in 3,830 net acres of leasehold on a Cheyenne and Rawlins Counties, Kansas prospect for $21,450. A 3-D seismic survey is currently in progress on the prospect.
 
 Depreciation, Depletion, Amortization and Valuation Provisions (DD&A). Major components are the provision for impairment of undeveloped leaseholds, provision for impairment of long-lived assets, depletion of producing leaseholds and depreciation of tangible and intangible lease and well costs. Undeveloped leaseholds are amortized over the life of the leasehold 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 $168,819 in 2004 and $94,369 in 2003. The increase in the provision for impairment is directly related to the exploration activity discussed under Exploration Costs, above. The 2003 provision for impairment was primarily due to the annual amortization of undeveloped leaseholds. The most significant 2004 impairment was a Coal County, Oklahoma marginal well, which resulted in an impairment of $121,526.
 
 As discussed in Note 10 to the accompanying financial statements, accounting principles require the recognition of an impairment loss on long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets carrying amount. Reviews were performed in both 2004 and 2003. The 2004 provision of $320,154 was the result of a decline in production of wells which first produced in 2003 and wells completed in 2004 for which the estimated fair market value of future production was less than the Companys carrying amount in the well. The 2003 provision of $348,923 was to a great extent the result of similar declines in 2003.
 
 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 $407,142 in 2004 and $374,060 in 2003.
 
 General, Administrative and Other Expenses (G&A). G&A decreased $8,100 (1%) to $783,850 in 2004 from $791,950 in 2003. The decrease was the result of a decrease in employee salaries and benefits, offset by an increase in accounting fees.
 
 18
 Equity Income (Loss) in Investees. The following is an analysis of equity income (loss) in investees by entity for the years ended December 31, 2004 and 2003. See Note 7 to the accompanying financial statements included in Item 7 below.
 
 
 2004 Income (Loss)Net Income (Loss)

Over (Under)2004

2003

2003Broadway Sixty-Eight, Ltd.

$
22,066

$
40,019

$
(17,953
)Millennium Golf Properties, LLC


13,180


(7,782
)

20,962OKC Industrial Properties, LC


48,980


562


48,418JAR Investment, LLC


2,455


(27,354
)

29,809Total

$
86,681

$
5,445

$
81,236
 
 Other Income (Loss), Net. See Note 11 to the accompanying financial statements for an analysis of the components of this line item for the years ended 2004 and 2003. Other income, net increased $181,345 (137%) to $313,272 in 2004 from $131,927 in 2003.
 
 Realized and unrealized gain on trading securities decreased $88,073 (90%) to $9,338 in 2004 from $97,411 in 2003. Realized gains or losses result when a trading security which is owned 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 market value. In 2004, the Company had realized gains of $35,347 and unrealized losses of $26,009. In 2003, the Company had realized losses of $152,658 and unrealized gains of $250,069 .
 
 Accrual basis interest income decreased $1,340 (3%) to $50,028 in 2004 from $51,368 in 2003. The decrease was the result of a decline in the average rate of return on cash equivalents and available for sale securities from which most of interest income is derived. The average rate of return fell 0.40% to 0.88% in 2004 from 1.28% in 2003 and the average balance outstanding of $4,475,566 increased $51,967 (1.2%) from $4,423,599 in 2003.
 
 Most of the increase in this line item was due to an increase in class action lawsuit settlements of $288,872 (3,470%) to $297,196 in 2004 from $8,324 in 2003. All of this increase was due to settlement of litigation described earlier under Operating Activities. The Company currently has no similar or significant pending lawsuits.
 
 Provision for (Benefit from) Income Taxes. See Note 6, to the accompanying financial statements for an analysis of the various components of income taxes. In 2004, the Company had an estimated provision for income taxes of $453,071 as the result of a current tax provision of $89,129 plus a deferred tax provision of $363,942. In 2003, the Company had an estimated provision for income taxes of $259,216 all due to a deferred tax provision and no current tax provision. No 2003 current income taxes were provided primarily as a result of accelerated depreciation of 2003 lease and well equipment additions under provision of the Jobs and Growth Tax Relief Reconciliation Act of 2003.
  19    Item 7. Financial Statements.
 Index to Financial Statements.PageReport of Independent Registered Public Accounting Firm - Grant Thornton LLP
21Balance Sheets - December 31, 2004 and 2003
22Statements of Operations - Years Ended December 31, 2004 and 2003
24Statement of Stockholders Equity - December 31, 2004 and 2003
25Statements of Cash Flows - Years Ended December 31, 2004 and 2003
26Notes to Financial Statements
28Unaudited Supplemental Financial Information
37
  20   **Report of Independent Registered Public Accounting Firm**
 
