Attached files
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
| ☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| For the Fiscal Year Ended December 31, 2013 | ||
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File Number 0-8157
THE RESERVE PETROLEUM COMPANY
(Exact Name of Registrant as Specified in Its Charter)
| DELAWARE | 73-0237060 | |
| (State or Other Jurisdiction of Incorporation or Organization) | (I.R.S. Employer Identification No.) |
6801 Broadway ext., Suite 300
Oklahoma City, Oklahoma 73116-9037
(405) 848-7551
(Address and telephone number, including area code, of registrant’s principal executive offices)
Securities registered under Section 12(b) of the Exchange Act: NONE
Securities registered under Section 12(g) of the Exchange Act:
COMMON STOCK ($0.50 PAR VALUE)
(Title of Class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ☐ No ☒
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):
| Large accelerated filer | ☐ | Accelerated filer | ☐ | Non-accelerated filer | ☐ | Smaller reporting company | ☒ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
As of June 28, 2013, (the last business day of the registrant’s most recently completed second fiscal quarter), the aggregate market value of the voting and non-voting common stock of the registrant held by non-affiliates of the registrant was $34,568,417, as computed by reference to the last reported sale which was on June 27, 2013.
As of March 21, 2014, there were 159,045 shares of the registrant’s common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement (the “Proxy Statement”) relating to the registrant’s Annual Meeting of Shareholders to be held on May 20, 2014, which will be filed within 120 days of the end of the registrant’s year ended December 31, 2013, are incorporated by reference into Part III of this Form 10-K to the extent described therein.
TABLE OF CONTENTS
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This Report on Form 10-K contains forward-looking statements. Actual events and/or future results of operations may differ materially from those contemplated by such forward-looking statements. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a summation of some of the risks and uncertainties inherent in forward-looking statements. Readers should consider the risks and uncertainties described in connection with any forward-looking statements that may be made in this Form 10-K. Readers should carefully review this Form 10-K in its entirety including, but not limited to, the Company’s financial statements and the notes thereto and the risks and uncertainties described herein. Forward-looking statements contained in this Form 10-K speak only as of the date of this Form 10-K. The Company does not undertake to update its forward-looking statements.
| 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 256,364 gross acres equivalent to 88,445 net acres. These mineral interests are located in nine different states in the north and south central United States. A total of 81,311 (92%) net acres are located in the States of Arkansas, Kansas, Oklahoma, South Dakota and Texas, the areas of concentration for the Company in its recent exploration and development programs.
The Company has several options relating to the exploration and/or development of these owned mineral interests. Management continually reviews various industry reports and other sources for activity (leasing, drilling, significant discoveries, etc.) in areas where the Company has mineral ownership. Based on its analysis of any activity and assessment of the potential risk relative to the particular area, management may negotiate a lease or farmout agreement and accept a royalty interest, or it may choose to participate as a working interest owner and pay its proportionate share of any exploration or development drilling costs.
A substantial amount of the Company’s oil and gas revenue has resulted from its owned mineral property management. In 2013, $5,108,703 (28%) of oil and gas sales was from royalty interests versus $3,517,635 (27%) in 2012. As a result of its mineral ownership, the Company had royalty interests in 34 gross (0.69 net) wells, which were drilled and completed as producing wells in 2013. This resulted in an average royalty interest of about 2.0% for these 34 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 2013, the Company participated in the drilling of 34 development wells with 32 wells (4.24 net), including the 8 wells in progress at the end of 2012, completed as producers and 2 wells (0.34 net) in progress at the time of this Form 10-K.
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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 2013, the Company participated in the drilling of 17 exploration wells with 10 wells (1.21 net), including 4 wells in progress at the end of 2012, completed as producers; 5 wells (0.75 net), including 1 well in progress at the end of 2012, completed as dry holes; and 2 wells (0.29 net) in progress at the time of this Form 10-K.
For a summation of exploratory and development wells drilled in 2013 or planned for in 2014, 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, 2012.”
Customers
In 2013, the Company had two customers whose total purchases were greater than 10% of revenues from oil and gas sales. Redland Resources, Inc. purchases were $4,513,392 or 25% of total oil and gas sales. Luff Exploration Company purchases were $2,353,871 or 13% of total oil and gas sales. The Company sells most of its oil and gas under short-term sales contracts that are based on the spot market price. A minor amount of oil and gas sales are made under fixed price contracts having terms of more than one year.
Competition
The oil and gas industry is highly competitive in all of its phases. There are numerous circumstances within the industry and related market place that are out of the Company’s control such as cost and availability of alternative fuels, the level of consumer demand, the extent of other domestic production of oil and gas, the price and extent of importation of foreign oil and gas, the cost of and proximity of pipelines and other transportation facilities, the cost and availability of drilling rigs, regulation by state and federal authorities, and the cost of complying with applicable environmental regulations.
The Company does not operate any of the wells in which it has an interest; rather, it partners with companies that have the resources, staff, and experience to operate wells both in the drilling and production phases. The Company uses its strong financial base and its mineral and leasehold acreage ownership, along with its own geologic and economic evaluations, to participate in drilling operations with these companies. This methodology allows the Company to participate in exploration and development activities it could not undertake on its own due to financial and personnel limits and allows it to maintain low overhead costs.
Regulation
The Company’s operations are affected in varying degrees by political developments and federal and state laws and regulations. Although released from federal price controls, interstate sales of natural gas are subject to regulation by the Federal Energy Regulatory Commission (FERC). Oil and gas operations are affected by environmental laws and other laws relating to the petroleum industry, and both are affected by constantly changing administrative regulations. Rates of production of oil and gas have, for many years, been subject to a variety of conservation laws and regulations, and the petroleum industry is frequently affected by changes in the federal tax laws.
Generally, the respective state regulatory agencies supervise various aspects of oil and gas operations within their states and the transportation of oil and gas sold intrastate.
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Environmental Protection and Climate Change
The operation of the various producing properties, in which the Company has an interest, is subject to federal, state, and local provisions regulating discharge of materials into the environment, the storage of oil and gas products, and the contamination of subsurface formations. The Company’s lease operations and exploratory activity have been and will continue to be affected by existing regulations in future periods. However, the known effect to date has not been material as to capital expenditures, earnings, or industry competitive position. Environmental compliance expenditures produce no increase in productive capacity or revenue and require more of management’s time and attention at a cost which cannot be estimated with any assurance of certainty.
In 2009, the EPA officially published its findings that greenhouse gas emissions present an endangerment to human health and the environment. According to the EPA, these emissions are contributing to global warming and climate change. These findings allowed the EPA to adopt and implement regulations in recent years to restrict these emissions under existing provisions of the Federal Clean Air Act.
The Company may be, directly and indirectly, subject to the effects of climate change and may, directly or indirectly, be affected by government laws and regulations related to climate change. The Company cannot predict with any degree of certainty what effect, if any, climate change and government laws and regulations related to climate change will have on the Company and its business, whether directly or indirectly. While we believe that it is difficult to assess the timing and effect of climate change and pending legislation and regulation related to climate change on the Company’s business, we believe that those laws and regulations may affect, directly or indirectly, (i) the costs associated with drilling and production operations in which we participate; (ii) the demand for oil and natural gas; (iii) insurance premiums, deductibles, and the availability of coverage; and (iv) the cost of utilities paid by the Company. In addition, climate change may increase the likelihood of property damage and the disruption of operations of wells in which we participate. As a result, our financial condition could be negatively impacted, but we are unable to determine at this time whether that impact would be material.
Other Business
See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” subheading “Equity Investments” and Item 8, Notes 2 and 7 to the accompanying financial statements for a discussion of other business including guarantees.
Employees
At December 31, 2013, the Company had eight employees, including officers. See the Proxy Statement for additional information. During 2013, all the Company’s employees devoted a portion of their time to duties with affiliated companies, and the Company was reimbursed for the affiliates’ share of compensation directly from those companies. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” subheading “Certain Relationships and Related Transactions” and Item 8, Note 12 to the accompanying financial statements for additional information.
| ITEM 1A. | RISK FACTORS |
Not applicable.
| ITEM 1B. | UNRESOLVED STAFF COMMENTS |
Not applicable.
| Item 2. | PropertIES |
The Company’s principal properties are oil and natural gas properties. The Company has interests in approximately 830 producing properties with 36% of them being working interest properties and the remaining 64% being royalty interest properties. About 81% of all properties are located in Oklahoma and Texas and account for approximately 66% of the Company’s annual oil and gas sales. About 15% of the properties are located in Arkansas, Kansas, and South Dakota and account for approximately 34% of the Company’s annual oil and gas sales. The remaining 4% of these properties are located in Colorado and Montana and account for less than 1% of the Company’s annual oil and gas sales. No individual property provides more than 10% of the Company’s annual oil and gas sales. See discussion of revenues from Robertson County, Texas, royalty interest properties in Item 7, “Operating Revenues” for additional information about significant properties.
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OIL AND NATURAL GAS OPERATIONS
Oil and Gas Reserves
Reference is made to the Unaudited Supplemental Financial Information beginning on Page 31 for working interest reserve quantity information.
