ITEM 1.
BUSINESS
Overview
The Reserve Petroleum Company (the “Company”) is engaged principally in managing its owned mineral properties and the exploration for and the development of oil and natural gas properties. Other business segments are not significant factors in the Company’s operations. The Company is a corporation organized under the laws of the State of Delaware in 1931.
Oil and Natural Gas Properties
For a summary of certain data relating to the Company’s oil and gas properties including production, undeveloped acreage, producing and dry wells drilled and recent activity, see Item 2, “Properties.” For a discussion and analysis of current and prior years’ revenue and related costs of oil and gas operations and a discussion of liquidity and capital resource requirements, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Owned Mineral Property Management
The Company owns non-producing mineral interests in 260,470 gross acres equivalent to 89,494 net acres. These mineral interests are located in nine different states in the north and south central United States. A total of 82,361 net acres are located in the states of Arkansas, Kansas, Oklahoma, South Dakota and Texas, the areas of concentration for the Company in its present exploration and development programs.
The Company has several options relating to the exploration and/or development of these owned mineral interests. Management continually reviews various industry reports and other sources for activity (leasing, drilling, significant discoveries, etc.) in areas where the Company has mineral ownership. Based on its analysis of any activity and assessment of the potential risk relative to the particular area, management may negotiate a lease or farmout agreement and accept a royalty interest, or it may choose to participate as a working interest owner and pay its proportionate share of any exploration or development drilling costs.
A substantial amount of the Company’s oil and gas revenue has resulted from its owned mineral property management. In 2010, $4,693,408 (39%) of oil and gas sales was from royalty interests versus $3,890,699 (44%) in 2009. As a result of its mineral ownership, the Company had royalty interests in 23 gross (.35 net) wells, which were drilled and completed as producing wells in 2010. This resulted in an average royalty interest of about 1.5% for these 23 new wells. The Company has very little control over the timing or extent of the operations conducted on its royalty interest properties. See the following paragraphs for a discussion of mineral interests in which the Company chooses to participate as a working interest owner.
Development Program
Development drilling by the Company is usually initiated in one of three ways. The Company may participate as a working interest owner with a third party operator in the development of non-producing mineral interests, which it owns; with a joint interest operator, it may participate in drilling additional wells on its producing leaseholds; or if its exploration program, discussed below, results in a successful exploratory well, it may participate in the drilling of additional wells on the exploratory prospect. In 2010, the Company participated in the drilling of 21 development wells with 15 wells (2.01 net) completed as producers and 6 wells (.77 net) in progress.
Exploration Program
The Company’s exploration program is normally conducted by purchasing interests in prospects developed by independent third parties; participating in third party exploration of Company-owned non-producing minerals; developing its own exploratory prospects; or a combination of the above.
The Company normally acquires interests in exploratory prospects from someone in the industry with whom management has conducted business in the past and/or if management has confidence in the quality of the geological and geophysical information presented for evaluation by Company personnel. If evaluation indicates the prospect is within the Company’s risk limits, the Company may negotiate to acquire an interest in the prospect and participate in a non-operating capacity.
The Company develops exploratory drilling prospects by identification of an area of interest, development of geological and geophysical information and purchase of leaseholds in the area. The Company may then attempt to sell an interest in the prospect to one or more companies in the petroleum industry with one of the purchasing companies functioning as operator. In 2010, the Company participated in the drilling of 15 exploration wells with 6 wells (.82 net) completed as producers, 7 wells (1.14 net) completed as dry holes and 2 wells (.29 net) in progress. Of the six wells (.78 net) still drilling at the end of 2009, four (.66 net) were completed as producing wells in 2010 and two wells (.12 net) were dry holes.
For a summation of exploratory and development wells drilled in 2010 or planned for in 2011, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” subheading “Update of Oil and Gas Exploration and Development Activity from December 31, 2009.”
Customers
In 2010, the Company had two customers whose total purchases were greater than 10% of revenues from oil and gas sales. Redland Resources, Inc. purchases were $2,653,850, or 22% of total oil and gas sales. Luff Exploration Company purchases were $1,641,530, or 14% of total oil and gas sales. The Company sells most of its oil and gas under short-term sales contracts that are based on the spot market price. A minor amount of oil and gas sales are made under fixed price contracts having terms of more than one year.
Competition
The oil and gas industry is highly competitive in all of its phases. There are numerous circumstances within the industry and related market place that are out of the Company’s control such as cost and availability of alternative fuels, the level of consumer demand, the extent of other domestic production of oil and gas, the price and extent of importation of foreign oil and gas, the cost of and proximity of pipelines and other transportation facilities, the cost and availability of drilling rigs, regulation by state and federal authorities, and the cost of complying with applicable environmental regulations.
The Company does not operate any of the wells in which it has an interest; rather, it partners with companies that have the resources, staff, and experience to operate wells both in the drilling and production phases. The Company uses its strong financial base and its mineral and leasehold acreage ownership, along with its own geologic and economic evaluations, to participate in drilling operations with these companies. This methodology allows the Company to participate in exploration and development activities it could not undertake on its own due to financial and personnel limits and allows it to maintain low overhead costs.
Regulation
The Company’s operations are affected in varying degrees by political developments and federal and state laws and regulations. Although released from federal price controls, interstate sales of natural gas are subject to regulation by the Federal Energy Regulatory Commission (FERC). Oil and gas operations are affected by environmental laws and other laws relating to the petroleum industry, and both are affected by constantly changing administrative regulations. Rates of production of oil and gas have, for many years, been subject to a variety of conservation laws and regulations, and the petroleum industry is frequently affected by changes in the federal tax laws.
Generally, the respective state regulatory agencies supervise various aspects of oil and gas operations within their states and the transportation of oil and gas sold intrastate.
Environmental Protection and Climate Change
The operation of the various producing properties, in which the Company has an interest, is subject to federal, state, and local provisions regulating discharge of materials into the environment, the storage of oil and gas products, and the contamination of subsurface formations. The Company’s lease operations and exploratory activity have been and will continue to be affected by existing regulations in future periods. However, the known effect to date has not been material as to capital expenditures, earnings, or industry competitive position. Environmental compliance expenditures produce no increase in productive capacity or revenue and require more of management’s time and attention; a cost which cannot be estimated with any assurance of certainty.
In 2009, the EPA officially published its findings that greenhouse gas emissions present an endangerment to human health and the environment. According to the EPA, these emissions are contributing to global warming and climate change. These findings allowed the EPA to adopt and implement regulations in 2010 to restrict these emissions under existing provisions of the Federal Clean Air Act.
The Company may be, directly and indirectly, subject to the effects of climate change and may, directly or indirectly, be affected by government laws and regulations related to climate change. The Company cannot predict with any degree of certainty what effect, if any, climate change and government laws and regulations related to climate change will have on the Company and its business, whether directly or indirectly. While we believe that it is difficult to assess the timing and effect of climate change and pending legislation and regulation related to climate change on the Company's business, we believe that climate change and government laws and regulations related to climate change may affect, directly or indirectly, (i) the costs associated with drilling and production operations in which we participate; (ii) the demand for oil and natural gas; (iii) insurance premiums, deductibles, and the availability of coverage; and (iv) the cost of utilities paid by the Company. In addition, climate change may increase the likelihood of property damage and the disruption of operations of wells in which we participate. As a result, our financial condition could be negatively impacted, but we are unable to determine at this time whether that impact would be material.
Other Business
See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” subheading “Equity Investments” and Item 8, Notes 2 and 7 to the accompanying financial statements for a discussion of other business including guarantees.
Employees
At December 31, 2010, the Company had eight employees, including officers. See the Proxy Statement for additional information. During 2010, all the Company’s employees devoted a portion of their time to duties with affiliated companies, and the Company was reimbursed for the affiliates’ share of compensation directly from those companies. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” subheading “Certain Relationships and Related Transactions” and Item 8, Note 12 to the accompanying financial statements for additional information.
ITEM 1A.
ITEM 1A.