 
 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, 2004 and 2003, and the related statements of operations, 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 audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion 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, 2004 and 2003, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
 
 
 
 GRANT THORNTON LLP
 
 Oklahoma City, Oklahoma
 March 11, 2005
 
 
 
  21   THE RESERVE PETROLEUM COMPANY
 BALANCE SHEETS
 
 ASSETS
 December 31,2004

2003Current Assets:Cash and Cash Equivalents (Note 2)

$
570,497

$
346,167Available for Sale Securities (Notes 2 & 5)


4,718,828


4,266,012Trading Securities (Notes 2 & 5)


261,893


251,667Receivables (Note 2)


669,008


436,703Refundable Income Taxes


----


34,685Prepayments


----


5,6256,220,226


5,340,859Investments:Equity Investments (Notes 2 & 7)


532,469


517,288Other


15,298


15,298547,767


532,586Property, Plant & Equipment (Notes 2, 8 & 10):Oil & Gas Properties, at Cost Based on theSuccessful Efforts Method of AccountingUnproved Properties


624,061


638,630Proved Properties


7,172,141


5,568,6847,796,202


6,207,314Less - Valuation Allowance and AccumulatedDepreciation, Depletion & Amortization


5,141,638


4,741,4352,654,564


1,465,879Other Property & Equipment, at Cost


375,568


344,739Less - Accumulated Depreciation & Amortization


175,615


173,979199,953


170,7602,854,517


1,636,639Other Assets


461,722


447,166$
10,084,232

$
7,957,250(continued)See Accompanying Notes
 
 
 
 22
 THE RESERVE PETROLEUM COMPANY
 BALANCE SHEETS
 
 
 (concluded)
 
 LIABILITIES AND STOCKHOLDERS EQUITY
 
 December 31,2004

2003Current Liabilities:Accounts Payable (Note 2)

$
169,823

$
38,862Income Taxes Payable


4,394


----Other Current Liabilities -Deferred Income Taxes and Other


147,682


112,414321,899


151,276Long Term Liabilities:Dividends Payable (Note 3)


170,928


160,307Deferred Tax Liability


384,484


8,144555,412


168,451Commitments & Contingencies (Notes 2 & 7)Stockholders Equity (Notes 3 & 4)Common Stock


92,368


92,368Additional Paid-in Capital


65,000


65,000Retained Earnings


9,303,963


7,720,6459,461,331


7,878,013Less - Treasury Stock, at Cost


254,410


240,4909,206,921


7,637,523$
10,084,232

$
7,957,250See Accompanying Notes
  23    THE RESERVE PETROLEUM COMPANY
 STATEMENTS OF OPERATIONS
 
 
 Year Ended December 31,2004

2003Operating Revenues:Oil & Gas Sales

$
3,921,384

$
2,852,846Lease Bonuses & Other


343,162


56,9364,264,546


2,909,782Operating Costs and Expenses:Production


620,492


509,482Exploration


139,231


156,948Depreciation, Depletion, Amortization& Valuation Provisions


918,864


829,672General, Administrative and Other


783,850


791,9502,462,437


2,288,052Income from Operations


1,802,109


621,730Equity Income in Investees (Note 7)


86,681


5,445Other Income, Net (Note 11)


313,272


131,927Income before Income Taxes


2,202,062


759,102Provision for Income Taxes (Notes 2 & 6)


453,071


259,216Net Income

$
1,748,991

$
499,886Per Share Data (Note 2):Net Income, Basic and Diluted

$
10.56

$
3.00Cash Dividends

$
1.00

$
1.00Weighted Average Shares Outstanding, Basic and Diluted


165,661


166,408See Accompanying Notes
 
 
 24
 THE RESERVE PETROLEUM COMPANY
 STATEMENT OF STOCKHOLDERS EQUITY
 FOR THE TWO YEARS ENDED DECEMBER 31, 2004
  
 AdditionalCommon

Paid-in

Retained

TreasuryStock

Capital

Earnings

StockBalance at January 1, 2003

$
92,368

$
65,000

$
7,387,225

$
(216,423
)Net Income


----


----


499,886


----Cash Dividends on Common Stock


----


----


(166,466
)