Since January 1, 2013, 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 2012 Annual Report on Form 10-K and federal income tax return for the year ended December 31, 2012. 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, 2013, 2012 and 2011. Equivalent MCF was calculated using approximate relative energy content.
| Royalties | Working Interests | |||||||||||||||||||
| Sales Price | Sales Price | Average Production Cost per | ||||||||||||||||||
| Oil | Gas | Oil | Gas | Equivalent | ||||||||||||||||
| Per Bbl | Per MCF | Per Bbl | Per MCF | MCF | ||||||||||||||||
| 2013 | $ | 93.73 | $ | 3.48 | $ | 90.17 | $ | 3.54 | $ | 1.73 | ||||||||||
| 2012 | $ | 91.13 | $ | 2.63 | $ | 86.15 | $ | 3.07 | $ | 1.85 | ||||||||||
| 2011 | $ | 91.27 | $ | 3.83 | $ | 87.32 | $ | 4.26 | $ | 1.98 | ||||||||||
At December 31, 2013, the Company had working interests in 218 gross (26.38 net) wells producing primarily gas and 219 gross (22.86 net) wells producing primarily oil. These interests were in 95,480 gross (11,431 net) producing acres. These wells include 52 gross (1.30 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, 2013.
| Acreage | ||||||||
| Gross | Net | |||||||
| Non-producing Mineral Interests | 256,364 | 88,445 | ||||||
| Undeveloped Leaseholds | 52,110 | 6,894 | ||||||
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, 2011 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 2013 include the 13 wells still drilling at the end of 2012. As indicated in the “Development Program” on Page 3 and “Exploration Program” on Page 4, 2 development wells and 2 exploratory wells were still in process at the time of this Form 10-K.
| Number of Net Working Interest Wells Drilled | ||||||||||||||||
| Exploratory | Development | |||||||||||||||
| Productive | Dry | Productive | Dry | |||||||||||||
| 2013 | 1.21 | 0.75 | 4.24 | — | ||||||||||||
| 2012 | 1.75 | 1.48 | 3.06 | — | ||||||||||||
| 2011 | 1.26 | 0.61 | 2.26 | — | ||||||||||||
Recent Activities
See Item 7, under the subheading “Update of Oil and Gas Exploration and Development Activity from December 31, 2012” for a summary of recent activities related to oil and natural gas operations.
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| Item 3. | Legal Proceedings |
There are no material legal proceedings pending affecting the Company or any of its properties.
| Item 4. | MINE SAFETY DISCLOSURES |
Not applicable.
| Item 5. | Market for REGISTRANT’S Common Equity, Related Stockholder Matters AND ISSUER PURCHASES OF EQUITY SECURITIES |
The Company’s stock is dually traded in the Pink Sheet Electronic Quotation Service and the OTC Bulletin Board under the symbol “RSRV.” The following high and low bid information was quoted on the Pink Sheets OTC Market Report. Prices reflect inter-dealer prices without retail markup, markdown, or commission and may not reflect actual transactions.
| Quarterly Ranges | ||||||||
| Quarter Ending | High Bid | Low Bid | ||||||
| 03/31/12 | $ | 340 | $ | 290 | ||||
| 06/30/12 | $ | 335 | $ | 275 | ||||
| 09/30/12 | $ | 300 | $ | 275 | ||||
| 12/31/12 | $ | 320 | $ | 288 | ||||
| 03/31/13 | $ | 315 | $ | 288 | ||||
| 06/30/13 | $ | 320 | $ | 300 | ||||
| 09/30/13 | $ | 371 | $ | 295 | ||||
| 12/31/13 | $ | 405 | $ | 355 | ||||
There was limited public trading in the Company’s common stock in 2013 and 2012. There were 67 brokered trades appearing in the Company’s transfer ledger for 2013 and 11 in 2012.
At March 21, 2014, the Company had approximately 1620 record holders of its common stock. The Company paid dividends on its common stock in the amount of $10.00 per share in 2013 (in the second quarter of 2013) and $20.00 per share in 2012 ($10.00 per share in both the second and fourth quarters of 2012). 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 2014 with the Board of Directors for its approval.
ISSUER PURCHASES OF EQUITY SECURITIES
| Period | Total Number of Shares Purchased | Average Price Paid Per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs1 | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs1 | ||||||||||||
| October 1 to October 31, 2013 | 6 | $ | 230.00 | — | — | |||||||||||
| November 1 to November 30, 2013 | 67 | $ | 230.00 | — | — | |||||||||||
| December 1 to December 31, 2013 | 6 | $ | 230.00 | — | — | |||||||||||
| Total | 79 | $ | 230.00 | — | — | |||||||||||
1The Company has no formal equity security purchase program or plan. The Company acts as its own transfer agent, and most purchases result from requests made by shareholders receiving small, odd lot share quantities as the result of probate transfers.
| ITEM 6. | SELECTED FINANCIAL DATA |
Not applicable.
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| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Please refer to the financial statements and related notes in Item 8 of this Form 10-K to supplement this discussion and analysis.
Forward-Looking Statements
In addition to historical information, from time to time the Company may publish forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements provide the reader with management’s current expectations of future events. They include statements relating to such matters as anticipated financial performance, business prospects such as drilling of oil and gas wells, technological development, and similar matters.
Although management believes that the expectations reflected in such forward-looking statements are based on reasonable assumptions, a variety of factors could cause the Company’s actual results and experience to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance, development, and results of the Company’s business include, but are not limited to, the following:
| • | The Company’s future operating results will depend upon management’s ability to employ and retain quality employees, generate revenues, and control expenses. Any decline in operating revenues, without corresponding reduction in operating expenses, could have a material adverse effect on the Company’s business, results of operations, and financial condition. |
| • | The Company has no significant long-term sales contracts for either oil or gas. For the most part, the price the Company receives for its product is based upon the spot market price, which in the past has experienced significant fluctuations. Management anticipates such price fluctuations will continue in the future, making any attempt at estimating future prices subject to significant uncertainty. |
| • | Exploration costs have been a significant component of the Company’s capital expenditures in the past and are expected to remain so, to a somewhat lesser degree, in the near term. Under the successful efforts method of accounting for oil and gas properties which the Company uses, these costs are capitalized if drilling is successful or charged to operating costs and expenses if unsuccessful. Estimating the amount of such future costs which may relate to successful or unsuccessful drilling is extremely imprecise at best. |
The Company does not undertake any obligation to publicly revise forward-looking statements to reflect events or circumstances that arise after the date hereof. Readers should carefully review the information described in other documents the Company files from time to time with the Securities and Exchange Commission, including the Quarterly Reports on Form 10-Q to be filed by the Company in 2014 and any Current Reports on Form 8-K filed by the Company.
Critical Accounting Estimates
| • | Estimates of future revenues from oil and gas sales are derived from a combination of factors which are subject to significant fluctuation over any given period of time. Reserve estimates, by their nature, are subject to revision in the short-term. The evaluating engineer considers production performance data, reservoir data, and geological data available to the Company, as well as makes estimates of production costs, sale prices, and the time period the property can be produced at a profit. A change in any of the above factors can significantly change the timing and amount of net revenues from a property. The Company’s producing properties are composed of many small working interest and royalty interest properties. As a non-operating owner, the Company has limited access to the underlying data from which working interest reserve estimates are calculated, and estimates of royalty interest reserves are not made because the information required for the estimation is not available to the Company. While reserve estimates are not accounting estimates, they are the basis for depreciation, depletion, and amortization described below. Additionally, the estimated economic life for each producing property from the reserve estimates is used in the calculation of asset retirement obligations. |
| • | The provisions for depreciation, depletion, and amortization of oil and gas properties all constitute critical accounting estimates. Non-producing leaseholds are amortized over the life of the leases using a straight line method; however, when leases are impaired or condemned, an appropriate adjustment to the provision is made at that time. |
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| • | The provision for impairment of long-lived assets is determined by review of the estimated future cash flows from the individual properties. A significant, unforeseen downward adjustment in future prices and/or potential reserves could result in a material change in estimated long-lived assets impairment. |
| • | Depletion and depreciation of oil and gas properties are computed using the units-of-production method. A significant, unanticipated change in volume of production or estimated reserves would result in a material, unexpected change in the estimated depletion and depreciation provisions. |
| • | The Company has significant obligations to remove tangible equipment and facilities associated with oil and gas wells and to restore land at the end of oil and gas production operations. Removal and restoration obligations are most often associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires estimates and judgments because most of the removal obligations will take effect in the future. Additionally, these operations are subject to private contracts and government regulations that often have vague descriptions of what is required. Asset removal technologies and costs are constantly changing as are regulatory, political, environmental, and safety considerations. Inherent in the present value calculations are numerous assumptions and judgments including the ultimate removal cost amounts, inflation factors, and discount rate. |
| • | Oil and natural gas sales revenue accrual is another critical accounting estimate. The Company does not operate any of its oil and natural gas properties. Obtaining timely production data on all wells from the operators is not feasible; therefore, the Company utilizes past production receipts and estimated sales price information to estimate its accrual of revenue on all wells each quarter. The oil and natural gas sales revenue accrual can be impacted by many variables, including rapid production decline rates, production curtailments by operators, and rapidly changing market prices for oil and natural gas. These variables could lead to an over or under accrual of oil and natural gas sales at the end of any particular quarter. Based on past history, the Company’s estimated accrual has been materially accurate. |
| • | The estimation of the amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations as well as the completion of complex calculations, including the determination of the Company’s percentage depletion deduction, if any. To calculate the exact excess percentage depletion allowance, a well-by-well calculation is, and can only be, performed at the end of each year. During interim periods, a high-level estimate is made taking into account historical data and current pricing. Although the Company’s management believes its income tax accruals are adequate, differences may occur in the future depending on the resolution of pending and new tax matters. |
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Company is affiliated by common management and ownership with Mesquite Minerals, Inc. (Mesquite), Mid-American Oil Company (Mid-American), Lochbuie Limited Partnership (LLTD) and Lochbuie Holding Company (LHC). The Company also owns interests in certain producing and non-producing oil and gas properties as tenants in common with Mesquite, Mid-American and LLTD.
Mason McLain, a director of the Company, is a 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 28% of the common stock of the Company, approximately 33% of the common stock of Mesquite, and approximately 19% of the common stock of Mid-American. These three corporations, each, have only one class of stock outstanding. See Item 8, Note 12 to the accompanying financial statements for additional disclosures regarding these relationships.
EQUITY INVESTMENT
The Company had a 33% partnership interest in Broadway Sixty-Eight, Ltd. (the “Partnership”) in 2012 and 2013, which it accounted for on the equity method. In using the equity method, the Company records the original investment in an entity as an asset and adjusts the asset balance for the Company’s share of any income or loss, as well as any additional contributions to or distributions from the entity. The Company does not have actual or effective control of the Partnership. The management of the Partnership could, at any time, make decisions in their own best interests that could affect the Company’s net income or the value of the Company’s investment.
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The Partnership has an indemnity agreement under which the Company is contingently liable. See Item 8, Note 7 to the accompanying financial statements for related disclosures and additional information regarding Broadway Sixty-Eight, Ltd.
LIQUIDITY AND CAPITAL RESOURCES
To supplement the following discussion, please refer to the Balance Sheets and the Statements of Cash Flows included in this Form 10-K.