RISK FACTORS
Smaller reporting companies are not required to provide the information required by this Item.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
Smaller reporting companies are not required to provide the information required by this Item.
ITEM 2.
ITEM 2.
PROPERTIES
The Company’s principal properties are oil and natural gas properties. The Company has interests in approximately 660 producing properties with one-third of them being working interest properties and the remaining two-thirds being royalty interest properties. About 85% of these properties are located in Oklahoma and Texas and account for approximately 67.5% of the Company’s annual oil and gas sales. About 10% of the properties are located in Arkansas, Kansas, and South Dakota and account for approximately 32.1% of the Company’s annual oil and gas sales. The remaining 5% of these properties are located in Colorado and Montana and account for less than 1% of the Company’s annual oil and gas sales. No individual property provides more than 8% of the Company’s annual oil and gas sales. See discussion of revenues from Robertson County, Texas, royalty interest properties in Item 7, “Operating Revenues” for additional information about significant properties.
OIL AND NATURAL GAS OPERATIONS
Oil and Gas Reserves
Reference is made to the Unaudited Supplemental Financial Information beginning on Page 33 for working interest reserve quantity information.
Since January 1, 2010, the Company has not filed any reports with any federal authority or agency, which included estimates of total proved net oil or gas reserves, except for its 2009 Annual Report on Form 10-K and federal income tax return for the year ended December 31, 2009. 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, 2010, 2009 and 2008. Equivalent MCF was calculated using approximate relative energy content.
At December 31, 2010, the Company had working interests in 149 gross (18.24 net) wells producing primarily gas and 146 gross (14.6 net) wells producing primarily oil. These interests were in 62,729 gross (8,084 net) producing acres. These wells include 52 gross (1.03 net) wells associated with secondary recovery projects.
Undeveloped Acreage
The Company’s undeveloped acreage consists of non-producing mineral interests and undeveloped leaseholds. The following table summarizes the Company’s gross and net acres in each at December 31, 2010.
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, 2008 and thereafter, as to net productive and dry exploratory wells drilled and net productive and dry development wells drilled. Net exploratory and development totals for 2010 include the six wells still drilling at the end of 2009. As indicated in the “Development Program” on Page 3 and “Exploration Program” on Page 4, six development wells and two exploratory wells were still in process at the time of this Form 10-K.
Recent Activities
See Item 7, under the subheading “Update of Oil and Gas Exploration and Development Activity from December 31, 2009” for a summary of recent activities related to oil and natural gas operations.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
There are no material legal proceedings pending affecting the Company or any of its properties.
ITEM 4.
ITEM 4.
(REMOVED AND RESERVED)
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCK-HOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
The Company’s stock is dually traded in the Pink Sheet Electronic Quotation Service and the OTC Bulletin Board under the symbol “RSRV.” The following high and low bid information was quoted on the Pink Sheets OTC Market Report. Prices reflect inter-dealer prices without retail markup, markdown, or commission and may not reflect actual transactions.
There was limited public trading in the Company’s common stock in 2010 and 2009. In 2010, there were 20 brokered trades appearing in the Company’s transfer ledger versus 15 in 2009.
At March 25, 2011, the Company had approximately 1,500 record holders of its common stock. The Company paid dividends on its common stock in the amount of $10.00 per share in the second quarter and $30.00 per share in the fourth quarter of 2010, and $10.00 per share in the second quarter of 2009. See the “Financing Activities” section of Item 7 below for more information about dividends paid. Management will review the amount of the annual dividend to be paid in 2011 with the Board of Directors for its approval.
ISSUER PURCHASES OF EQUITY SECURITIES
1The Company has no formal equity security purchase program or plan. The Company acts as its own transfer agent, and most purchases result from requests made by shareholders receiving small, odd lot share quantities as the result of probate transfers.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
Smaller reporting companies are not required to provide the information required by this Item.
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Please refer to the financial statements and related notes in Item 8 of this Form 10-K to supplement this discussion and analysis.
Forward-Looking Statements
In addition to historical information, from time to time the Company may publish forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements provide the reader with management’s current expectations of future events. They include statements relating to such matters as anticipated financial performance, business prospects such as drilling of oil and gas wells, technological development, and similar matters.
Although management believes that the expectations reflected in such forward-looking statements are based on reasonable assumptions, a variety of factors could cause the Company’s actual results and experience to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance, development, and results of the Company’s business include, but are not limited to, the following:
·
The Company’s future operating results will depend upon management’s ability to employ and retain quality employees, generate revenues, and control expenses. Any decline in operating revenues, without corresponding reduction in operating expenses, could have a material adverse effect on the Company’s business, results of operations, and financial condition.
·
The Company has no significant long-term sales contracts for either oil or gas. For the most part, the price the Company receives for its product is based upon the spot market price, which in the past has experienced significant fluctuations. Management anticipates such price fluctuations will continue in the future, making any attempt at estimating future prices subject to significant uncertainty.
·
Exploration costs have been a significant component of the Company’s capital expenditures in the past and are expected to remain so, to a somewhat lesser degree, in the near term. Under the successful efforts method of accounting for oil and gas properties which the Company uses, these costs are capitalized if the prospect is successful or charged to operating costs and expenses if unsuccessful. Estimating the amount of such future costs which may relate to successful or unsuccessful prospects is extremely imprecise at best.
The Company does not undertake any obligation to publicly revise forward-looking statements to reflect events or circumstances that arise after the date hereof. Readers should carefully review the information described in other documents the Company files from time to time with the Securities and Exchange Commission, including the Quarterly Reports on Form 10-Q to be filed by the Company in 2011 and any Current Reports on Form 8-K filed by the Company.
Critical Accounting Estimates
·
Estimates of future revenues from oil and gas sales are derived from a combination of factors which are subject to significant fluctuation over any given period of time. Reserve estimates, by their nature, are subject to revision in the short-term. The evaluating engineer considers production performance data, reservoir data, and geological data available to the Company, as well as makes estimates of production costs, sale prices, and the time period the property can be produced at a profit. A change in any of the above factors can significantly change the timing and amount of net revenues from a property. The Company’s producing properties are composed of many small working interest and royalty interest properties. As a non-operating owner, the Company has limited access to the underlying data from which working interest reserve estimates are calculated, and estimates of royalty interest reserves are not made because the information required for the estimation is not available to the Company. While reserve estimates are not accounting estimates, they are the basis for depreciation, depletion, and amortization described below. Additionally, the estimated economic life for each producing property from the reserve estimates is used in the calculation of asset retirement obligations.
·
The provisions for depreciation, depletion, and amortization of oil and gas properties all constitute critical accounting estimates. Non-producing leaseholds are amortized over the life of the leasehold using a straight line method; however, when leaseholds are impaired or condemned, an appropriate adjustment to the provision is made at that time.
·
The provision for impairment of long-lived assets is determined by review of the estimated future cash flows from the individual properties. A significant, unforeseen downward adjustment in future prices and/or potential reserves could result in a material change in estimated long-lived assets impairment.
·
Depletion and depreciation of oil and gas properties are computed using the units-of-production method. A significant, unanticipated change in volume of production or estimated reserves would result in a material, unexpected change in the estimated depletion and depreciation provisions.
·
The Company has significant obligations to remove tangible equipment and facilities associated with oil and gas wells and to restore land at the end of oil and gas production operations. Removal and restoration obligations are most often associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires estimates and judgments because most of the removal obligations will take effect in the future. Additionally, these operations are subject to private contracts and government regulations that often have vague descriptions of what is required. Asset removal technologies and costs are constantly changing as are regulatory, political, environmental, and safety considerations. Inherent in the present value calculations are numerous assumptions and judgments including the ultimate removal cost amounts, inflation factors, and discount rate.