----Purchase of Treasury Stock


----


----


----


(24,067
)Balance at December 31, 2003


92,368


65,000


7,720,645


(240,490
)Net Income


-----


----


1,748,991


----Cash Dividends on Common Stock


-----


----


(165,673
)

----Purchase of Treasury Stock


-----


----


----


(13,920
)Balance at December 31, 2004

$
92,368

$
65,000

$
9,303,963

$
(254,410
)See Accompanying Notes
  25    THE RESERVE PETROLEUM COMPANY
 STATEMENTS OF CASH FLOWS
 Increase (Decrease) in Cash and Cash Equivalents
 
 Year Ended December 31,2004

2003Cash Flows from Operating Activities:Cash Received-Oil and Gas Sales

$
3,762,604

$
2,691,215Lease Bonuses and Rentals


309,451


35,517Agricultural Rentals & Other


5,415


5,198Cash Paid-Production Costs


(602,551
)

(504,964
)Exploration Costs


(139,151
)

(185,698
)General Suppliers, Employees and Taxes,Other than Income


(786,160
)

(825,382
)Interest Received


39,500


56,422Interest Paid


(9,375
)

(11,250
)Settlement of Class Action Lawsuits


297,196


8,324Dividends Received on TradingSecurities


657


428Purchase of Trading Securities


(533,568
)

(654,316
)Sale of Trading Securities


532,680


658,308Income Taxes Refunded, net


----


205,743Net Cash Provided by OperatingActivities

$
2,876,698

$
1,479,545Cash Flows from Investing Activities:Sale and Maturity of Available forSale Securities


7,880,588


8,172,552Purchase of Available for Sale Securities


(8,333,404
)

(8,164,948
)Property Dispositions


81,607


33,848Property Additions


(2,183,687
)

(1,317,192
)Cash Distributions from Equity Investments


71,500


11,550Cash Applied to Equity Investments


---


(2,000
)Net Cash Applied to Investing Activities

$
(2,483,396
)
$
(1,266,190
)(Continued)See Accompanying Notes
  26    (Concluded)
 
 THE RESERVE PETROLEUM COMPANY
 STATEMENTS OF CASH FLOWS
 Increase (Decrease) in Cash and Cash Equivalents
 
 
 Year Ended December 31,2004

2003Cash Flows Applied to Financing Activities:Dividends Paid to Shareholders

$
(155,052
)
$
(157,597
)Purchase of Treasury Stock


(13,920
)

(24,067
)Total Cash Applied to Financing Activities


(168,972
)

(181,664
)Net Change in Cash and Cash Equivalents


224,330


31,691Cash and Cash Equivalents at Beginning of Year


346,167


314,476Cash and Cash Equivalents at End of Year

$
570,497

$
346,167Reconciliation of Net Income to NetCash Provided by Operating Activities:Net Income

$
1,748,991

$
499,886Net Income Increased (Decreased) by -Net Change in -Unrealized Holding (Gains) Losseson Trading Securities


26,009


(250,069
)Accounts Receivable


(181,342
)

(160,626
)Interest and Dividends Receivable


(10,240
)

5,054Income Taxes Refundable/Payable


39,079


204,309Accounts Payable


55,214


(39,775
)Trading Securities


(36,236
)

156,649Other Assets


(14,556
)

(15,128
)Deferred Taxes


413,942


259,216Other Liabilities


(2,334
)

(2,394
)Equity (Income) Losses in Investees


(86,681
)

(5,445
)Disposition of Property & Equipment


5,988


(1,804
)Depreciation, Depletion, Amortizationand Valuation Provisions


918,864


829,672Net Cash Provided by Operating Activities

$
2,876,698

$
1,479,545See Accompanying Notes
  27    THE RESERVE PETROLEUM COMPANY
 NOTES TO FINANCIAL STATEMENTS
 
 Note 1 - **** NATURE OF OPERATIONS
 
 The Company is principally engaged in oil and natural gas exploration and development with an area of concentration in Texas and Oklahoma.
 
 Note 2 - SUMMARY OF ACCOUNTING POLICIES
 
 Cash & Cash Equivalents
 The Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Company maintains its cash in bank deposit accounts which at times may exceed federally insured limits. The Company believes it is not exposed to any significant credit risk on such accounts.
 