In 2013, as in prior years, the Company funded its business activity through the use of internal sources of capital. For the most part, these internal sources are cash flows from operations, cash, cash equivalents and available-for-sale securities. When cash flows from operating activities are in excess of those needed for other business activities, the remaining balance is used to increase cash, cash equivalents and/or available-for-sale securities. When cash flows from operating activities are not adequate to fund other business activities, withdrawals are made from cash, cash equivalents and/or available-for-sale securities. Cash equivalents are highly liquid debt instruments purchased with a maturity of three months or less. All of the available-for-sale securities are U.S. Treasury Bills.
In 2013, net cash provided by operating activities was $12,258,084. Sales (including lease bonuses), net of production, general and administrative costs, and income taxes paid were $12,218,843, which accounted for 99.7% of net cash provided by operations. The remaining components provided less than 1% of cash flow. In 2013, net cash applied to investing activities was $10,246,949. In 2013, dividend payments and treasury stock purchases totaled $2,088,940 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:
Trading securities increased $197,373 (51%) to $586,708 in 2013 from $389,335 in 2012. Most of the increase is due to a $166,804 increase in unrealized gains, which represent the change in the fair value of the securities from their original cost. The remaining increase of $30,569 represents the 2013 income.
Refundable income taxes decreased $181,457 (35%) to $336,620 in 2013 from $518,077 in 2012. This decrease was due to excess 2013 estimated tax payments being less than in 2012.
Receivables increased $712,879 (41%) to $2,449,048 in 2013 from $1,736,169 in 2012. The increase was due to the use of increased product prices and volumes for both oil and natural gas sales accrual estimates for year-end 2013 compared to 2012. Additional information about oil and natural gas sales for 2013 is included in the “Results of Operations” section that follows.
Accounts payable decreased $152,032 (29%) to $367,622 in 2013 from $519,654 in 2012. This decrease was primarily due to decreased drilling activity at the end of 2013 compared to 2012.
Deferred income taxes and other accrued liabilities increased $130,194 (63%) to $337,624 in 2013 from $207,430 in 2012. 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 2013.
The following is a discussion of material changes in cash flow by activity between the years ended December 31, 2013 and 2012. 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 2013 were $12,258,084, which, when compared to the $10,454,012 provided in 2012, represents a net increase of $1,804,072 or 17%. The increase was mostly due to an increase in oil and gas sales cash flows of $4,723,598, offset by lower lease bonuses and coal royalties of $1,922,985 and an increase in production costs of $562,326 and taxes of $421,900. Additional discussion of the more significant items follows.
Discussion of Selected Material Line Items Resulting in an Increase in Cash Flows. The $4,723,598 (36%) increase in cash received from oil and gas sales to $17,728,795 in 2013 from $13,005,197 in 2012 was the result of an increase in both the oil and gas sales volumes and prices. See “Results of Operations” below for a price/volume analysis and the related discussion of oil and gas sales.
| 10 |
Discussion of Selected Material Line Items Resulting in a Decrease in Cash Flows. Cash received for lease bonuses and coal royalties decreased $1,922,985 (84%) to $372,895 in 2013 from $2,295,880 in 2012. The decrease is due to a decrease in cash received for lease bonuses of $1,593,692 and coal royalties of $329,293 in 2013 versus 2012. No coal was produced from the Company’s leases in 2013.
Cash paid for production costs increased $562,326 (24%) to $2,952,670 in 2013 from $2,390,344 in 2012. This increase was mostly due to lease operating and handling expense on new wells of about $379,000. The remaining increase was due to increased operating expense on previous wells and production taxes. The increase in production taxes was due to the increase in sales in 2013 versus 2012.
Cash flow decreased due to an increase in estimated income tax payments of $421,900 (47%) to $1,311,250 in 2013 from $889,350 in 2012. The higher payments were mostly due to higher net income and current taxable income in 2013.
Investing Activities
Net cash applied to investing activities increased $3,625,281 to $10,246,949 in 2013 from $6,621,668 of cash applied in 2012. This $3,625,280 increase was due primarily to a $3,258,946 increase in cash applied to exploration and development expenditures, including $1,917,376 in December 2013 for some producing properties and leasehold. See the “Exploration and Development Costs” section in the “Results of Operations” section below for more information about this acquisition. The remaining significant increase in cash applied to investing activities pertains to the decrease in proceeds from property disposals. This line item decreased $368,153 (74%) to $131,400 in 2013 from $499,553 in 2012. This decrease was the result of fewer sales of Kansas and Oklahoma non-producing leaseholds in 2013 compared to 2012.
Financing Activities
Cash applied to financing activities decreased $1,051,835 (33%) to $2,088,940 in 2013 from $3,140,775 in 2012. Cash applied to financing activities consist of cash dividends on common stock and cash used for the purchase of treasury stock. In 2013, cash dividends paid on common stock amounted to $1,767,613 as compared to $3,100,835 in 2012. Dividends of $10.00 per share were paid for 2013 and $20.00 per share for 2012. This $1,333,222 decline in dividends paid was offset by a $281,387 increase in cash applied to purchase treasury stock.
Forward-Looking Summary
The Company’s latest estimate of business to be done in 2014 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 2013 the Company had net income of $6,068,042 as compared to a net income of $4,553,845 in 2012. Net income per share, basic and diluted, was $37.90 in 2013, an increase of $9.60 per share from $28.30 in 2012. Material line item changes in the Statements of Income will be discussed in the following paragraphs.
Operating Revenues
Operating revenues increased $3,678,292 (24%) to $18,812,673 in 2013 from $15,134,381 in 2012. Oil and gas sales increased $5,494,876 (42%) to $18,443,984 in 2013 from $12,949,108 in 2012. Lease bonuses and other revenues decreased $1,816,584 to $368,689 in 2013 from $2,185,273 in 2012. This decrease was the result of a decrease in lease bonuses of $1,593,692 primarily from leases in Texas. In addition, coal royalties from North Dakota leases declined $222,893 (99%) to $1,443 in 2013 from $224,336 in 2012. The increase in oil and gas sales is discussed in the following paragraphs.
The $5,494,876 increase in oil and gas sales was the result of a $1,889,973 increase in gas sales, a $3,597,493 increase in oil sales and a $7,410 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 2013 to 2012. Miscellaneous oil and gas product sales of $362,263 in 2013 and $354,853 in 2012 are not included in the analysis.
| 11 |
| Variance | ||||||||||||||||
| Production | 2013 | Price | Volume | 2012 | ||||||||||||
| Gas – | ||||||||||||||||
| MCF (000 omitted) | 1,459 | 331 | 1,128 | |||||||||||||
| $ (000 omitted) | $ | 5,129 | $ | 939 | $ | 951 | $ | 3,239 | ||||||||
| Unit Price | $ | 3.51 | $ | 0.64 | $ | 2.87 | ||||||||||
| Oil – | ||||||||||||||||
| Bbls (000 omitted) | 142 | 35 | 107 | |||||||||||||
| $ (000 omitted) | $ | 12,953 | $ | 551 | $ | 3,047 | $ | 9,355 | ||||||||
| Unit Price | $ | 90.97 | $ | 3.87 | $ | 87.10 | ||||||||||
The $1,889,973 (58%) increase in natural gas sales to $5,128,702 in 2013 from $3,238,729 in 2012 was the result of an increase in both gas sales volumes and the average price received per thousand cubic feet (MCF). The average price per MCF of natural gas sales increased $0.64 per MCF to $3.51 in 2013 from $2.87 per MCF in 2012, resulting in a positive gas price variance of $939,323. A positive volume variance of $950,650 was the result of an increase in natural gas volumes sold of 331,237 MCF to 1,459,622 MCF in 2013 from 1,128,385 MCF in 2012. The increase in the volume of gas production was the net result of new 2013 production of about 367,000 MCF, offset by a decline of about 36,000 MCF in production from previous wells. As disclosed in Supplemental Schedule 1 of the Unaudited Supplemental Financial Information included in Item 8 below, working interests in natural gas extensions and discoveries were adequate to replace working interest reserves produced in 2012 but not in 2013.
The gas production for 2012 and 2013 includes production from about 100 royalty interest properties drilled by various operators in Robertson County, Texas. These properties accounted for approximately 387,000 MCF and $965,000 of the 2012 gas sales and approximately 370,000 MCF and $1,257,000 of the 2013 gas sales. These properties accounted for about 30% of the Company’s 2012 gas revenues compared to 25% of 2013 gas revenues. The Company has no control over the timing of future drilling on the acreage in which we hold mineral interests. However, if natural gas prices continue to recover, the Company expects that drilling activity in Robertson County will increase also.
The $3,597,493 (38%) increase in crude oil sales to $12,953,019 in 2013 from $9,355,526 in 2012 was the result of an increase in the average price per barrel (Bbl) and an increase in oil sales volumes. The average price received per Bbl of oil increased $3.87 to $90.97 in 2013 from $87.10 in 2012, resulting in a positive oil price variance of $550,969. An increase in oil sales volumes of 34,977 Bbls to 142,384 Bbls in 2013 from 107,407 Bbls in 2012 resulted in a positive volume variance of $3,046,524. The increase in the oil volume production was the net result of new 2013 production of about 49,300 Bbls, offset by a 14,300 Bbl decline in production from previous wells. Of the new 2013 production, approximately 12,200 Bbls (25%) was from Woods County, Oklahoma; about 17,500 Bbls (35%) was from new working interest wells in Oklahoma (in counties other than Woods); 9,000 Bbls (18%) was from new royalty interest wells in Oklahoma; and about 10,600 Bbls (22%) was from new royalty interest and working interest wells in Arkansas, Kansas, South Dakota and 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 2012 and 2013.
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 $1,746,348 (18%) to $11,239,428 in 2013 from $9,493,080 in 2012, primarily due to an increase in production and depreciation, depletion and amortization expense. The material components of operating costs and expenses are discussed below.