·
Oil and natural gas sales revenue accrual is another critical accounting estimate. The Company does not operate any of its oil and natural gas properties. Obtaining timely production data on all wells from the operators is not feasible; therefore, the Company utilizes past production receipts and estimated sales price information to estimate its accrual of revenue on all wells each quarter. The oil and natural gas sales revenue accrual can be impacted by many variables, including rapid production decline rates, production curtailments by operators, and rapidly changing market prices for oil and natural gas. These variables could lead to an over or under accrual of oil and natural gas sales at the end of any particular quarter. Based on past history, the Company’s estimated accrual has been materially accurate.
·
The estimation of the amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations as well as the completion of complex calculations, including the determination of the Company’s percentage depletion deduction, if any. To calculate the exact excess percentage depletion allowance, a well-by-well calculation is, and can only be, performed at the end of each fiscal year. During interim periods, a high-level estimate is made taking into account historical data and current pricing. Although the Company’s management believes its tax accruals are adequate, differences may occur in the future depending on the resolution of pending and new tax matters.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Company is affiliated by common management and ownership with Mesquite Minerals, Inc. (Mesquite), Mid-American Oil Company (Mid-American), Lochbuie Limited Partnership (LLTD) and Lochbuie Holding Company (LHC). The Company also owns interests in certain producing and non-producing oil and gas properties as tenants in common with Mesquite, Mid-American and LLTD.
Mason McLain, an officer and director of the Company, is an officer and director of Mesquite and Mid-American. Robert T. McLain and Jerry Crow, Directors of the Company, are directors of Mesquite and Mid-American. Kyle McLain and Cameron R. McLain are sons of Mason McLain, who owns more than 5% of the Company, and are officers and directors of the Company. Kyle McLain and Cameron McLain are officers and directors of Mesquite and Mid-American. Mason McLain and Robert T. McLain, who are brothers, each own an approximate 32% limited partner interest in LLTD, and Mason McLain is president of LHC, the general partner of LLTD. Robert T. McLain is not an employee of any of the above entities and devotes only a small amount of time conducting their business.
The above named officers, directors, and employees as a group, beneficially own approximately 29% of the common stock of the Company, approximately 32% of the common stock of Mesquite, and approximately 17% of the common stock of Mid-American. These three corporations, each, have only one class of stock outstanding. See Item 8, Note 12 to the accompanying financial statements for additional disclosures regarding these relationships.
EQUITY INVESTMENTS
For all of 2009 and 2010, the Company had investments in two entities, which it accounted for on the equity method. In using the equity method, the Company records the original investment in an entity as an asset and adjusts the asset balance for the Company’s share of any income or loss, as well as any additional contributions to or distributions from the entity. The entities include an Oklahoma limited partnership and an Oklahoma limited liability company identified below. The Company does not have actual or effective control of either of the entities. The management of these entities could, at any time, make decisions in their own best interests that could affect the Company’s net income or the value of the Company’s investments.
The entities in which the Company had investments during 2009 and 2010 are Broadway Sixty-Eight, Ltd. (33% limited partnership interest) and JAR Investments, LLC (25% ownership). In November, 2010, JAR Investments, LLC sold its remaining real estate investment and distributed the proceeds to all investees. In December 2010, after a final distribution of the remaining funds, JAR Investments, LLC was dissolved. Broadway Sixty-Eight, Ltd. has a guarantee arrangement under which the Company is contingently liable. See Item 8, Note 7 to the accompanying financial statements for related disclosures and additional information regarding these entities and the JAR Investments, LLC dissolution.
LIQUIDITY AND CAPITAL RESOURCES
To supplement the following discussion, please refer to the Balance Sheets and the Statements of Cash Flows included in this Form 10-K.
In 2010, as in prior years, the Company funded its business activity through the use of internal sources of capital. For the most part, these internal sources are cash flows from operations, cash, cash equivalents and available-for-sale securities. When cash flows from operating activities are in excess of those needed for other business activities, the remaining balance is used to increase cash, cash equivalents and/or available-for-sale securities. When cash flows from operating activities are not adequate to fund other business activities, withdrawals are made from cash, cash equivalents and/or available-for-sale securities. Cash equivalents are highly liquid debt instruments purchased with a maturity of three months or less. Most of the available-for-sale securities are U.S. Treasury Bills.
In 2010, net cash provided by operating activities was $8,343,078. Sales (including lease bonuses), net of production, exploration, and general and administrative costs, and income taxes paid were $8,305,287, which accounted for 99% of net cash provided by operations. The remaining components provided less than 1% of cash flow. In 2010, net cash applied to investing activities was $369,952. In 2010, dividend payments and treasury stock purchases totaled $6,083,300 and accounted for all of the cash applied to financing activities.
Other than cash and cash equivalents, other significant changes in working capital include the following:
Available-for-sale securities decreased $2,931,664 (18%) to $13,138,811 in 2010 from $16,070,475 in 2009. The decrease was due to the need for cash to fund the 2010 capitalized property additions and dividend payments in excess of the cash provided by operations.
Trading securities increased $63,752 (18%) to $414,124 in 2010 from $350,372 in 2009. Most of the increase is due to a $43,225 increase in unrealized gains, which represent the change in the fair value of the securities from their original cost. The remaining increase of $20,527 represents additional securities investments.
Refundable income taxes decreased $32,476 (10%) to $281,832 in 2010 from $314,308 in 2009. This decrease was due to excess 2010 estimated tax payments being less than in 2009.
Receivables increased $355,902 (25%) to $1,800,659 in 2010 from $1,444,757 in 2009. The increase was due primarily to receivables for sales accruals that have increased about $380,000 in 2010 from 2009. This increase was offset by a $25,000 decrease in a note receivable in 2010 from 2009. Additional information about the increase in sales for 2010 is included in the “Results of Operations” section that follows. Information about the note receivable is included in Item 8, Note 7 to the accompanying financial statements.
Prepaid expenses of $197,304 in 2009 were prepaid seismic expenses on a Kansas, prospect. The seismic survey work was completed in February, 2010, and no similar prepayments were made at the end of 2010.
Accounts payable decreased $133,261 (43%) to $177,628 in 2010 from $310,889 in 2009. This decrease was primarily due to the payment of about $131,000 of charges from early 2009 from an operator for the Company’s share of costs on an exploratory well. The operator had filed for bankruptcy and had several liens filed by service company vendors who worked on the well. The amount owed was paid to the bankruptcy trustee in 2010.
Deferred income taxes and other increased $54,560 (27%) to $256,354 in 2010 from $201,794 in 2009. This increase was primarily due to the increase in the current deferred tax accrual due to the increase in the oil and gas sales accrual in 2010.
The following is a discussion of material changes in cash flow by activity between the years ended December 31, 2010 and 2009. Also, see the discussion of changes in operating results under “Results of Operations” below in this Item 7.
Operating Activities
As noted above, net cash flows provided by operating activities in 2010 were $8,343,078, which, when compared to the $5,304,623 provided in 2009, represents an increase of $3,038,455 or 57%. The increase was mostly due to an increase in oil and gas sales cash flows of $2,844,581, an increase in lease bonuses and coal royalties of $1,457,682; a decline in exploration costs of $405,349 and a decline in general, administrative, and other costs of $76,432. Those increases in cash flows were partially offset by an increase in production costs of $346,627; an increase in income taxes paid of $1,292,278; and a decline in interest received of $82,224. Additional discussion of the more significant items follows.
Discussion of Selected Material Line Items Resulting in an Increase in Cash Flows. The $2,844,581 (32%) increase in cash received from oil and gas sales to $11,715,671 in 2010 from $8,871,090 in 2009 was the result of an increase in the average oil and gas prices and the volume of oil sales, offset by a slight decline in the gas sales volume. See “Results of Operations” below for a price/volume analysis and the related discussion of oil and gas sales.
Cash received for lease bonuses and coal royalties increased $1,457,682 (528%) to $1,733,389 in 2010 from to $275,707 in 2009. Most of the increase is due to an increase in cash received for lease bonuses of $1,451,231 in 2010 versus 2009.