 Investments
 The Company accounts for its investments in a partnership and limited liability companies on the equity basis and adjusts the investment balance to agree with its equity in the underlying assets of the entities. See Note 7 for additional information.
 
 Trading securities, which consist primarily of equity securities, are carried at fair value with unrealized gains and losses included in operations.
 
 Available for sale securities, which consist primarily of US Government securities, are carried at fair value with unrealized gains and losses reported as a component of other comprehensive income, when material.
 
 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. The Company has historically had little, if any, uncollectible receivables; therefore, an allowance for uncollectible accounts is not required.
 
 Property and Equipment
 Oil and gas properties are accounted for on the successful efforts method. The acquisition, exploration and development costs of producing properties are capitalized. The Company has not historically had any capitalized exploratory drilling costs that are pending determination of reserves for more than one year. All costs relating to unsuccessful exploration, geological and geophysical costs, delay rentals and abandoned properties are expensed. Lease costs related to unproved properties are amortized over the life of the lease and are assessed 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.
 
 28
 
 Other property and equipment is depreciated on the straight-line, declining-balance or other accelerated methods.
 
 The following estimated useful lives are used for the different types of property:
 
 Buildings and improvements
10 to 20 yearsOffice furniture & 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 and the undiscounted cash flows estimated to be generated by those assets are less than the assets carrying amount. See Note 10 for discussion of impairment losses.
 
 Income Taxes
 Deferred income taxes are provided for significant carryforwards and temporary differences using the liability method. See Note 6 for additional information.
 
 Net Income Per Share
 Net income per share is calculated based on the weighted average of the number of shares outstanding during the year. There are no dilutive shares.
 
 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 and Oklahoma. The Company had one purchaser in 2004 and 2003 whose purchases were in excess of 10% of total oil and gas sales. In 2004, the purchases were $760,446, or 19.4% of total oil and gas sales. In 2003, the purchases were $334,582, or 11.7% of total oil and gas sales.
 
 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. Actual results could differ from those estimates.
 
 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 its estimated remaining recoverable reserves (over produced). No receivables are recorded for those wells where the Company has taken less than its ownership share of gas production (under produced).
 
 Guarantees
 In November 2002, FASB Interpretation 45, *Guarantors Accounting and Disclosure*  *Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others* (FIN 45), was issued. FIN 45 requires a guarantor entity, at the inception of a guarantee covered by the measurement provisions of the interpretation, to record a liability for the fair market value of the obligation undertaken in issuing the guarantee. The Company previously did not record a liability when guaranteeing obligations unless it became probable that the Company would have to perform under the guarantee. FIN 45 applied prospectively to guarantees the Company issues or modifies subsequent to December 31, 2002. The Company historically issues guarantees only on a limited basis but has issued such guarantees associated with the Companys equity investments in Broadway Sixty-Eight, Ltd and JAR Investment, LLC. Disclosures required by FIN 45 and the effect of guarantees issued in 2002 are discussed in Note 7.
 
 29
 Asset Retirement Obligations
 In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, *Accounting for Asset Retirement Obligations.* SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset, unless such items are immaterial. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. The Company has assessed the impact of SFAS No. 143 and based on the results of the assessment believes the impact of this statement is immaterial to its financial position and results of operations.
 
 Note 3 - **** DIVIDENDS PAYABLE
 
 Dividends payable include amounts that are due to stockholders whom the Company has been unable to locate and uncashed dividend checks of other stockholders.
 
 Note 4 - COMMON STOCK
 
 The following table summarizes the changes in common stock issued and outstanding:
 Shares

Shares of
Treasury

SharesIssued

Stock

OutstandingJanuary 1, 2003, $.50par value stock, 400,000shares authorized


184,735.28


18,045.55


166,689.73Purchase of stock


----


752.09


(752.09
)December 31, 2003, $.50par value stock, 400,000shares authorized


184,735.28


18,797.64


165,937.64Purchase of stock


----


429.00


(429.00
)December 31, 2004, $.50par value stock, 400,000shares authorized


184,735.28


19,226.64


165,508.64
  30
 Note 5 - **** INVESTMENTS IN DEBT AND EQUITY SECURITIES
 At December 31, 2004 and 2003, the difference between the aggregate fair value and amortized cost basis of available for sale securities was immaterial; therefore, reporting of comprehensive income is not required. The available for sale securities by contractual maturity are as follows at December 31, 2004:
 
 Due within one year or less

$
4,718,828
 
 As to the trading securities held at year end, unrealized trading (losses) gains included in earnings were ($26,009) in 2004 and $250,069 for 2003.
 