Production Costs. Production costs increased $595,192 (25%) to $3,009,953 in 2013 from $2,414,761 in 2012. The increase was the result of a $127,357 (23%) increase in gross production tax (net of production tax refunds) to $678,015 in 2013 from $550,658 in 2012; an increase in lease operating expense of $265,036 (18%) to $1,729,973 in 2013 from $1,464,937 in 2012; and an increase in handling expense of $202,799 (51%) to $601,965 in 2013 from $399,166 in 2012. Of the increase in lease operating expense, $258,565 was the result of new wells with the remaining $6,471 due to an increase in expenses for existing wells. Of the increase in handling expense, $120,227 was the result of new wells with the remaining $82,572 due to an increase in expenses for existing wells. Handling expense is comprised of gas gathering, treating, transportation, and compression costs. Gross production taxes are state taxes, which are calculated as a percentage of gross proceeds from the sale of products from each producing oil and gas property; therefore, they fluctuate with the change in the dollar amount of revenues from oil and gas sales.
| 12 |
Exploration and Development Costs. Under the successful efforts method of accounting used by the Company, geological and geophysical costs are expensed as incurred as are the costs of unsuccessful exploratory drilling. The costs of successful exploratory drilling and all development costs are capitalized. Total costs of exploration and development, excluding asset retirement obligations but inclusive of geological and geophysical costs, were $7,485,378 in 2013 and $7,197,753 in 2012. See Item 8, Note 8 to the accompanying financial statements for a breakdown of these costs. Exploration costs charged to operations were $663,627 in 2013 and $316,465 in 2012, inclusive of unsuccessful exploratory well costs of $199,144 in 2013 and $316,465 in 2012 and geological and geophysical costs of $464,483 in 2013, with no geological and geophysical costs in 2012.
Update of Oil and Gas Exploration and Development Activity from December 31, 2012. For the year ended December 31, 2013, the Company participated in the drilling of 17 gross exploratory and 34 gross development working interest wells with working interests ranging from a high of 18% to a low of 0.2%. Of the 17 exploratory wells, 10 were completed as producing wells, 5 as dry holes and 2 were in progress. Of the 34 development wells, 32 were completed as producing wells and 2 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 February 28, 2014, updating both exploration and development activity from December 31, 2012, for the period ended December 31, 2013.
The Company participated with its 18% working interest in the drilling of seven development wells on a Barber County, Kansas prospect. Four of these wells were completed as commercial gas producers, one as a commercial oil and gas producer, one as a commercial oil producer and one as a marginal oil producer. Three additional development wells will be drilled starting in March 2014. Capitalized costs for the period were $655,584, including $47,912 in prepaid drilling costs.
The Company participated with 14%, 14%, 8% and 16% working interests in the drilling of four step-out wells on a Woods County, Oklahoma prospect. The first three wells were completed as commercial oil and gas producers and a completion is in progress on the fourth. The Company will participate with 16% and 8% working interests in the drilling of two additional step-out wells starting in March 2014. Capitalized costs for the period were $363,120, including $71,757 in prepaid drilling costs.
The Company participated with 13.7% working interests in the drilling of three development wells and with a 17.9% interest in the drilling of a fourth on a Woods County, Oklahoma prospect. All four of these wells were completed as commercial oil and gas producers. Capitalized costs for the period were $425,106, including $28,073 in prepaid drilling costs.
The Company participated with its 16% working interest in the drilling of a step-out well on a Woods County, Oklahoma prospect. The well was completed as a marginal oil and gas producer. Capitalized costs were $75,340 for the period.
The Company participated with its 16% working interest in the drilling of two step-out wells on a Hodgeman County, Kansas prospect. Both wells were completed as commercial oil producers. Capitalized costs for the period were $172,286.
The Company participated with its 8.3% interest in the drilling of two additional horizontal wells in a Harding County, South Dakota waterflood unit. Both wells were completed as commercial oil producers. Capitalized costs for the period were $430,705.
The Company participated with its 10.5% working interest in the drilling of a step-out horizontal well on a Garfield County, Oklahoma prospect. The well was completed as a commercial oil and gas producer. Capitalized costs for the period were $136,984.
The Company participated with its 7% working interest in the drilling of two exploratory wells on a Grayson County, Texas prospect. The first well was drilled and completed as a horizontal well and is a marginal oil producer. For geologic reasons, the planned horizontal section of the second well was not drilled and it was completed as a vertical well. The initial completion resulted in marginal oil production. Additional completion operations are in progress. Capitalized costs for the period were $969,939, including $201,901 in prepaid drilling costs, and a $510,000 impairment loss was recorded for the horizontal well.
| 13 |
The Company participated with fee mineral interests in completion operations on two exploratory horizontal wells in Beaver County, Oklahoma (the wells were drilled in 2012). The Company has interests of 12.6% and 10.2% in the wells, which were both completed as commercial oil producers. Capitalized costs for the period were $606,009.
The Company participated with a 5.7% working interest in the drilling of a horizontal development well on a Dewey County, Oklahoma prospect. The well was completed as a commercial oil and gas producer. Capitalized costs for the period were $269,889.
The Company participated with its 16% interest in a 3-D seismic survey on a Hodgeman County, Kansas prospect. An exploratory well was drilled and completed as a marginal oil producer. Capitalized costs for the period were $88,000, including $13,220 in prepaid drilling costs. Seismic costs of $15,533 were expensed.
The Company participated with its 10.5% interest in a 3-D seismic survey on a Cimarron County, Oklahoma prospect. An exploratory well was drilled and completed, testing oil and water. Temporary pumping equipment will be installed to further test the well. A second exploratory well was drilled and completed as a dry hole. The prospect is under evaluation for the possible drilling of an additional exploratory well. Seismic costs of $91,822 were expensed for the period. Capitalized costs were $131,953, including $28,784 in prepaid drilling costs. Dry hole costs for the period were $59,600.
Starting in January 2013, the Company purchased a 14% interest in 12,404 net acres of leasehold on a Ford and Gray Counties, Kansas prospect for $167,097. A 3-D seismic survey was conducted on the prospect. The Company participated in the drilling of two exploratory wells that were both completed as dry holes. Dry hole costs for the period were $81,447. Seismic costs of $185,187 were expensed.
The Company is participating in the development of a Grayson County, Texas prospect with an 8.75% interest. The first phase of acreage acquisition has been completed. The second phase will involve selling a portion of the acreage to an industry partner, additional acreage acquisition and the drilling of exploratory wells. Prospect costs for the period were $175,000.
In July 2013, the Company purchased an 18% interest in 1,440 net acres of leasehold on a Meade County, Kansas prospect for $24,624. The Company participated in the drilling of an exploratory well that was completed as a dry hole. The leasehold cost was written off to impairment expense. Dry hole costs for the period were $45,575.
The Company participated with a 7.5% working interest in the drilling of a step-out horizontal well on a Woods County, Oklahoma prospect. The well was completed as a commercial oil and gas producer. Capitalized costs for the period were $430,800.
The Company participated with a 9% working interest in the drilling of a step-out horizontal well on a Roger Mills County, Oklahoma prospect. The well was completed as a commercial gas and condensate producer. Capitalized costs for the period were $712,754.
In September 2013, the Company paid $4,320 to renew and extend its 18% interest in 320 net acres of leasehold on a Kiowa County, Kansas prospect. The Company participated in the drilling of two exploratory wells. The first well was completed as a commercial oil producer. The second has been completed, testing gas, and is awaiting pipeline connection. Capitalized costs for the period were $215,550, including $77,180 in prepaid drilling costs.
The Company participated with its 18% working interest in the drilling of a development well on a Woods County, Oklahoma prospect. A completion is in progress. Capitalized costs were $133,200, including $82,780 in prepaid drilling costs.
The Company participated with a fee mineral interest in the drilling of an exploratory horizontal well in Kingfisher County, Oklahoma. The Company has a 3.5% interest in the well, which was completed as a commercial oil and gas producer. Capitalized costs for the period were $460,541.
In November 2013, the Company purchased a 10.5% interest in 718 net acres of leasehold and 8.5 square miles of 3-D seismic data on a Logan County, Oklahoma prospect for $120,549. An exploratory well will be drilled in the second quarter of 2014.
| 14 |
In December 2013, the Company purchased a 7% interest in 2,083 net acres of leasehold and 11 square miles of 3-D seismic data on a Garvin County, Oklahoma prospect for $155,285. The Company is participating in an exploratory well that is currently drilling. Prepaid drilling costs for the period were $322,371.
In December 2013, the Company purchased a 10.5% interest in a five prospect package in Seminole County, Oklahoma covering 1,240 acres, paying a $58,590 up-front fee (50% of its ultimate cost if all of the acreage is acquired). The Company will participate in the drilling of an exploratory well and a salt water disposal well on one of the prospects starting in March 2014.
In December 2013, the Company purchased a 14% interest in 7,290 net acres of producing leasehold and interests ranging from 5.9% to 12.5% in 50 producing wells in Woods County, Oklahoma and Barber County, Kansas for $1,917,376. The Company will participate with a 5.9% working interest in the drilling of a development well in the second quarter of 2014.
In February 2014, the Company purchased a 10% interest in 250 net acres of leasehold on a McClain County, Oklahoma prospect for $11,875. An exploratory well will be drilled starting in March or April 2014.
In February 2014, the Company agreed to purchase a 14% interest in 1,705 net acres of leasehold and 70 square miles of 3-D seismic data on a Creek County, Oklahoma prospect for $684,376. Seismic interpretation and additional leasehold acquisition are in progress, and exploratory wells will be drilled in the second half of 2014.
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 $215,861 in 2013 and $136,456 in 2012. Of the 2013 provision, $174,048 was due to the annual amortization of undeveloped leaseholds and $41,813 was due to specific leasehold impairments. The 2012 provision was due to the annual amortization of undeveloped leaseholds of $101,596 and specific leasehold impairments of $34,860.
As discussed in Item 8, Note 10 to the accompanying financial statements, accounting principles require the recognition of an impairment loss on long-lived assets used in operations when indicators of impairment are present. Impairment evaluation is a two-step process. The first step is to measure when the undiscounted cash flows estimated to be generated by those assets, determined on a well basis, is less than the assets’ carrying amounts. Those assets meeting the first criterion are adjusted to estimated fair value. Evaluation for impairment was performed in both 2013 and 2012. The 2013 impairment loss was $1,644,142 and the 2012 impairment loss was $1,811,732. The $167,590 decline in impairments in 2013 was mainly due to the improved natural gas prices.