Cash flow increased due to a decrease in cash paid for exploration expenses of $405,349 (45%) to $485,872 in 2010 from $891,221 in 2009. About $190,000 of the decrease was due to decreased geological and geophysical expense in 2010 versus 2009 due to the prepaid seismic balance at 2009 year-end. The remaining decrease of about $215,000 was due to lower dry hole costs in 2010 versus 2009.
Discussion of Selected Material Line Items Resulting in a Decrease in Cash Flows. Cash paid for production costs increased $346,627 (22%) to $1,937,064 in 2010 from $1,590,437 in 2009. This increase was due to a $259,815 increase in lease operating and handling expenses and an increase of $86,812 in production taxes in 2010 versus 2009. Most of the lease $259,815 operating expense increase was attributable to higher handling expenses in 2010 versus 2009. The increased handling expense in 2010 was primarily related to the natural gas sales from the two new Van Buren County, Arkansas working interest wells discussed in the "Results of Operations" below. The increase in production taxes was due to the increase in sales in 2010 versus 2009.
Cash received for interest earned on cash equivalents and available-for-sale securities decreased $82,224 (69%) to $36,253 in 2010 from $118,477 in 2009. The decrease was the result of a decrease in the average rate of return to 0.23% in 2010 from 0.73% in 2009 and a slight decline in the average outstanding balance of available-for-sale securities.
Income taxes paid increased $1,292,278 to $1,310,754 in 2010 from $18,476 in 2009 due to no estimated tax payments in 2009.
Investing Activities
Net cash applied to investing activities decreased $3,658,771 (91%) to $369,952 in 2010 from $4,028,723 in 2009. In 2010, net cash flows from available-for-sale securities were $2,931,664 compared to net cash applied of $949,902 in 2009. This change was a result of needing to supplement the operations cash flow for financing activities in 2010 as discussed below. Cash flows related to property acquisitions resulted in an increase in cash applications to investing activities in 2010 versus 2009. Cash applied to property acquisitions increased $312,497 (10%) to $3,534,643 in 2010 from $3,222,146 in 2009 due primarily to increased exploration and development drilling activity. See the “Update of Oil and Gas Exploration and Development Activity from December 31, 2009” under the “Results of Operations” heading below for more information regarding expenditures related to this drilling activity. The increases in cash applications for investing activities were offset by an increase in cash distributions from equity investments of $112,825 to $119,575 in 2010 from $6,750 in 2009. This increase is mostly due to $119,575 of distributions in 2010 from the JAR Investments, LLC. See Item 8, Note 7 to the accompanying financial statements for more information regarding the cash flow from this equity investment.
Financing Activities
Cash applied to financing activities increased $4,427,709 (267%) to $6,083,300 in 2010 from $1,655,591 in 2009. Cash applied to financing activities consist of cash dividends on common stock and cash used for the purchase of treasury stock. In 2010, cash dividends paid on common stock amounted to $6,017,060 as compared to $1,565,551 in 2009. Dividends of $40.00 per share were issued for 2010 and $10.00 per share for 2009. The cash applied to the purchase of treasury stock was $66,240 in 2010 as compared to $90,040 in 2009. The decrease in treasury stock purchases in 2010 from 2009 is due to a combination of fewer shares purchased in 2010 (414 shares) versus 2009 (485 shares) and a lower average price paid in 2010 of $160 per share versus $186 per share in 2009. For additional information about treasury stock purchases, see Note1 at the end of Item 5, "Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” above.
Forward-Looking Summary
The Company’s latest estimate of business to be done in 2011 and beyond indicates the projected activity can be funded from cash flow from operations and other internal sources, including net working capital. The Company is engaged in exploratory drilling. If this drilling is successful, substantial development drilling may result. Also, should other exploration projects which fit the Company’s risk parameters become available or other investment opportunities become known, capital requirements may be more than the Company has available. If so, external sources of financing could be required.
RESULTS OF OPERATIONS
As disclosed in the Statements of Income in Item 8 of this Form 10-K, in 2010 the Company had net income of $5,250,659 as compared to a net income of $1,607,399 in 2009. Net income per share, basic and diluted, was $32.51 in 2010, an increase of $22.59 per share from $9.92 in 2009. Material line item changes in the Statements of Income will be discussed in the following paragraphs.
Operating Revenues
Operating revenues increased $4,816,108 (53%) to $13,829,341 in 2010 from $9,013,233 in 2009. Oil and gas sales increased $3,306,716 (38%) to $12,061,747 in 2010 from $8,755,031 in 2009. Lease bonuses and other revenues increased $1,509,392 to $1,767,594 in 2010 from $258,202 in 2009. This increase was the result of an increase in lease bonuses of $1,451,232 from leases in East Texas and Oklahoma. In addition, coal royalties from North Dakota leases increased $58,160 (28%) to $267,054 in 2010 from $208,894 in 2009. The Company does not anticipate that coal royalties will have a significant impact on its future results of operations. The increase in oil and gas sales is discussed in the following paragraphs.
The $3,306,716 increase in oil and gas sales was the result of a $1,444,276 increase in gas sales, plus a $1,790,274 increase in oil sales and a $72,166 increase in miscellaneous oil and gas product sales. The following price and volume analysis is presented to explain the changes in oil and gas sales from 2009 to 2010. Miscellaneous oil and gas product sales of $264,501 in 2010 and $192,335 in 2009 are not included in the analysis.
The $1,444,276 (32%) increase in natural gas sales to $5,898,016 in 2010 from $4,453,740 in 2009 was the combination of an increase in the average price received per thousand cubic feet (MCF) and a slight decline in gas sales volumes. The average price per MCF of natural gas sales increased $1.31 per MCF to $4.74 in 2010 from $3.43 per MCF in 2009, resulting in a positive gas price variance of $1,630,167. A negative volume variance of $185,891 was the result of a decrease in natural gas volumes sold of 54,196 MCF to 1,243,138 MCF in 2010 from 1,297,334 MCF in 2009. The decrease in the volume of gas production was the net result of new 2010 production of about 360,000 MCF, offset by a decline of 415,000 MCF in production from previous wells. The new 2010 production includes approximately 177,000 MCF of gas sales from two working interest wells in Van Buren County, Arkansas that were drilled in late 2009 and began producing in January, 2010. As disclosed in Supplemental Schedule 1 of the Unaudited Supplemental Financial Information included in Item 8 below, working interests in natural gas extensions and discoveries were adequate to replace working interest reserves produced in 2009 and 2010.
The gas production for 2009 and 2010 includes production from several royalty interest properties drilled by various operators in Robertson County, Texas. These properties accounted for approximately 729,000 MCF and $2,504,000 of the 2009 gas sales and approximately 540,000 MCF and $2,450,000 of the 2010 gas sales. These properties accounted for about 42% of the Company’s 2010 gas revenues and continue to have a significant impact on our operating income. While the operators are currently drilling and plan more drilling in the future on the acreage in which the Company holds mineral interests, the Company has no control over the timing of such activity.
The $1,790,274 (44%) increase in crude oil sales to $5,899,230 in 2010 from $4,108,956 in 2009 was the result of an increase in both the average price per barrel (Bbl) and oil sales volumes. The average price received per Bbl of oil increased $20.17 to $71.81 in 2010 from $51.64 in 2009, resulting in a positive oil price variance of $1,657,087. An increase in oil sales volumes of 2,579 Bbls to 82,155 Bbls in 2010 from 79,576 Bbls in 2009 resulted in a positive volume variance of $133,187. The increase in the oil volume production was the net result of new 2010 production of about 16,600 Bbls, offset by a 14,000 Bbl decline in production from older producing properties. Of the new 2010 production, approximately 9,400 Bbls (56%) was from Woods County, Oklahoma, about 3,600 Bbls (22%) was from new working interest wells in Kansas and Oklahoma (in counties other than Woods), and about 3,600 Bbls (22%) was from new royalty interest wells in Texas. As disclosed in Supplemental Schedule 1 of the Unaudited Supplemental Financial Information included below in Item 8, working interests in oil extensions and discoveries were adequate to replace working interest reserves produced in 2010 but not in 2009.