 Note 6 - INCOME TAXES
 
 Components of deferred taxes follows:
 December 31,2004

2003AssetsLeasehold Costs

$
182,338

$
162,824Gas Balancing Receivable


52,379


52,379Long-Lived Asset Impairment


233,523


229,175Equity Investments and Other


271


11,761Total Assets


468,511


456,139LiabilitiesMarketable Securities


7,056


15,910Receivables


98,137


51,681Intangible Development Costs and Depreciation


852,994


464,282Total Liabilities


958,187


531,873Net Deferred Tax Liability

$
(489,676
)
$
(75,734
)
  The following table summarizes the current and deferred portions of income tax expense.
 Year Ended December 31,2004

2003Current Tax Provision:Federal

$
89,129

$State


----


----89,129


----Deferred Provision


363,942


259,216Total Provision

$
453,071

$
259,216
   31
 The total provision for income tax expressed as a percentage of income before income tax was 21% in 2004 and 34% in 2003. These amounts differ from the amounts computed by applying the statutory US Federal income tax rate of 35% for 2004 and 2003 to income before income tax as summarized in the following reconciliation:
 
 Year Ended December 31,2004

2003Computed Federal TaxProvision

$
770,722

$
265,685Increase (Decrease) in Tax From:Corporate Graduated Tax RateStructure


(22,021
)

(7,626
)Refund for Capital Loss Carryback


(49,312
)

----Allowable Depletion in Excess of Basis


(246,801
)

----Dividend Received Deduction


(161
)

(99
)Other


644


1,256Provision for Income Tax

$
453,071

$
259,216Effective Tax Rate


21%


34%
 
 
 Note 7 - **** INVESTMENTS AND RELATED COMMITMENTS AND CONTINGENT LIABILITIES INCLUDING GUARANTEES
 
 The carrying value of Equity Investments consist of the following at December 31:
 
 Ownership %

2004

2003Broadway Sixty-Eight, Ltd.


33%

$
308,284

$
286,218JAR Investment, LLC


25%


93,820


91,365Millennium Golf Properties, LLC


9%


57,676


75,996OKC Industrial Properties, L.L.C.


10%


72,689


63,709$
532,469

$
517,288
 Broadway Sixty-Eight, Ltd., an Oklahoma limited partnership (the Partnership), owns and operates an office building in Oklahoma City, Oklahoma. Although the Company invested as a limited partner, along with the other limited partners, it agreed jointly and severally with all other limited partners to reimburse the general partner for any losses suffered from operating the Partnership. The indemnity agreement provides no limitation to the maximum potential future payments.
 
 The Company leases its corporate office from the Partnership. The operating lease under which the space was rented expired December 31, 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 $27,000 for each of the years ended December 31, 2004 and 2003.
 
 32
 JAR Investment, LLC, (JAR) an Oklahoma limited liability company, holds Oklahoma City metropolitan area real estate to be improved for sale and/or lease. JAR owns a 70% management interest in Main-Eastern, LLC (M-E), also an Oklahoma limited liability company. M-E was formed in 2002 to establish a joint venture to develop a retail/commercial center on a portion of JARs real estate.
 
 The Company has a guarantee agreement limited to 25% of JARs 70% interest in M-Es outstanding loan plus all costs and expenses related to enforcement and collection, or $159,886 at December 31, 2004. This loan matures November 27, 2008. Because the guarantee of the M-E loan has not been modified subsequent to December 31, 2002, no liability for the fair value of the obligation is required to be recorded by the Company. The maximum potential amount of future payments (undiscounted) the Company could be required to make under the M-E guarantee at December 31, 2004 (based on the original loan amount) is $169,750 plus costs and expenses related to enforcement and collection.
 
 The Company has a continuing guaranty agreement relating to a JAR bank loan with an outstanding balance of $532,367 at December 31, 2004. This loan matures May 22, 2009. The maximum liability of the Company under the guaranty will not exceed 25% of all indebtedness under the loan. The maximum potential amount of future payments (undiscounted) the Company could be required to make is $133,092 plus all costs and expenses of enforcement of the guaranty and collection and sale of the collateral securing the guaranty. The note is collateralized by commercial property owned by JAR with an appraised value of $1,300,000 on the date of appraisal, April 16, 2003. The Companys 25% ownership interest in this appraised value is $325,000, or more than twice the maximum potential undiscounted liability under the guaranty agreement. Management believes the fair value of the Companys obligation under this continuing guarantee is nominal and as such, no liability has been recorded.
 