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. In 2012, approximately 40% and in 2013, approximately 34% of the working interest wells in which the Company participated were horizontal wells. A horizontal well may cost five to eight times as much as a vertically drilled well. In addition, horizontal wells’ initial production rates tend to be greater and their production decline rates are usually higher than in vertical wells. The larger investment in the costlier horizontal wells and the increased production rates result in an increase in depreciation expense. The provision for depletion and depreciation increased $901,893 (28%) to $4,071,720 in 2013 from $3,169,827 in 2012. This increase is due to the reasons discussed above. The provision also includes $88,457 for 2013 and $116,048 for 2012 for the amortization of the Asset Retirement Costs. See Item 8, Note 2 to the accompanying financial statements for additional information regarding the Asset Retirement Obligation.
Other Income (Loss), Net. See Item 8, Note 11 to the accompanying financial statements for an analysis of the components of this line item for 2013 and 2012. Other income, net decreased $134,281 (27%) to $357,081 in 2013 from $491,362 in 2012. The line items responsible for this decrease are described below.
Net realized and unrealized gains (losses) on trading securities increased $207,017 to a net gain of $195,721 in 2013 from a net loss of $(11,296) in 2012. 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 2013, the Company had realized gains of $28,917 and unrealized gains of $166,804. In 2012, the Company had realized gains of $6,359 and unrealized losses of $(17,655).
| 15 |
Gains on sales or disposals of assets decreased $334,579 (74%) to $118,011 in 2013 from gains of $452,590 in 2012. This was due to lower sales of the Company’s interests in certain non-producing leaseholds in Oklahoma and Kansas.
Interest income decreased $9,601 (30%) to $22,833 in 2013 from $32,434 in 2012. This decrease was the result of a decrease in the average balance of cash equivalents and average balance of available-for-sale securities from which most of the interest income is derived. The average balance outstanding decreased $666,735 to $11,822,785 in 2013 from $12,489,520 in 2012.
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 2013, the Company had an estimated provision for income taxes of $1,897,487 as the result of a current tax provision of $1,492,708 and a deferred tax provision of $404,779. In 2012, the Company had an estimated provision for income taxes of $1,651,821 as the result of a current tax provision of $1,187,398 and a deferred tax provision of $464,423.
| ITEM 7A. | QUANTITATIVE AND QUALiTATIVE DISCLOSURES ABOUT MARKET RISKS |
Not applicable.
| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
Index to Financial Statements
| 16 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
The Reserve Petroleum Company
We have audited the accompanying balance sheets of The Reserve Petroleum Company as of December 31, 2013 and 2012, and the related statements of income, stockholders’ equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of The Reserve Petroleum Company as of December 31, 2013 and 2012, and the results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.
/s/ HoganTaylor LLP
Oklahoma City, Oklahoma
March 28, 2014
| 17 |
| THE RESERVE PETROLEUM COMPANY | |||
| BALANCE SHEETS | |||
| ASSETS |
| December 31, | ||||||||
| 2013 | 2012 | |||||||
| Current Assets: | ||||||||
| Cash and Cash Equivalents (Note 2) | $ | 10,764,506 | $ | 10,842,311 | ||||
| Available-for-Sale Securities (Notes 2 & 5) | 6,653,823 | 6,652,590 | ||||||
| Trading Securities (Notes 2 & 5) | 586,708 | 389,335 | ||||||
| Refundable Income Taxes | 336,620 | 518,077 | ||||||
| Receivables (Note 2) | 2,449,048 | 1,736,169 | ||||||
| Prepaid Seismic | 6,232 | — | ||||||
| 20,796,937 | 20,138,482 | |||||||
| Investments: | ||||||||
| Equity Investment (Notes 2 & 7) | 613,558 | 594,855 | ||||||
| Other | 151,839 | 151,839 | ||||||
| 765,397 | 746,694 | |||||||
| Property, Plant and Equipment (Notes 2, 8 & 10): | ||||||||
| Oil and Gas Properties, at Cost, | ||||||||
| Based on the Successful Efforts Method of Accounting – | ||||||||
| Unproved Properties | 1,601,180 | 874,367 | ||||||
| Proved Properties | 47,968,895 | 39,329,747 | ||||||
| 49,570,075 | 40,204,114 | |||||||
| Less – Accumulated Depreciation, Depletion, Amortization and Valuation Allowance | 31,170,203 | 25,726,672 | ||||||
| 18,399,872 | 14,477,442 | |||||||
| Other Property and Equipment, at Cost | 427,056 | 425,024 | ||||||
| Less – Accumulated Depreciation and Amortization | 305,302 | 268,095 | ||||||
| 121,754 | 156,929 | |||||||
| Total Property, Plant and Equipment | 18,521,626 | 14,634,371 | ||||||
| Other Assets | 376,982 | 363,722 | ||||||
| Total Assets | $ | 40,460,942 | $ | 35,883,269 | ||||
See Accompanying Notes
| 18 |
| THE RESERVE PETROLEUM COMPANY | |||
| BALANCE SHEETS | |||
| LIABILITIES AND STOCKHOLDERS’ EQUITY |
| December 31, | ||||||||
| 2013 | 2012 | |||||||
| Current Liabilities: | ||||||||
| Accounts Payable | $ | 367,622 | $ | 519,654 | ||||
| Other Current Liabilities – Deferred Income Taxes and Other | 337,624 | 207,430 | ||||||
| 705,246 | 727,084 | |||||||
| Long-Term Liabilities: | ||||||||
| Asset Retirement Obligation (Note 2) | 1,510,864 | 1,162,078 | ||||||
| Dividends Payable (Note 3) | 1,369,966 | 1,535,568 | ||||||
| Deferred Tax Liability, Net (Note 6) | 3,548,035 | 3,274,807 | ||||||
| 6,428,865 | 5,972,453 | |||||||
| Total Liabilities | 7,134,111 | 6,699,537 | ||||||
| Commitments and Contingencies (Notes 2 & 7) | ||||||||
| Stockholders’ Equity (Notes 3 & 4): | ||||||||
| Common Stock | 92,368 | 92,368 | ||||||
| Additional Paid-in Capital | 65,000 | 65,000 | ||||||
| Retained Earnings | 34,363,292 | 29,898,866 | ||||||
| 34,520,660 | 30,056,234 | |||||||
| Less – Treasury Stock, at Cost | 1,193,829 | 872,502 | ||||||
| Total Stockholders’ Equity | 33,326,831 | 29,183,732 | ||||||
| Total Liabilities and Stockholders’ Equity | $ | 40,460,942 | $ | 35,883,269 | ||||
See Accompanying Notes
| 19 |
| THE RESERVE PETROLEUM COMPANY | |||
| STATEMENTS OF INCOME |
| Year Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Operating Revenues: | ||||||||
| Oil and Gas Sales | $ | 18,443,984 | $ | 12,949,108 | ||||
| Lease Bonuses and Other | 368,689 | 2,185,273 | ||||||
| 18,812,673 | 15,134,381 | |||||||
| Operating Costs and Expenses: | ||||||||
| Production | 3,009,953 | 2,414,761 | ||||||
| Exploration | 663,627 | 316,465 | ||||||
| Depreciation, Depletion, Amortization and Valuation Provisions (Note 10) | 5,969,290 | 5,158,215 | ||||||
| General, Administrative and Other | 1,596,558 | 1,603,639 | ||||||
| 11,239,428 | 9,493,080 | |||||||
| Income from Operations | 7,573,245 | 5,641,301 | ||||||
| Equity Income in Investee (Note 7) | 35,203 | 73,003 | ||||||
| Other Income, Net (Note 11) | 357,081 | 491,362 | ||||||
| Income Before Income Taxes | 7,965,529 | 6,205,666 | ||||||
| Provision for Income Taxes (Notes 2 & 6) | 1,897,487 | 1,651,821 | ||||||
| Net Income | $ | 6,068,042 | $ | 4,553,845 | ||||
| Per Share Data (Note 2): | ||||||||
| Net Income, Basic and Diluted | $ | 37.90 | $ | 28.30 | ||||
| Cash Dividends | $ | 10.00 | $ | 20.00 | ||||
| Weighted Average Shares Outstanding, Basic and Diluted | 160,092 | 160,933 | ||||||
See Accompanying Notes
| 20 |
| THE RESERVE PETROLEUM COMPANY | ||||||||||
| STATEMENTS OF STOCKHOLDERS’ EQUITY | ||||||||||
| FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012 |
| Additional | ||||||||||||||||||||
| Common | Paid-in | Retained | Treasury | |||||||||||||||||
| Stock | Capital | Earnings | Stock | Total | ||||||||||||||||
| Balance at December 31, 2011 | $ | 92,368 | $ | 65,000 | $ | 28,563,474 | $ | (832,562 | ) | $ | 27,888,280 | |||||||||
| Net Income | — | — | 4,553,845 | — | 4,553,845 | |||||||||||||||
| Dividends Declared | — | — | (3,218,453 | ) | — | (3,218,453 | ) | |||||||||||||
| Purchase of Treasury Stock | — | — | — | (39,940 | ) | (39,940 | ) | |||||||||||||
| Balance at December 31, 2012 | 92,368 | 65,000 | 29,898,866 | (872,502 | ) | 29,183,732 | ||||||||||||||
| Net Income | — | — | 6,068,042 | — | 6,068,042 | |||||||||||||||
| Dividends Declared | — | — | (1,603,616 | ) | — | (1,603,616 | ) | |||||||||||||
| Purchase of Treasury Stock | — | — | — | (321,327 | ) | (321,327 | ) | |||||||||||||
| Balance at December 31, 2013 | $ | 92,368 | $ | 65,000 | $ | 34,363,292 | $ | (1,193,829 | ) | $ | 33,326,831 | |||||||||
See Accompanying Notes
| 21 |
| THE RESERVE PETROLEUM COMPANY | |||
| STATEMENTS OF CASH FLOWS |
| Year Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Cash Flows from Operating Activities: | ||||||||
| Cash Received – | ||||||||
| Oil and Gas Sales | $ | 17,728,795 | $ | 13,005,197 | ||||
| Lease Bonuses and Coal Royalties | 372,895 | 2,295,880 | ||||||
| Sale of Trading Securities | 1,619,062 | 733,913 | ||||||
| Interest Received | 18,993 | 31,476 | ||||||
| Agricultural Rentals and Other | 20,686 | 6,318 | ||||||
| Dividends Received on Trading Securities | 1,648 | 1,678 | ||||||
| Cash Paid – | ||||||||
| Production Costs | (2,952,670 | ) | (2,390,344 | ) | ||||
| General Suppliers, Employees and Taxes, Other than Income Taxes | (1,618,927 | ) | (1,600,374 | ) | ||||
| Interest Paid | (37 | ) | (4,432 | ) | ||||
| Purchase of Trading Securities | (1,620,714 | ) | (735,580 | ) | ||||
| Income Taxes Paid, Net | (1,311,250 | ) | (889,350 | ) | ||||
| Farm Expense | (397 | ) | (370 | ) | ||||
| Net Cash Provided by Operating Activities | 12,258,084 | 10,454,012 | ||||||
| Cash Flows Provided by/(Applied to) Investing Activities: | ||||||||
| Maturity of Available-for-Sale Securities | 13,306,310 | 13,307,033 | ||||||
| Purchase of Available-for-Sale Securities | (13,307,544 | ) | (13,304,785 | ) | ||||
| Proceeds from Disposal of Property, Plant and Equipment | 131,400 | 499,553 | ||||||