For both oil and gas sales, the price change was mostly the result of a change in the spot market prices upon which most of the Company’s oil and gas sales are based. These spot market prices have had significant fluctuations in the past and these fluctuations are expected to continue. Spot market price declines in 2009 for both crude oil and natural gas provided an excellent example of the fluctuations that can and do occur, and the impact they can have on operating results.
Operating Costs and Expenses
Operating costs and expenses decreased $476,653 (6%) to $6,994,660 in 2010 from $7,471,313 in 2009, primarily due to decreases in depreciation, depletion, and amortization and exploration costs, offset by an increase in production expense. The material components of operating costs and expenses are discussed below.
Production Costs. Production costs increased $333,863 (21%) to $1,942,855 in 2010 from $1,608,992 in 2009. The increase was the result of a $86,812 (23%) increase in gross production tax (net of production tax refunds) to $468,413 in 2010 from $381,601 in 2009, plus an increase in lease operating and handling expense of $247,052 (20%) to $1,474,443 in 2010 from $1,227,391 in 2009. Most of the increase in lease operating and handling expense was due to an increase in handling expense of $149,579 (47%) to $471,017 in 2010 from $321,438 in 2009. About $122,500 of the handling expense increase was on the two new Van Buren County, Arkansas working interest wells discussed in the “Operating Revenues” section above. Handling expense is comprised of gas gathering, treating, transportation, and compression costs. Gross production taxes are state taxes, which are calculated as a percentage of gross proceeds from the sale of products from each producing oil and gas property; therefore, they fluctuate with the change in the dollar amount of revenues from oil and gas sales. Most of the gross production tax refunds relate to the Robertson County, Texas properties and are due to a Texas program used as an incentive to encourage operators to drill deep or tight sands gas wells. These refunds are not permanent but are for a limited number of months of production.
Exploration and Development Costs. Under the successful efforts method of accounting used by the Company, geological and geophysical costs are expensed as incurred as are the costs of unsuccessful exploratory drilling. The costs of successful exploratory drilling and all development costs are capitalized. Total costs of exploration and development, excluding asset retirement obligations but inclusive of geological and geophysical costs, were $3,756,837 in 2010 and $3,693,128 in 2009. See Item 8, Note 8 to the accompanying financial statements for additional information regarding a breakdown of these costs. Exploration costs charged to operations were $556,636 in 2010 and $987,088 in 2009, inclusive of unsuccessful exploratory well costs of $363,536 in 2010 and $694,762 in 2009 and geological and geophysical costs of $193,100 in 2010 and $292,326 in 2009.
Update of Oil and Gas Exploration and Development Activity from December 31, 2009. For the 12 months ended December 31, 2010, the Company participated in the drilling of 15 gross exploratory and 21 gross development working interest wells with working interests ranging from a high of 18% to a low of 4.8%. Of the 15 exploratory wells, 6 were completed as producing wells, 7 as dry holes and 2 were in progress. Of the 21 development wells, 15 were completed as producing wells and 6 were in progress. In management’s opinion, the exploratory drilling summarized above has produced some possible development drilling opportunities.
The following is a summary as of March 4, 2011, updating both exploration and development activity from December 31, 2009, for the period ended December 31, 2010.
The Company participated with its 18% working interest in the drilling of six development wells on two adjoining Barber County, Kansas prospects. Three of the wells were completed as oil and gas producers; one commercial and the other two marginal. Completion attempts are in progress on the other three wells. Capitalized well costs for the period were $488,706, including $140,196 in prepaid drilling costs.
The Company is participating in the acquisition of leasehold on a Grady County, Oklahoma prospect in which it has a 10% interest. A 3-D seismic survey was conducted in 2009 and potential drilling locations were identified. An exploratory well will likely be drilled in the third quarter of 2011. Total capitalized leasehold costs for the period were $39,569 and seismic costs were $3,480.
The Company participated with its 18% working interest in the drilling of three step-out wells on a Comanche County, Kansas prospect (two of these wells were started in 2009). All three wells were completed as marginal oil producers. Capitalized costs for the period were $84,600, including $32,032 in prepaid drilling costs.
The Company participated with its 18% working interest in the drilling of an exploratory well on a Comanche County, Kansas prospect. The well has been completed, testing gas at a commercial rate, and is currently shut in awaiting pipeline construction. Capitalized costs for the period were $84,600, including $28,043 in prepaid drilling costs.
The Company participated with its 16% working interest in the drilling of two wells, one exploratory and the other a step-out, on a Harper County, Kansas prospect. The exploratory well was completed as a commercial oil producer. The step-out well was completed as a commercial gas producer. Total capitalized costs for the period were $122,445.
The Company participated with an 18% interest in the development of a McClain County, Oklahoma prospect. Acreage has been acquired, and it is likely that an exploratory well will be drilled in 2011.
The Company participated with its 16% working interest in the drilling of an exploratory well on another McClain County, Oklahoma prospect (the well was started in 2009). The well was completed as a marginal oil and gas producer. Capitalized costs for the period were $89,976.
The Company is participating with a 21% interest in the development of a Lincoln County, Oklahoma prospect. Acreage has been acquired, and the prospect is under evaluation for the possible drilling of an exploratory horizontal well in 2011. Leasehold costs were $1,233 for the period.
The Company participated with a 14% working interest in the drilling of two step-out wells on a Woods County, Oklahoma prospect. Both wells were completed as commercial oil and gas producers. Two additional development wells will be drilled in 2011. Capitalized costs for the period were $162,400, including $3,235 in prepaid drilling costs.
The Company participated in the drilling of nine step-out wells on a Woods County, Oklahoma prospect in which it has a 10.5% interest (three of these wells were started in 2009; the Company has reduced working interests of 2.7% and 9.6% in the third and ninth wells). Seven of the wells were completed as commercial oil and gas producers. Completion attempts are in progress on the other two wells. Total capitalized costs for the period were $377,481.
The Company participated in the drilling of two development wells (18% and 13.7% working interests) on a Woods County, Oklahoma prospect (these wells were started in 2009). Both wells were completed as commercial oil and gas producers. Capitalized costs for the period were $20,586.
The Company participated with its 16% working interest in the drilling of a step-out well and five exploratory wells on a Ford County, Kansas prospect (two of these wells were started in 2009). The step-out well and one exploratory well were completed as commercial oil producers. Two of the other exploratory wells were completed as dry holes. Completion attempts on the remaining two wells were unsuccessful and they will be plugged. Capitalized costs for the period were $51,980, including $5,565 in prepaid drilling costs. Dry hole costs for the period were $231,033.
The Company participated with its 16% interest in a 3-D seismic survey and in the drilling of three exploratory wells and a step-out well on a Hodgeman County, Kansas prospect. One exploratory well and the step-out well were completed as commercial oil producers. The other two wells were completed as dry holes. An additional step-out well and an additional exploratory well will be drilled in 2011. Capitalized costs for the period were $169,597, including $16,954 in prepaid drilling costs. Dry hole costs for the period were $70,403.
The Company participated in the drilling of two additional horizontal wells in a Harding County, South Dakota waterflood unit in which it has an 8.3% working interest. Both wells were completed as commercial oil producers. Both will be converted to water injection wells in 2011. Two additional horizontal wells will be drilled in 2011. Total capitalized costs for the unit for the period were $395,309.
Another Harding County, South Dakota waterflood unit was enlarged effective June 1, 2010, reducing the Company’s working interest from 4.3% to 4.1%. An additional horizontal development well was drilled and completed as a commercial oil producer. Capitalized costs for the period were $105,423.
The Company participated with a fee mineral interest in the drilling of an exploratory horizontal well in Harding County, South Dakota. The well, in which the Company has an 8.3% interest, was completed as a commercial oil producer. Capitalized costs for the period were $217,300.
The Company participated with its 4.8% working interest in the drilling of a horizontal development well on a Dewey County, Oklahoma prospect. The well was completed as a marginal oil producer. Capitalized costs for the period were $208,608.