 Millennium Golf Properties, LLC, an Oklahoma limited liability company, owns and operates two Oklahoma City area golf courses, Coffee Creek Golf Course and River Oaks Golf Course. It is also involved in real estate development around each golf course.
 
 OKC Industrial Properties, L.L.C., an Oklahoma limited liability company, holds certain Oklahoma City metropolitan area real estate as an investment.
 
 Note 8 - COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION, AND DEVELOPMENT ACTIVITIES
 
 All of the Companys oil and gas operations are within the continental United States. In connection with its oil and gas operations, the following costs were incurred:
 Year Ended December 31,2004

2003Acquisition of PropertiesUnproved

$
359,005

$
148,656Proved

$
----

$
224,000Exploration Costs

$
1,333,434

$
428,374Development Costs

$
636,747

$
580,531
 33
 
  Note 9 -FINANCIAL INSTRUMENTS
 
 The following table includes various estimated fair value information as of December 31, 2004 and 2003, which pertains to the Company's financial instruments and does not purport to represent the aggregate net fair value of the Company. The carrying amounts in the table below are the amounts at which the financial instruments are reported in the financial statements.
 
 All of the Company's financial instruments are held for purposes other than trading, except for trading securities.
 
 The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
 
 1.  Cash and Cash Equivalents
 The carrying amount approximates fair value because of the short maturity and highly liquid nature of those instruments.
 
 2.  Available for Sale Securities
 The estimated fair values are based upon quoted market prices.
 
 3.  Trading Securities
 The estimated fair values are based upon quoted market prices.
 
 4.  Dividends Payable
 The carrying amount approximates fair value. Fair value is the amount that will be paid on demand at the reporting date.
 
 The carrying amounts and estimated fair values of the Company's financial instruments are as follows:
 
 2004

2003Carrying

Estimated

Carrying

EstimatedAmount

Fair Value

Amount

Fair ValueFinancial AssetsCash and Cash Equivalents

$
570,497

$
570,497

$
346,167

$
346,167Available for Sale Securities


4,718,828


4,718,828


4,266,012


4,266,012Trading Securities


261,893


261,893


251,667


251,667Financial LiabilitiesDividends Payable


(180,928
)

(180,928
)

(170,307
)

(170,307
)
 
 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 $320,154 for the year ended December 31, 2004 and $348,923 for the year ended December 31, 2003 are included in the Statements of Operations in the line item, Depreciation, Depletion, Amortization and Valuation Provisions.
 
 
 34
 Note 11 - OTHER INCOME, NET
 
 The following is an analysis of the components of Other Income, Net for the years ended 2004 and 2003:
 2004

2003Realized and Unrealized GainOn Trading Securities

$
9,338

$
97,411Loss on Asset Sales


(39,651
)

(19,615
)Interest Income


50,028


51,368Settlements of Class Action Lawsuits


296,908


8,324Agricultural Rental Income


5,600


5,600Dividend and Other Income


657


428Interest and Other Expenses


(9,608
)

(11,589
)Other Income, Net

$
313,272

$
131,927
 Note 12 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
 
 The Company is affiliated by common management and ownership with Mesquite Minerals, Inc., (Mesquite), Mid-American Oil Company (Mid-American), Lochbuie Limited Partnership (LLTD) and Lochbuie Holding Company (LHC). The Company also owns interests in certain producing and non-producing oil and gas properties as tenants in common with Mesquite, Mid-American and LLTD.
 
 Mesquite, Mid-American and LLTD share facilities and employees, including executive officers, with the Company. The Company has been reimbursed for services, facilities and miscellaneous business expenses incurred during 2004 by payment to the Company in the amount of $169,950 by Mesquite, $119,965 by Mid-American and $79,976 by LLTD. Reimbursements for 2003 were $159,738 by Mesquite, $112,756 by Mid-American and $75,171 by LLTD. Included in the 2004 amounts, Mesquite paid $112,888, Mid-American $79,686 and LLTD $53,124 for their share of salaries. In 2003, the share of salaries paid by Mesquite was $120,033, Mid-American $84,729, and LLTD $56,486.
  