| Purchase of Property, Plant and Equipment | (10,426,615 | ) | (7,167,669 | ) | ||||
| Cash Distributions from Equity and Other Investments | 49,500 | 44,200 | ||||||
| Net Cash Provided by/(Applied to) Investing Activities | (10,246,949 | ) | (6,621,668 | ) | ||||
See Accompanying Notes
| 22 |
| THE RESERVE PETROLEUM COMPANY | |||
| STATEMENTS OF CASH FLOWS |
| Year Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Cash Flows Applied to Financing Activities: | ||||||||
| Dividends Paid to Stockholders | $ | (1,767,613 | ) | $ | (3,100,835 | ) | ||
| Purchase of Treasury Stock | (321,327 | ) | (39,940 | ) | ||||
| Total Cash Applied to Financing Activities | (2,088,940 | ) | (3,140,775 | ) | ||||
| Net Change in Cash and Cash Equivalents | (77,805 | ) | 691,569 | |||||
| Cash and Cash Equivalents at Beginning of Year | 10,842,311 | 10,150,742 | ||||||
| Cash and Cash Equivalents at End of Year | $ | 10,764,506 | $ | 10,842,311 | ||||
| Reconciliation of Net Income to Net Cash Provided by Operating Activities: | ||||||||
| Net Income | $ | 6,068,042 | $ | 4,553,845 | ||||
| Net Income Increased (Decreased) by Net Change in – | ||||||||
| Net Unrealized Holding (Gains)/Losses on Trading Securities | (166,804 | ) | 17,655 | |||||
| Accounts Receivable | (709,039 | ) | 168,652 | |||||
| Interest and Dividends Receivable | (3,840 | ) | (958 | ) | ||||
| Refundable Income Taxes | 181,458 | 298,048 | ||||||
| Accounts Payable | 36,519 | 118,146 | ||||||
| Trading Securities | (30,568 | ) | (8,028 | ) | ||||
| Other Assets | (13,260 | ) | (1,920 | ) | ||||
| Deferred Taxes | 404,779 | 464,423 | ||||||
| Other Liabilities | (1,357 | ) | (1,330 | ) | ||||
| Income from Equity and Other Investments | (68,203 | ) | (117,203 | ) | ||||
| Exploratory Costs | 670,416 | 228,405 | ||||||
| Gain on Disposition of Property, Plant and Equipment | (102,339 | ) | (452,590 | ) | ||||
| Depreciation, Depletion, Amortization and Valuation Provisions | 5,992,280 | 5,186,867 | ||||||
| Net Cash Provided by Operating Activities | $ | 12,258,084 | $ | 10,454,012 | ||||
See Accompanying Notes
| 23 |
THE RESERVE PETROLEUM COMPANY
Note 1 – NATURE OF OPERATIONS
The Company is engaged in oil and natural gas exploration and development and minerals management with areas of concentration in Texas, Oklahoma, Kansas, Arkansas and South Dakota, a single business segment.
Note 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Cash and Cash Equivalents
The Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents.
Investments
Marketable Securities:
The Company classifies its debt and marketable equity securities in one of two categories: trading or available-for-sale. Trading securities are bought and held principally for the purposes of selling them in the near term. All other securities are classified as available-for-sale.
Trading and available-for-sale securities are recorded at fair value. Unrealized gains and losses on trading securities, which consist primarily of equity securities, are reported in current earnings.
Unrealized gains and losses on available-for-sale securities, which consist entirely of U.S. Government securities, are reported as a component of other comprehensive income when significant to the financial statements.
Equity Investments:
The Company accounts for its non-marketable investment in a partnership on the equity basis. See Note 7 for additional information.
Receivables and Revenue Recognition
Oil and gas sales and resulting receivables are recognized when the product is delivered to the purchaser and title has transferred. Sales are to credit-worthy major energy purchasers with payments generally received within 60 days of transportation from the well site. Historically, the Company has had little, if any, uncollectible receivables; therefore, an allowance for uncollectible accounts has not been provided.
Property and Equipment
Oil and gas properties are accounted for on the successful efforts method. The acquisition, exploration and development costs of producing properties are capitalized. The Company has not historically had any capitalized exploratory drilling costs that are pending determination of reserves for more than one year. All costs relating to unsuccessful exploratory wells, geological and geophysical costs, delay rentals, and abandoned properties are expensed. Lease costs related to unproved properties are amortized over the life of the lease and are assessed for impairment periodically. Any impairment of value is charged to expense.
Depreciation, depletion and amortization of producing properties is computed on the units-of-production method on a property-by-property basis. The units-of-production method is based primarily on estimates of proved reserve quantities. Due to uncertainties inherent in this estimation process, it is at least reasonably possible that reserve quantities will be revised in the near term. Changes in estimated reserve quantities are applied to depreciation, depletion and amortization computations prospectively.
Other property and equipment are depreciated on the straight-line, declining-balance, or other accelerated methods as appropriate.
| 24 |
The following estimated useful lives are used for the different types of property:
| Office furniture and fixtures | 5 to 10 years |
| Automotive equipment | 5 to 8 years |
Impairment losses are recorded on long-lived assets used in operations when indicators of impairment are present. The Company uses its oil and gas reserve reports to test each producing property for impairment annually. See Note 10 for discussion of impairment losses.
Income Taxes
The Company utilizes an asset/liability approach to calculating deferred income taxes. Deferred income taxes are provided to reflect temporary differences in the basis of net assets and liabilities for income tax and financial reporting purposes. Deferred tax assets are reduced by a valuation allowance if a determination is made that it is more likely than not that some or all of the deferred assets will not be realized based on the weight of all available evidence.
The Company recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based upon the technical merits of the position. The Company will record the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement with taxing authorities.
The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense. The federal income tax returns for 2010, 2011 and 2012 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 2013 and 2012, 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 2013 and 2012 whose combined purchases were 38% and 42%, respectively, of total oil and gas sales.
The Company maintains its cash in bank deposit accounts, which at times may exceed federally insured limits. The Company has not experienced any losses in such accounts, and believes that it is not exposed to any significant credit risk with respect to cash and cash equivalents.
Use of Estimates
The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include oil and natural gas reserve quantities that form the basis for the calculation of amortization of oil and natural gas properties. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories. Actual results could differ from the estimates and assumptions used in the preparation of the Company’s financial statements.
Gas Balancing
Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability is recorded when the Company’s excess takes of natural gas volumes exceed our estimated remaining recoverable reserves (over produced). No receivables are recorded for those wells where the Company has taken less than our ownership share of gas production (under produced).
| 25 |
Guarantees
At the inception of a guarantee or subsequent modification, the Company records a liability for the fair value of the obligation undertaken in issuing the guarantee. The Company records a liability for its obligations when it becomes probable that the Company will have to perform under the guarantee. The Company has issued a guarantee associated with the Company’s equity investment in Broadway Sixty-Eight, Ltd.
Asset Retirement Obligation
The Company records the fair value of its estimated liability to retire its oil and natural gas producing properties in the period in which it is incurred (typically the date of first sales). The estimated liability is calculated by obtaining current estimated plugging costs from the well operators and inflating it over the life of the property. Current year inflation rate used is 4.08%. 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 2013 and 2012:
| 2013 | 2012 | |||||||
| Beginning balance at January 1 | $ | 1,162,078 | $ | 990,074 | ||||
| Liabilities incurred | 281,030 | 126,551 | ||||||
| Liabilities settled (wells sold or plugged) | (12,285 | ) | (4,116 | ) | ||||
| Accretion expense | 34,384 | 29,761 | ||||||
| Revision to estimate | 45,657 | 19,808 | ||||||
| Ending balance at December 31 | $ | 1,510,864 | $ | 1,162,078 | ||||
New Accounting Pronouncements
No new accounting standards that were issued or became effective during 2013 have had or are expected to have a material impact on the Company’s financial statements.
In February 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU” or “Update”) 2013-02, Comprehensive Income: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, which adds new disclosure requirements for items reclassified out of accumulated other comprehensive income (“AOCI”). The Update requires that the Company present either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of AOCI based on its source and the income statement line items affected by the reclassification. The guidance is effective for interim and annual reporting periods beginning on or after December 15, 2012. This guidance had no impact on the Company’s financial statements.
Reclassifications
Certain amounts in the 2012 financial statements have been reclassified to conform to the 2013 presentation. The amounts were not material to the financial statements and had no effect on previously reported net income.