In April 2010, the Company purchased an 18% interest in 6,560 net acres of leasehold on a Sumner and Harper Counties, Kansas prospect for $70,848. An exploratory well (a re-entry and washdown of an old dry hole) was drilled and completed as a dry hole. Dry hole costs for the period were $32,090 and leasehold impairments were $70,848.
In April 2010, the Company agreed to purchase a 16% interest in 986.66 net acres of leasehold on a Beaver County, Oklahoma prospect for $42,666. An exploratory well will be drilled in 2011.
The Company is participating with fee mineral interests in the drilling of three horizontal development wells in Faulkner County, Arkansas. The first well, in which the Company has a 4.7% interest, was completed as a commercial gas well. The second well (3.4% interest) has been drilled and a completion attempt is in progress. The third well (2.2% interest) will be drilled in 2011. Capitalized costs for the period were $388,049, including $115,861 in prepaid drilling costs.
In August 2010, the Company paid $13,440 for interests (16%, 12.8% and 16%) in three wells in Woods County, Oklahoma, along with the rights to drill up to four additional wells. Work has been performed on two of the wells to restore commercial production and a step-out well will be drilled in 2011. Capitalized costs for the period were $64,224.
In September 2010, the Company purchased an 8% interest in a Custer County, Oklahoma prospect for $5,951. An exploratory well was drilled and completed as a commercial oil and gas producer. Capitalized costs for the period were $81,608.
In November 2010, the Company purchased a 10.5% interest in 799 net acres of leasehold on a Custer County, Oklahoma prospect for $35,597. An exploratory well has been drilled and a completion attempt is in progress. Capitalized costs for the period were $38,398.
In October 2010, the Company agreed to purchase a 10.5% interest in 1,553 net acres of leasehold on a Custer County, Oklahoma prospect for $59,321. An exploratory horizontal well will be drilled in 2011.
In December 2010, the Company purchased 18% interests in two Rice County, Kansas prospects for $14,108. An exploratory well was drilled on each prospect in 2011. Both were completed as dry holes. Prepaid drilling costs at year-end were $75,893.
In February 2011, the Company purchased 18% interests in two prospects in Ness and Hodgeman Counties, Kansas for $17,798. An exploratory well will be drilled on each prospect in 2011.
Depreciation, Depletion, Amortization and Valuation Provisions (DD&A). Major DD&A components are the provision for impairment of undeveloped leaseholds, provision for impairment of long-lived assets, depletion of producing leaseholds and depreciation of tangible and intangible lease and well costs. Undeveloped leaseholds are amortized over the life of the leasehold (most are 3 years) using a straight line method, except when the leasehold is impaired or condemned by drilling and/or geological interpretation of seismic data; if so, an adjustment to the provision is made at the time of impairment. The provision for impairment of undeveloped leaseholds was $313,801 in 2010 and $369,915 in 2009. Of the 2010 provision, $202,373 was due to the annual amortization of undeveloped leaseholds and $111,427 was due to specific leasehold impairments. The 2009 provision was due to the annual amortization of undeveloped leaseholds of $327,528 and specific leasehold impairments of $42,387.
As discussed in Item 8, Note 10 to the accompanying financial statements, accounting principles require the recognition of an impairment loss on long-lived assets used in operations when indicators of impairment are present. Impairment evaluation is a two-step process. The first step is to measure when the undiscounted cash flows estimated to be generated by those assets, determined on a well basis, is less than the assets’ carrying amount. Those assets meeting the first criterion are adjusted to estimated fair value. Evaluation for impairment was performed in both 2010 and 2009. The 2010 impairment loss was $703,645 and 2009 impairment loss was $1,353,020. The depressed average oil and natural gas prices for 2009 had a significant impact on the undiscounted cash flows of future production and fair value estimates, and accordingly, the large impairment loss for 2009.
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 $2,051,253 in 2010 and $1,700,964 in 2009. Most of the increase of $350,289 is due to increased oil and gas property additions in 2010 and changes in reserve estimates. It also includes $72,212 for 2010 and $80,636 for 2009 for the amortization of the Asset Retirement Obligation. See Item 8, Note 2 to the accompanying financial statements for additional information regarding the Asset Retirement Obligation.
Equity Income in Investees. The following is an analysis of equity income in investees by entity for the years ended December 31, 2010 and 2009. See Item 8, Note 7 to the accompanying financial statements for more information about these investments.
Other Income (Loss), Net. See Item 8, Note 11 to the accompanying financial statements for an analysis of the components of this line item for the years ended December 31, 2010 and 2009. Other income, net declined $91,735 (38%) to $152,723 in 2010 from $244,458 in 2009. The line items responsible for this decline are described below.
Net realized and unrealized gains (losses) on trading securities decreased $67,116 to a net gain of $62,325 in 2010 from a net gain of $129,441 in 2009. Realized gains or losses result when a trading security is sold. Unrealized gains or losses result from adjusting the Company’s carrying amount in trading securities owned at the reporting date to estimated fair value. In 2010, the Company had realized gains of $19,100 and unrealized gains of $43,225. In 2009, the Company had realized gains of $38,884 and unrealized gains of $90,557.
Interest income decreased $37,267 (51%) to $36,261 in 2010 from $73,528 in 2009. This decrease was the result of a decrease in the average rate of return on cash equivalents and available-for-sale securities from which most of interest income is derived. The average rate of return decreased 0.50% to 0.23% in 2010 from 0.73% in 2009. A decrease of only $543,882 in the average balance outstanding to $15,737,781 in 2010 from $16,281,663 in 2009 had minimal impact on the total return.
Settlements of class action lawsuits decreased $24,839 to $107 in 2010 from $24,946 in 2009. There were no settlements in 2010 similar to those occurring in 2009.
Provision for Income Taxes. See Item 8, Note 6 to the accompanying financial statements for an analysis of the various components of income taxes. In 2010, the Company had an estimated provision for income taxes of $1,865,889 as the result of a current tax provision of $1,343,230 and a deferred tax provision of $522,659. In 2009, the Company had an estimated provision for income taxes of $213,975 as the result of a current tax provision of $703,741 less a deferred tax benefit of ($489,766).
ITEM 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Smaller reporting companies are not required to provide the information required by this Item.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
The Reserve Petroleum Company
We have audited the accompanying balance sheet of The Reserve Petroleum Company as of December 31, 2010 and 2009, and the related statements of income, stockholders’ equity and cash flows for the years ended December 31, 2010 and 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of The Reserve Petroleum Company and the results of its operations and cash flows for the years ended December 31, 2010 and 2009, in conformity with U.S. generally accepted accounting principles.
We were not engaged to examine management’s assessment of the effectiveness of The Reserve Petroleum Company’s internal control over financial reporting as of December 31, 2010, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting and, accordingly, we do not express an opinion thereon.
/s/ HoganTaylor LLP
Oklahoma City, Oklahoma
March 31, 2011
See Accompanying Notes
See Accompanying Notes
See Accompanying Notes
See Accompanying Notes
See Accompanying Notes
See Accompanying Notes
THE RESERVE PETROLEUM COMPANY
NOTES TO FINANCIAL STATEMENTS
Note 1 - NATURE OF OPERATIONS
The Company is principally engaged in oil and natural gas exploration and development and minerals management with areas of concentration in Texas, Oklahoma, Kansas, Arkansas and South Dakota, a single business segment.
Note 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Cash and Cash Equivalents
The Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents.
Investments
Marketable Securities:
The Company classifies its debt and marketable equity securities in one of three categories: trading, available-for-sale and held-to-maturity. Trading securities are bought and held principally for the purposes of selling them in the near term. Held-to-maturity securities are those securities in which the Company has both the ability and intent to hold the security until maturity. All other securities not included in trading or held-to-maturity are classified as available-for-sale.
Trading and available-for-sale securities are recorded at fair value. Unrealized gains and losses on trading securities, which consist primarily of equity securities, are reported in current earnings.
Unrealized gains and losses on available-for-sale securities, which consist almost entirely of U.S. Government securities, are reported as a component of other comprehensive income when significant to the financial statements.