 35
 
 UNAUDITED SUPPLEMENTAL FINANCIAL INFORMATION
 
 36


SUPPLEMENTAL SCHEDULE 1








THE RESERVE PETROLEUM COMPANY


WORKING INTERESTS RESERVE QUANTITY INFORMATION


(Unaudited)





Year Ended December 31,2004

2003Oil & Natural Gas Liquids (Bbls)Proved Developed and Undeveloped ReservesBeginning of Year


53,605


31,181Revisions of Previous Estimates


6,088


533Extensions and Discoveries


43,100


29,280Production


(12,320
)

(8,424
)Purchases of Reserves in Place


----


1,035End of Year


90,473


53,605Proved Developed ReservesBeginning of Year


53,605


31,181End of Year


90,473


53,605Gas (MCF)Proved Developed and Undeveloped ReservesBeginning of Year


1,089,402


1,070,380Revisions of Previous Estimates


66,204


(125,250
)Extensions and Discoveries


421,434


196,260Production


(247,340
)

(232,748
)Purchases of Reserves in Place


----


180,760End of Year


1,329,700


1,089,402Proved Developed ReservesBeginning of Year


1,089,402


1,070,380End of Year


1,329,700


1,089,402(continued)See notes on next page




37    SUPPLEMENTAL SCHEDULE 1
 
 
 
 THE RESERVE PETROLEUM COMPANY
 WORKING INTERESTS RESERVE QUANTITY INFORMATION
 (Unaudited)
 
 
 (Concluded)
 
 
 Notes
1.
Estimates of royalty interests reserves have not been included because the information required for the estimation of said reserves is not available. The Companys share of production from its net royalty interests was 12,507 Bbls of oil and 271,858 MCF of gas for the year ended December 31, 2004, and 13,891 Bbls of oil and 217,462 MCF of gas for the year ended December 31, 2003.2.
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 the years ended December 31, 2004 and 2003. 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.
  38    SUPPLEMENTAL SCHEDULE 2
 
 
 
 
 THE RESERVE PETROLEUM COMPANY
 STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
 RELATING TO PROVED WORKING INTERESTS
 OIL AND GAS RESERVES
 (Unaudited)
 
 
 At December 31,2004

2003Future Cash Inflows

$
12,666,911

$
6,656,376Future Production andDevelopment Costs


(3,701,502
)

(2,288,742
)Future Income Tax Expense


(2,504,856
)

(1,201,565
)Future Net Cash Flows


6,460,553


3,166,06910% Annual Discount forEstimated Timing of Cash Flows


(1,932,192
)

(925,321
)Standardized Measure of DiscountedFuture Net Cash Flows

$
4,528,361

$
2,240,748
 
 Estimates of future net cash flows from the Companys proved working interests oil and gas reserves are shown in the table above. These estimates, which by their nature are subject to revision in the near term, are based on prices in effect at year end, with no escalation, except for fixed and determinable amounts attributable to gas under provisions of the Natural Gas Policy Act (NGPA). The development and production costs are based on year-end cost levels, assuming the continuation of existing economic conditions. Cash flows are further reduced by estimated future income tax expense calculated by applying the current statutory income tax rates to the pretax net cash flows less depreciation of the tax basis of the properties and depletion applicable to oil and gas production.
  39   SUPPLEMENTAL SCHEDULE 3
 
 
 THE RESERVE PETROLEUM COMPANY
 CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE
 NET CASH FLOWS FROM PROVED WORKING INTERESTS RESERVE QUANTITIES
 (Unaudited)
 
 
 
 Year Ended December 31,2004

2003Standardized Measure,Beginning of Year

$
2,240,748

$
1,731,867Sales and Transfers, Net ofProduction Costs


(1,380,392
)

(924,239
)Net Change in Sales and TransferPrices, Net of Production Costs


1,314,998


336,417Extensions, Discoveries and ImprovedRecoveries, Net of Future Productionand Development Costs


2,376,102


855,969Revisions of Quantity Estimates


500,544


(134,955
)Accretion of Discount


309,122


240,646Net Change in Income Taxes


(905,186
)

(175,879
)Purchases of Reserves in Place


----


252,584Changes in Production Rates(Timing) and Other


72,425


58,338Standardized Measure,End of Year

$
4,528,361

$
2,240,748
 
 40
 
 
 Item 8. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
 
 Not Applicable
 
 Item 8A. Controls and Procedures
 
 a)  Evaluation of Disclosure Controls and Procedures.
 