Note 3 – DIVIDENDS PAYABLE
Dividends payable includes amounts that are due to stockholders whom the Company has been unable to locate, stockholders’ heirs pending ownership transfer documents, or uncashed dividend checks of other stockholders.
| 26 |
Note 4 – COMMON STOCK
The following table summarizes the changes in common stock issued and outstanding:
| Shares of | ||||||||||||
| Shares | Treasury | Shares | ||||||||||
| Issued | Stock | Outstanding | ||||||||||
| January 1, 2012, $.50 par value stock, 400,000 shares authorized | 184,735 | 23,715 | 161,020 | |||||||||
| Purchase of stock | — | 232 | (232 | ) | ||||||||
| December 31, 2012, $.50 par value stock, 200,000 shares authorized | 184,735 | 23,947 | 160,788 | |||||||||
| Purchase of stock | — | 1,416 | (1,416 | ) | ||||||||
| December 31, 2013, $.50 par value stock, 200,000 shares authorized | 184,735 | 25,363 | 159,372 | |||||||||
In June 2012, the Company amended its Certificate of Incorporation to change its shares authorized from 400,000 shares to 200,000 shares.
Note 5 – MARKETABLE SECURITIES
At December 31, 2013, available-for-sale securities, consisting entirely of U.S. government securities, are due within one year or less by contractual maturity.
For trading securities, in 2013 the Company recorded realized gains of $28,917 and unrealized gains of $166,804. In 2012 the Company recorded realized gains of $6,359 and unrealized losses of $17,655.
Note 6 – INCOME TAXES
Components of deferred taxes are as follows:
| December 31, | ||||||||
| 2013 | 2012 | |||||||
| Assets: | ||||||||
| Net Leasehold Impairment Reserves | $ | 253,939 | $ | 254,045 | ||||
| Gas Balance Receivable | 52,379 | 52,379 | ||||||
| Long-Lived Asset Impairment | 1,524,237 | 1,293,338 | ||||||
| Deferred Geological and Geophysical Expense | 118,443 | 466 | ||||||
| Other | 192,180 | 210,625 | ||||||
| Total Assets | 2,141,178 | 1,810,853 | ||||||
| Liabilities: | ||||||||
| Receivables | 276,273 | 201,436 | ||||||
| Intangible Drilling Costs | 4,484,726 | 4,000,766 | ||||||
| Depletion, Depreciation and Other | 1,237,881 | 1,061,574 | ||||||
| Total Liabilities | 5,998,880 | 5,263,776 | ||||||
| Net Deferred Tax Liability | $ | (3,857,702 | ) | $ | (3,452,923 | ) | ||
The increase in the deferred tax liability for 2013 reflected in the above table is primarily the result of the Company’s increased current year drilling activity, which resulted in an increase in the intangible drilling costs and the bonus depreciation on the increased lease and well equipment additions for successful wells.
| 27 |
The following table summarizes the current and deferred portions of income tax expense:
| Year Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Current Tax Provision: | ||||||||
| Federal | $ | 1,450,082 | $ | 1,153,057 | ||||
| State | 42,626 | 34,341 | ||||||
| 1,492,708 | 1,187,398 | |||||||
| Deferred Provision | 404,779 | 464,423 | ||||||
| Total Provision | $ | 1,897,487 | $ | 1,651,821 | ||||
The total provision for income tax expressed as a percentage of income before income tax was 24% for 2013 and 27% for 2012. These amounts differ from the amounts computed by applying the statutory U.S. federal income tax rate of 34% for 2013 and 2012 to income before income tax as summarized in the following reconciliation:
| Year Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Computed Federal Tax Provision | $ | 2,708,280 | $ | 2,109,926 | ||||
| Increase (Decrease) in Tax From: | ||||||||
| Allowable Depletion in Excess of Basis | (811,242 | ) | (540,969 | ) | ||||
| Dividend Received Deduction | (392 | ) | (400 | ) | ||||
| State Income Tax Provision | 42,626 | 34,341 | ||||||
| Other | (41,785 | ) | 48,923 | |||||
| Provision for Income Tax | $ | 1,897,487 | $ | 1,651,821 | ||||
| Effective Tax Rate | 24 | % | 27 | % | ||||
Note 7 – EQUITY INVESTMENT AND RELATED COMMITMENTS AND CONTINGENT LIABILITIES INCLUDING GUARANTEES
The Company’s Equity Investment consists of 33% ownership in Broadway Sixty-Eight, Ltd. (the “Partnership”), an Oklahoma limited partnership that owns and operates an office building in Oklahoma City, Oklahoma. Although the Company invested as a limited partner, it agreed, jointly and severally, with all other limited partners to indemnify the general partner for any losses suffered from operating the Partnership. The indemnity agreement provides no limitation to the maximum potential future reimbursements. To date, no payments have been made with respect to this agreement.
The Company leases its corporate office from the Partnership. The operating lease, under which the space was rented, expired February 28, 1994, and the space is currently rented on a year-to-year basis under the terms of the expired lease. Rent expense for lease of the corporate office from the Partnership was approximately $29,700 for 2013 and 2012.
Note 8 – COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION, AND DEVELOPMENT ACTIVITIES
All of the Company’s oil and gas operations are within the continental United States. In connection with its oil and gas operations, the following costs were incurred:
| 28 |
| Year Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Acquisition of Properties: | ||||||||
| Unproved | $ | 818,290 | $ | 227,050 | ||||
| Proved | 1,917,376 | — | ||||||
| Exploration Costs | 3,587,244 | 2,713,181 | ||||||
| Development Costs | 3,898,134 | 4,484,572 | ||||||
| Asset Retirement Obligation | 326,687 | 146,359 | ||||||
Note 9 – FAIR VALUE MEASUREMENTS
Inputs used to measure fair value are organized into a fair value hierarchy based on how observable the inputs are. Level 1 inputs consist of quoted prices in active markets for identical assets. Level 2 inputs are inputs, other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs. During 2013 and 2012 there were no transfers into or out of Level 2 or Level 3.
Recurring Fair Value Measurements
Certain of the Company’s assets are reported at fair value in the accompanying balance sheets on a recurring basis. The Company determined the fair value of the available-for-sale securities using quoted market prices for securities with similar maturity dates and interest rates. At December 31, 2013 and 2012, the Company’s assets reported at fair value on a recurring basis are summarized as follows:
| 2013 | ||||||||||||
| Level 1 Inputs | Level 2 Inputs | Level 3 Inputs | ||||||||||
| Financial Assets: | ||||||||||||
| Available-for-Sale Securities – | ||||||||||||
| U.S. Treasury Bills Maturing in 2014 | $ | — | $ | 6,653,823 | $ | — | ||||||
| Trading Securities – | ||||||||||||
| Domestic Equities | 389,766 | — | — | |||||||||
| International Equities | 179,509 | — | — | |||||||||
| Others | 17,433 | — | — | |||||||||
| 2012 | ||||||||||||
| Level 1 Inputs | Level 2 Inputs | Level 3 Inputs | ||||||||||
| Financial Assets: | ||||||||||||
| Available-for-Sale Securities – | ||||||||||||
| U.S. Treasury Bills Maturing in 2013 | $ | — | $ | 6,652,590 | $ | — | ||||||
| Trading Securities – | ||||||||||||
| Domestic Equities | 257,229 | — | — | |||||||||
| International Equities | 111,729 | — | — | |||||||||
| Others | 20,377 | — | — | |||||||||
Non-recurring Fair Value Measurements
The Company’s asset retirement obligation incurred annually represents non-recurring fair value liabilities. The fair value of the non-financial liabilities incurred was $281,030 in 2013 and $126,551 in 2012 and was calculated using Level 3 inputs. See Note 2 above for more information about this liability and the inputs used for calculating fair value.
The impairment losses of $1,644,142 for 2013 and $1,811,732 for 2012 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, 2013 and 2012, the historical cost of cash and cash equivalents, trade receivables, trade payables, and dividends payable are considered to be representative of their respective fair values due to the short-term maturities of these items.
| 29 |
Note 10 – LONG-LIVED ASSETS IMPAIRMENT LOSS
Certain oil and gas producing properties have been deemed to be impaired because the assets, evaluated on a property-by-property basis, are not expected to recover their entire carrying value through future cash flows. Impairment losses totaling $1,644,142 for 2013 and $1,811,732 for 2012 are included in the Statements of Income in the line item Depreciation, Depletion, Amortization and Valuation Provisions. The impairments for 2013 and 2012 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. Forward pricing 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 2013 and 2012:
| 2013 | 2012 | |||||||
| Net Realized and Unrealized Gain (Loss) on Trading Securities | $ | 195,721 | $ | (11,296 | ) | |||
| Gains on Asset Sales | 118,011 | 452,590 | ||||||
| Interest Income | 22,833 | 32,434 | ||||||
| Settlements of Class Action Lawsuits | 15,085 | 718 | ||||||
| Agricultural Rental Income | 5,600 | 5,600 | ||||||
| Dividend Income | 1,648 | 1,678 | ||||||
| Income from Other Investments | 33,000 | 44,200 | ||||||
| Interest and Other Expenses | (34,817 | ) | (34,562 | ) | ||||
| Other Income, Net | $ | 357,081 | $ | 491,362 | ||||
Note 12 – CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Company is affiliated by common management and ownership with Mesquite Minerals, Inc. (Mesquite), Mid-American Oil Company (Mid-American), Lochbuie Limited Partnership (LLTD) and Lochbuie Holding Company (LHC). The Company also owns interests in certain producing and non-producing oil and gas properties as tenants in common with Mesquite, Mid-American and LLTD.