Equity Investments:
The Company accounts for its non-marketable investment in a partnership on the equity basis. See Note 7 for additional information.
Receivables and Revenue Recognition
Oil and gas sales and resulting receivables are recognized when the product is delivered to the purchaser and title has transferred. Sales are to credit-worthy major energy purchasers with payments generally received within 60 days of transportation from the well site. Historically, the Company has had little, if any, uncollectible receivables; therefore, an allowance for uncollectible accounts has not been provided.
Property and Equipment
Oil and gas properties are accounted for on the successful efforts method. The acquisition, exploration and development costs of producing properties are capitalized. The Company has not, historically, had any capitalized exploratory drilling costs that are pending determination of reserves for more than one year. All costs relating to unsuccessful exploratory wells, geological and geophysical costs, delay rentals, and abandoned properties are expensed. Lease costs related to unproved properties are amortized over the life of the lease and are assessed for impairment periodically. Any impairment of value is charged to expense.
Depreciation, depletion and amortization of producing properties are computed on the units-of-production method on a property-by-property basis. The units-of-production method is based primarily on estimates of proved reserve quantities. Due to uncertainties inherent in this estimation process, it is at least reasonably possible that reserve quantities will be revised in the near term. Changes in estimated reserve quantities are applied to depreciation, depletion and amortization computations prospectively.
Other property and equipment are depreciated on the straight-line, declining-balance, or other accelerated methods as appropriate.
The following estimated useful lives are used for the different types of property:
Impairment losses are recorded on long-lived assets used in operations when indicators of impairment are present. The Company uses its oil and gas reserve reports to test each producing property for impairment annually. See Note 10 for discussion of impairment losses.
Income Taxes
The Company utilizes a liability approach to calculating deferred income taxes. Deferred income taxes are provided to reflect temporary differences in the basis of net assets and liabilities for income tax and financial reporting purposes. Deferred tax assets are reduced by a valuation allowance if a determination is made that it is more likely than not that some or all of the deferred assets will not be realized based on the weight of all available evidence.
The Company recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based upon the technical merits of the position. The Company will record the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement with taxing authorities.
The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense. The federal income tax returns for 2008 and 2009 are subject to examination.
Earnings Per Share
Accounting guidance for Earnings Per Share (EPS) establishes the methodology of calculating basic earnings per share and diluted earnings per share. The calculations of basic earnings per share and diluted earnings per share differ in that instruments convertible to common stock (such as stock options, warrants, and convertible preferred stock) are added to weighted average shares outstanding when computing diluted earnings per share. For the years ended December 31, 2010 and 2009, the Company had no dilutive shares outstanding; therefore, basic and diluted earnings per share are the same.
Concentrations of Credit Risk and Major Customers
The Company’s receivables relate primarily to sales of oil and natural gas to purchasers with operations in Texas, Oklahoma, Kansas, and South Dakota. The Company had two purchasers in 2010 and four purchasers in 2009 whose purchases were in excess of 10% of total oil and gas sales.
The Company maintains its cash in bank deposit accounts, which at times may exceed federally insured limits. The Company has not experienced any losses in such accounts, and believes that it is not exposed to any significant credit risk with respect to cash and cash equivalents.
Use of Estimates
The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include oil and natural gas reserve quantities that form the basis for the calculation of amortization of oil and natural gas properties. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories. Actual results could differ from the estimates and assumptions used in the preparation of the Company’s financial statements.
Gas Balancing
Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability is recorded when the Company’s excess takes of natural gas volumes exceed our estimated remaining recoverable reserves (over produced). No receivables are recorded for those wells where the Company has taken less than our ownership share of gas production (under produced).
Guarantees
At the inception of a guarantee or subsequent modification, the Company records a liability for the fair value of the obligation undertaken in issuing the guarantee. The Company records a liability for its obligations when it becomes probable that the Company will have to perform under the guarantee. The Company has issued a guarantee associated with the Company’s equity investment in Broadway Sixty-Eight, Ltd.
Asset Retirement Obligation
The Company records the fair value of its estimated liability to retire its oil and natural gas producing properties in the period in which it is incurred (typically date of first sales). The estimated liability is calculated by obtaining current estimated plugging costs from the well operators and inflating it over the life of the property. Current year inflation rate used is 4.06%. When the liability is first recorded, a corresponding increase in the carrying amount of the related long-lived asset is also recorded. Subsequently, the asset is amortized to expense over the life of the property and the liability is increased annually for the change in its present value which is currently 3.25%.
The following table summarizes the asset retirement obligation for the years ended December 31:
New Accounting Pronouncements
In December 2010, the FASB issued Accounting Standards Update 2010-28, “Intangibles - Goodwill and Other: When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts” (“ASU 2010-28”). ASU 2010-28 requires step two of the goodwill impairment test to be performed when the carrying value of a reporting unit is zero or negative, if it is more likely than not that a goodwill impairment exists. The requirements of ASU 2010-28 are effective for fiscal years beginning after December 15, 2010. As the Company currently has no recorded goodwill, adoption of ASU 2010-28 will have no impact on our financial position or results of operations.
In December 2010, the FASB issued Accounting Standards Update 2010-29, “Business Combinations: Disclosure of Supplementary Pro Forma Information for Business Combinations” (“ASU 2010-29”). ASU 2010-29 clarifies that when presenting comparative pro forma financial statements in conjunction with business combination disclosures, revenue and earnings of the combined entity should be presented as though the business combination that occurred during the current year had occurred as of the beginning of the comparable, prior annual reporting period. In addition, the update requires a description of the nature and amount of material, nonrecurring pro forma adjustments included in pro forma revenue and earnings that are directly attributable to the business combination. ASU 2010-29 is effective, prospectively, for business combinations that occur on or after the beginning of the first annual reporting period after December 15, 2010. As ASU 2010-29 relates to disclosure requirements and the Company has never had a business combination, adoption of this standard will have no impact on the Company’s financial condition, results of operations, or disclosures
Reclassifications
Certain amounts in the 2009 financial statements have been reclassified to conform to the 2010 presentation. The amounts were not material to the financial statements and had no effect on previously reported net income.
Note 3 - DIVIDENDS PAYABLE
Dividends payable 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:
Note 5 - MARKETABLE SECURITIES
At December 31, 2010, available-for-sale securities, consisting almost entirely of U.S. government securities are due within one year or less by contractual maturity.
For trading securities during 2010, the Company recorded realized gains of $19,100 and unrealized gains of $43,225. During 2009, the Company recorded realized gains of $38,884 and unrealized gains of $90,557.
Note 6 - INCOME TAXES
Components of deferred taxes are as follows:
The following table summarizes the current and deferred portions of income tax expense/(benefit):
The total provision for income tax expressed as a percentage of income before income tax was 26% in 2010 and 12% in 2009. These amounts differ from the amounts computed by applying the statutory U.S. federal income tax rate of 34% for 2010 and 2009 to income before income tax as summarized in the following reconciliation:
Note 7 - EQUITY INVESTMENTS
The carrying values of Equity Investments consist of the following at December 31:
Broadway Sixty-Eight, Ltd. (the “Partnership”), an Oklahoma limited partnership, owns and operates an office building in Oklahoma City, Oklahoma. Although the Company invested as a limited partner, it agreed, jointly and severally, with all other limited partners to reimburse the general partner for any losses suffered from operating the Partnership. The indemnity agreement provides no limitation to the maximum potential future payments. To date, no monies have been paid with respect to this agreement.
The Company leases its corporate office from the Partnership. The operating lease, under which the space was rented, expired February 28, 1994, and the space is currently rented on a year-to-year basis under the terms of the expired lease. Rent expense for lease of the corporate office from the Partnership was approximately $29,500 and $28,500 for the years ended December 31, 2010 and 2009, respectively.