 As directed by Section 302(a) of the Sarbanes-Oxley Act of 2002, effective August 29, 2002, the Securities and Exchange Commission (SEC) adopted rules requiring a reporting companys principal executive and financial officers each to certify, among other things, that they are responsible for establishing, maintaining and regularly evaluating the effectiveness of the reporting companys disclosure controls and procedures. For purposes of the new rules, disclosure controls and procedures are defined by the SEC as controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports filed or submitted by it under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Commissions rules and forms. The SEC further explains, disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in its Exchange Act reports is accumulated and communicated to the issuers management, including its principal executive and financial officers, as appropriate to allow timely decisions regarding required disclosure.
 
 The effectiveness of the Companys disclosure controls and procedures were evaluated by the Principal Executive Officer and the Principal Financial Officer as of the end of the period covered by this Form 10-KSB. The scope of their evaluation included the following categories of review: overall control environment, risk assessment capabilities, specific control activities, quality of information and communication, and performance monitoring. Based on their evaluation it is their conclusion that the effectiveness of the Companys said disclosure controls and procedures is satisfactory.
 
 b)  Changes in Internal Controls Over Financial Reporting.
 
 There have been no significant changes in the Companys internal controls or in other factors that could significantly affect these controls that occurred during the fourth quarter of the period covered by this report, including any corrective actions with regard to significant deficiencies and material weakness. All internal control systems have inherent limitations, including the possibility of circumvention and overriding of controls, and therefore, can provide only reasonable assurance as to financial statement preparation and safeguarding of Company assets.
 
 
 41
 PART III
 
 
 Items 9, 10, and 11 are incorporated by reference to the Companys proxy statement to be mailed to security holders on or about April 22, 2005 in connection with its annual stockholders meeting to be held on May 24, 2005.
 
 Item 12. Certain Relationships and Related Transactions.
 See Item 6, Managements Discussion and Analysis of Financial Conditions and Results of Operations and Item 7, Note 12 to Financial Statements
 
 Item 13. Exhibits and Reports on Form 8-K.
 
 (a) Exhibits
 
 The following documents are exhibits to this Form 10-KSB. Each document marked by an asterisk is hereby incorporated herein by reference to the same document previously filed with the Securities and Exchange Commission.
 
 Exhibit

S.E.C.
ExhibitReference
Description
Report (Date)
Number
Page3.1
* Restated Certificate ofIncorporation datedNovember 1, 1988
10-KSB (12/96)
3.1
39*Amended As of November 14,2000 By-Laws datedNovember 1, 1988
10-KSB (12/00)
3.2(a)
383.2
*Resolution Amending By-LawsNovember 14, 2000
10-KSB (12/00)
3.2(b)
4831
Chief Executive OfficersCertification pursuant toSection 302 of the Sarbanes-Oxley Act of 2002
10-KSB (12/04)
31.1
4631
Chief Financial and AccountingOfficers Certification pursuantto Section 302 of the Sarbanes-Oxley Act of 2002
10-KSB (12/04)
31.2
4732
Chief Executive Officers andChief Financial OfficersCertification pursuant toSection 906 of the Sarbanes-Oxley Act of 2002
10-KSB (12/04)
32.1
48
 
 
 42
 
 (b). Reports on Form 8-K.
 
 On November 19, 2004, a Form 8-K was filed with the Securities and Exchange Commission reporting an amendment to the Company's Bylaws apporved November 16, 2004 by the Board of Directors.
 
 Item 14. Principal Accountant Fees and Services
   Incorporated by reference to Companys proxy statement to be filed with Securities and Exchange Commission pursuant to Regulation 14A within 120 days of the end of the Companys year 2004.
 
 
 
 43
 
 
 SIGNATURES
 
 In accordance with Section 13 or 15(d) of the Securities Exchange Act the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
  **THE RESERVE PETROLEUM COMPANY**(Registrant)Date: March 24, 2005
By:
/s/ Mason W. McLainMason W. McLain, President(Principal Executive Officer)
 
 ****By:
/s/ James L. TylerJames L. Tyler, 2nd Vice President(Principal Financial and Accounting Officer)
  Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:
 
 /s/ Mason McLain


/s/ Jerry L. CrowMason W. McLain (Director)


Jerry L. Crow (Director)March 24, 2005


March 24, 2005
 
 /s/ Robert L. Savage


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


William M. Smith (Director)March 24, 2005


March 24, 2005
   44