Mesquite, Mid-American and LLTD share facilities and employees including executive officers with the Company. The Company has been reimbursed for services, facilities, and miscellaneous business expenses incurred in 2013 in the amount of $177,782 each by Mesquite, Mid-American and LLTD. Reimbursements in 2012 were $174,589 each by Mesquite, Mid-American and LLTD. Included in the 2013 amounts, Mesquite, Mid-American and LLTD each paid $126,884 for their share of salaries. In 2012, the share of salaries paid by Mesquite, Mid-American and LLTD was $124,988 each.
| 30 |
UNAUDITED SUPPLEMENTAL FINANCIAL INFORMATION
| 31 |
| SUPPLEMENTAL SCHEDULE 1 | |||
| THE RESERVE PETROLEUM COMPANY | |||
| WORKING INTEREST RESERVE QUANTITY INFORMATION | |||
| (Unaudited) |
| Year Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Oil and Condensate (Bbls) | ||||||||
| Proved Developed and Undeveloped Reserves: | ||||||||
| Beginning of Year | 454,951 | 370,322 | ||||||
| Revisions of Previous Estimates | 6,602 | 25,072 | ||||||
| Extensions and Discoveries | 127,505 | 146,358 | ||||||
| Purchase of Reserves | 48,497 | — | ||||||
| Production | (110,196 | ) | (86,801 | ) | ||||
| End of Year | 527,359 | 454,951 | ||||||
| Proved Developed Reserves: | ||||||||
| Beginning of Year | 454,951 | 370,322 | ||||||
| End of Year | 484,633 | 454,951 | ||||||
| Gas (MCF) | ||||||||
| Proved Developed and Undeveloped Reserves: | ||||||||
| Beginning of Year | 3,634,480 | 2,588,974 | ||||||
| Revisions of Previous Estimates | 99,133 | (111,215 | ) | |||||
| Extensions and Discoveries | 716,497 | 1,766,753 | ||||||
| Purchase of Reserves | 589,003 | — | ||||||
| Production | (917,755 | ) | (610,032 | ) | ||||
| End of Year | 4,121,358 | 3,634,480 | ||||||
| Proved Developed Reserves: | ||||||||
| Beginning of Year | 3,634,480 | 2,588,974 | ||||||
| End of Year | 3,822,278 | 3,634,480 | ||||||
See notes on next page.
| 32 |
SUPPLEMENTAL SCHEDULE 1
THE RESERVE PETROLEUM COMPANY
WORKING INTEREST RESERVE QUANTITY INFORMATION
(Unaudited)
Notes:
| 1. | Estimates of royalty interests’ reserves, on properties in which the Company does not own a working interest, have not been included because the information required for the estimation of such reserves is not available. The Company’s share of production from its net royalty interests was 32,189 Bbls of oil and 541,866 MCF of gas for 2013 and 20,606 Bbls of oil and 518,353 MCF of gas for 2012. |
| 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 2013 and 2012. The Company engineer’s qualifications set forth in the Proxy Statement and as incorporated into Item 10 of this Form 10-K, are incorporated herein by reference. All reserves are located within the United States. |
| 3. | The Company emphasizes that the reserve volumes shown are estimates, which by their nature are subject to revision in the near term. The estimates have been made by utilizing geological and reservoir data, as well as actual production performance data available to the Company. These estimates are reviewed annually and are revised upward or downward as warranted by additional performance data. The Company’s engineer is not independent, but strives to use an objective approach in calculating the Company’s working interest reserve estimates. |
| 4. | The Company’s internal controls relating to the calculation of its working interests’ reserve estimates include review and testing of the accounting data flowing into the calculation of the reserve estimates. In addition, the average oil and natural gas product prices calculated in the engineer’s 2013 summary reserve report was tested by comparison to 2013 average sales price information from the accounting records. |
| 33 |
| SUPPLEMENTAL SCHEDULE 2 | |||
| THE RESERVE PETROLEUM COMPANY | |||
| STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS | |||
| RELATING TO PROVED WORKING INTEREST | |||
| OIL AND GAS RESERVES | |||
| (Unaudited) |
| At December 31, | ||||||||
| 2013 | 2012 | |||||||
| Future Cash Inflows | $ | 61,732,164 | $ | 47,594,837 | ||||
| Future Production and Development Costs | (20,525,589 | ) | (14,711,266 | ) | ||||
| Future Asset Retirement Obligation | (1,937,212 | ) | (1,499,238 | ) | ||||
| Future Income Tax Expense | (8,041,742 | ) | (6,744,346 | ) | ||||
| Future Net Cash Flows | 31,227,621 | 24,639,987 | ||||||
| 10% Annual Discount for Estimated Timing of Cash Flows | (9,505,407 | (7,621,558 | ) | |||||
| Standardized Measure of Discounted Future Net Cash Flows | $ | 21,722,214 | $ | 17,018,429 | ||||
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 2012 and 2013, with no escalation. The development and production costs are based on year-end cost levels, assuming the continuation of existing economic conditions. Cash flows are further reduced by estimated future asset retirement obligations and estimated future income tax expense calculated by applying the current statutory income tax rates to the pretax net cash flows, less depreciation of the tax basis of the properties and depletion applicable to oil and gas production.
| 34 |
| SUPPLEMENTAL SCHEDULE 3 | |||
| THE RESERVE PETROLEUM COMPANY | |||
| CHANGES IN STANDARDIZED MEASURE OF | |||
| DISCOUNTED FUTURE NET CASH FLOWS FROM | |||
| PROVED WORKING INTEREST RESERVE QUANTITIES | |||
| (Unaudited) |
| Year Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Standardized Measure, Beginning of Year | $ | 17,018,429 | $ | 16,055,120 | ||||
| Sales and Transfers, Net of Production Costs | (10,549,949 | ) | (7,431,704 | ) | ||||
| Net Change in Sales and Transfer Prices, Net of Production Costs | 1,841,016 | (2,076,678 | ) | |||||
| Extensions, Discoveries and Improved Recoveries, Net of Future Production and Development Costs | 9,793,021 | 9,250,745 | ||||||
| Revisions of Quantity Estimates | 601,915 | 184,782 | ||||||
| Accretion of Discount | 2,308,396 | 2,020,364 | ||||||
| Purchases of Reserves in Place | 1,969,430 | — | ||||||
| Net Change in Income Taxes | (935,750 | ) | (217,583 | ) | ||||
| Net Change in Asset Retirement Obligation | (314,402 | ) | (142,243 | ) | ||||
| Changes in Production Rates (Timing) and Other | (9,892 | ) | (624,374 | ) | ||||
| Standardized Measure, End of Year | $ | 21,722,214 | $ | 17,018,429 | ||||
| 35 |
| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
| ITEM 9A. | CONTROLS AND PROCEDURES |
Disclosure Controls and Procedures
As defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (the “Exchange Act”), the term “disclosure controls and procedures” means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
Management of the Company, with the participation of the Principal Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures and concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2013.
Management’s Annual Report on Internal Control over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting for the Company as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. This system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.
The Company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and the directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements, and provide reasonable assurance as to the detection of fraud.
Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time.
With the participation of the Principal Executive Officer and Principal Financial Officer, the Company’s management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting, based on the framework and criteria established in Internal Control-Integrated Framework (1922) 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, 2013.
This Annual Report on Form 10-K does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. As the Company is a Smaller Reporting Company, Management’s report was not subject to attestation by the Company’s independent registered public accounting firm.
| /s/ Cameron R. McLain | /s/ James L. Tyler | |
| Cameron R. McLain, President | James L. Tyler, 2nd Vice President | |
| Principal Executive Officer | Principal Financial Officer | |
| March 28, 2014 | March 28, 2014 |
| 36 |
Changes in Internal Control over Financial Reporting
Management of the Company, with the participation of the Principal Executive Officer and Principal Financial Officer, evaluated the internal control over financial reporting and concluded that no change in the Company’s internal control over financial reporting occurred during the fourth quarter ended December 31, 2013 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
| ITEM 9B. | OTHER INFORMATION |
None.
| ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
Information regarding directors and executive officers, Section 16(a) Beneficial Ownership Reporting Compliance, the Company’s Code of Ethics, Corporate Governance, and any other information called for by this item is incorporated by reference to the Proxy Statement.
| ITEM 11. | EXECUTIVE COMPENSATION |
Information regarding executive compensation called for by this Item is incorporated by reference to the Proxy Statement.
| ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
Information regarding security ownership of certain beneficial owners and management and related stockholder matters called for by this Item is incorporated by reference to the Proxy Statement.
| ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE |
See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8, Note 12 to Financial Statements. Information regarding the independence of our directors and other information called for by this Item is incorporated by reference to the Proxy Statement.
| ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES |
Information regarding fees billed to the Company by its independent registered public accounting firm is incorporated by reference to the Proxy Statement.
| 37 |
| ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
The following documents are exhibits to this Form 10-K. Each document marked by an asterisk is filed electronically herewith.
| Exhibit Number | Description | |
| 3.1 | Restated Certificate of Incorporation dated June 1, 2012 is incorporated by reference to Exhibit 3.1 of The Reserve Petroleum Company’s Annual Report 10-K (Commission File No. 0-8157) filed March 28, 2013. | |
| 3.2 | Amended By-Laws dated November 16, 2004, are incorporated by reference to Exhibit 3.2 of The Reserve Petroleum Company’s Annual Report on Form 10-KSB (Commission File No. 0-8157) filed March 30, 2006. | |
| 14 | Code of Ethics incorporated by reference to Exhibit 14 of The Reserve Petroleum Company’s Annual Report on Form 10-KSB (Commission File No. 0-8157) filed March 30, 2006. | |
| 31.1* | Certification of Principal Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as amended. | |
| 31.2* | Certification of Principal Financial Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as amended. | |
| 32* | Certification of Principal Executive Officer and Principal Financial Officer Pursuant to 18 U.S.C. Section 1350. | |
| 101.INS* | XBRL Instance Document | |
| 101.SCH* | XBRL Taxonomy Extension Schema Document | |
101.DEF* |
XBRL Taxonomy Extension Definition Linkbase Document | |
| 101.CAL* | XBRL Taxonomy Calculation Linkbase Document | |
| 101.LAB* | XBRL Taxonomy Label Linkbase Document | |
| 101.PRE* | XBRL Taxonomy Presentation Linkbase Document | |
| * Filed electronically herewith. |
| 38 |
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| THE RESERVE PETROLEUM COMPANY | ||
| (Registrant) | ||
| /s/ Cameron R. McLain | ||
| By: Cameron R. McLain, President | ||
| (Principal Executive Officer) | ||
| /s/ James L. Tyler | ||
| By: James L. Tyler, 2nd Vice President | ||
| (Principal Financial Officer) |
Date: March 28, 2014
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:
| /s/ Kyle L. McLain | /s/ Jerry L. Crow | |
| Kyle L. McLain (Chairman of the Board) | Jerry L. Crow (Director) | |
| March 28, 2014 | March 28, 2014 | |
| /s/ Robert L. Savage | /s/ William M. Smith | |
| Robert L. Savage (Director) | William M. Smith (Director) | |
| March 28, 2014 | March 28, 2014 |
39