Included with Receivables is a Note receivable in the amount of $50,000 from the Partnership bearing 3.5% interest and due December 31, 2010. On December 31, 2010, the interest due on this note was received along with a new Note receivable from the Partnership bearing 3.5% interest and due June 30, 2011. The Note receivable and interest rate included with Receivables at December 31, 2009 was $75,000 with a 3.5% rate. This related party transaction is connected to the construction of a new office building.
JAR Investment, LLC (JAR), an Oklahoma limited liability company, previously held Oklahoma City metropolitan area real estate that was sold in June 2005 (see below). JAR also owned a 70% management interest in Main-Eastern, LLC (M-E), an Oklahoma limited liability company. M-E was formed in 2002 to establish a joint venture to develop a retail/commercial center on a portion of JAR’s real estate.
The Company had a guarantee agreement related to an outstanding loan by M-E. M-E’s retail/commercial center was sold on November 5, 2010 and the loan was paid-off at closing. Immediately after closing, JAR distributed funds from the sale, and a final distribution of the remaining cash was received in December, 2010 and JAR was dissolved. Income from this equity investment for 2010 totaled $122,312 and included approximately $110,000 of gain from the sale of M-E’s developed property.
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:
Note 9 - FAIR VALUE MEASUREMENTS
Inputs used to measure fair value are organized into a fair value hierarchy based on how observable the inputs are. Level 1 inputs consist of quoted prices in active markets for identical assets. Level 2 inputs are inputs, other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs.
Recurring Fair Value Measurements
Certain of the Company’s assets are reported at fair value in the accompanying balance sheets on a recurring basis. The Company determined the fair value of the available-for-sale securities using quoted market prices for securities with similar maturity dates and interest rates. At December 31, 2010 and 2009, the Company’s assets reported at fair value on a recurring basis are summarized as follows:
Non-recurring Fair Value Measurements
The Company’s asset retirement obligations incurred annually represent non-recurring fair value liabilities. The fair value of these non-financial liabilities incurred was $122,104 in 2010 and $108,024 in 2009 and was calculated using Level 3 inputs. See Note 2 above for more information about this liability and the inputs used for calculating fair value.
The impairment losses of $703,645 for 2010 and $1,353,020 for 2009 also represent non-recurring fair value expenses. See Note 10 below for the inputs that are used for calculating these expenses.
Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, trade receivables, marketable securities, trade payables, and dividends payable. As of December 31, 2010 and 2009, the historical cost of cash and cash equivalents, trade receivables, trade payables, and dividends payable are considered to be representative of their respective fair values due to the short-term maturities of these items.
Note 10 - LONG-LIVED ASSETS IMPAIRMENT LOSS
Certain oil and gas producing properties have been deemed to be impaired because the assets, evaluated on a property-by-property basis, are not expected to recover their entire carrying value through future cash flows. Impairment losses totaling $703,645 for the year ended December 31, 2010 and $1,353,020 for the year ended December 31, 2009 are included in the Statements of Income in the line item Depreciation, Depletion, Amortization and Valuation Provisions. The impairments for 2010 and 2009 were calculated by reducing the carrying value of the individual properties to an estimated fair value equal to the discounted present value of the future cash flow from these properties. An average monthly price was used for calculating future revenue and cash flow.
Note 11 - OTHER INCOME, NET
The following is an analysis of the components of Other Income, Net for the years ended December 31, 2010 and 2009:
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 2010 in the amount of $158,537 each by Mesquite, Mid-American and LLTD. Reimbursements for 2009 were $146,217 each by Mesquite, Mid-American and LLTD. Included in the 2010 amounts, Mesquite, Mid-American and LLTD each paid $110,533 for their share of salaries. In 2009, the share of salaries paid by Mesquite, Mid-American and LLTD was $106,528 each.
UNAUDITED SUPPLEMENTAL FINANCIAL INFORMATION
SUPPLEMENTAL SCHEDULE 1
See notes on next page.
SUPPLEMENTAL SCHEDULE 1
THE RESERVE PETROLEUM COMPANY
WORKING INTERESTS RESERVE QUANTITY INFORMATION
(Unaudited)
Notes:
1.
Estimates of royalty interests’ reserves, on properties in which the company doesn't own a working interest, 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 15,082 Bbls of oil and 670,070 MCF of gas for the year ended December 31, 2010, and 14,145 Bbls of oil and 897,388 MCF of gas for the year ended December 31, 2009.
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, 2010 and 2009. The Company engineer’s qualifications in the Proxy Statement are incorporated herein by reference. All reserves are located within the United States.
3.
The Company emphasizes that the reserve volumes shown are estimates, which by their nature are subject to revision in the near term. The estimates have been made by utilizing geological and reservoir data, as well as actual production performance data available to the Company. These estimates are reviewed annually and are revised upward or downward as warranted by additional performance data. The Company’s engineer is not independent, but strives to use an objective approach in calculating the Company’s working interest reserve estimates.
4.
The Company's internal controls relating to the calculation of its working interests' reserve estimates include review and testing of the accounting data flowing into the calculation of the reserve estimates. In addition, the average oil and natural gas product prices calculated in the engineer's 2010 summary reserve report was tested by comparison to 2010 average sales price information from the accounting records.
SUPPLEMENTAL SCHEDULE 2
Estimates of future net cash flows from the Company’s proved working interests in oil and gas reserves are shown in the table above. These estimates, which by their nature are subject to revision in the near term, were based on an average monthly product price received by the Company for the twelve months ended December 31, 2009 and 2010, with no escalation. The development and production costs are based on year-end cost levels, assuming the continuation of existing economic conditions. Cash flows are further reduced by estimated future income tax expense calculated by applying the current statutory income tax rates to the pretax net cash flows, less depreciation of the tax basis of the properties and depletion applicable to oil and gas production.
SUPPLEMENTAL SCHEDULE 3
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
As defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (the "Exchange Act"), the term "disclosure controls and procedures" means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
The Company's Principal Executive Officer and Principal Financial Officer evaluated the effectiveness of the Company's disclosure controls and procedures and concluded that the Company's disclosure controls and procedures were effective as of December 31, 2010.
Changes in Internal Control over Financial Reporting
There were no changes in the Company’s internal control over financial reporting during the quarter ended December 31, 2010, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.
Management's Annual Report on Internal Control over Financial Reporting
The management of The Reserve Petroleum Company is responsible for establishing and maintaining adequate internal control over financial reporting for the Company as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. This system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.
The Company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and the directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company's assets that could have a material effect on the financial statements, and provide reasonable assurance as to the detection of fraud.
Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time.
With the participation of the Chief Executive Officer and Chief Financial Officer, the Company’s management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting, based on the framework and criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, the Company’s management concluded that the Company's internal control over financial reporting was effective as of December 31, 2010.
This Annual Report on Form 10-K does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to new 2010 rules of the Securities and Exchange Commission that permanently exempt smaller reporting companies.
/s/ Cameron R. McLain
/s/ James L. Tyler
Cameron R. McLain, President
James L. Tyler, 2nd Vice President
Principal Executive Officer
Principal Financial Officer
March 31, 2011
March 31, 2011
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information regarding directors and executive officers, compliance with Section 16(a) of the Exchange Act, the Company’s Code of Ethics, and Corporate Governance in the Proxy Statement is incorporated herein by reference.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
Information regarding executive compensation in the Proxy Statement is incorporated herein by reference.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information regarding security ownership of certain beneficial owners and management and related stockholder matters in the Proxy Statement is incorporated herein by reference.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8, Note 12 to Financial Statements. Information regarding the independence of our directors in the Proxy Statement is incorporated herein by reference.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information regarding fees billed to the Company by its independent registered public accounting firm in the Proxy Statement is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The following documents are exhibits to this Form 10-K. Each document marked by an asterisk is filed electronically herewith.
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:
/s/ Mason McLain
/s/ Jerry L. Crow
Mason W. McLain (Director)
Jerry L. Crow (Director)
March 31, 2011
March 31, 2011
/s/ Robert L. Savage
/s/ William M. Smith
Robert L. Savage (Director)
William M. Smith (Director)
March 31, 2011
March 31, 2011