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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, 2016

 

     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 30, 2016 (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 $19,967,661, as computed by reference to the last reported sale which was on June 29, 2016.

 

As of March 24, 2017, there were 157,846 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 23, 2017, which will be filed within 120 days of the end of the registrant’s year ended December 31, 2016, are incorporated by reference into Part III of this Form 10-K to the extent described therein.

 

 

TABLE OF CONTENTS

 

 

   

Page

Forward-Looking Statements

3

     
 

PART I

 

Item 1.

Business

3

Item 1A.

Risk Factors    

5

Item 1B.

Unresolved Staff Comments     

5

Item 2.

Properties

5

Item 3.

Legal Proceedings

6

Item 4.

Mine Safety Disclosures

7

   

 

 

PART II

 

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

7

Item 6.     

Selected Financial Data

7

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

7

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

15

Item 8.

Financial Statements and Supplementary Data

15

Item 9.     

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

36

Item 9A.     

Controls and Procedures

36

Item 9B.     

Other Information

37

   

 

 

PART III

 

Item 10.     

Directors, Executive Officers and Corporate Governance

37

Item 11.     

Executive Compensation

37

Item 12.     

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

37

Item 13.     

Certain Relationships and Related Transactions and Director Independence

37

Item 14.     

Principal Accountant Fees and Services

37

   

 

 

PART IV

 

Item 15.     

Exhibits and Financial Statement Schedules

38

Item 16. Form 10-K Summary 38

 

 
 

 

  

Forward-Looking Statements

 

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

  

 

PART I

 

 

Item 1.

Business

 

Overview 

 

The Reserve Petroleum Company (the “Company,” “we,” “our” or “us”) 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 our 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 256,335 gross acres equivalent to 88,288 net acres. These mineral interests are located in nine different states in the north and south central United States. A total of 81,155 (92%) net acres are located in the states of Arkansas, Kansas, Oklahoma, South Dakota and Texas, the areas of concentration for the Company in our exploration and development programs.

 

The Company has several options relating to the exploration and/or development of our 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 our 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 we may choose to participate as a working interest owner and pay our proportionate share of any exploration or development drilling costs.

  

A substantial amount of the Company’s oil and gas revenue has resulted from our owned mineral property management. In 2016, $1,487,173 (27%) of oil and gas sales was from royalty interests versus $1,969,058 (26%) in 2015. As a result of our mineral ownership, the Company had royalty interests in 10 gross (0.14 net) wells, which were drilled and completed as producing wells in 2016. This resulted in an average royalty interest of about 1.4% for these 10 new wells. The Company has very little control over the timing or extent of the operations conducted on our 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, we may participate in drilling additional wells on our producing leaseholds; or if our exploration program, discussed below, results in a successful exploratory well, we may participate in the drilling of additional wells on the exploratory prospect. In 2016, the Company participated in the drilling of 3 development wells with 4 wells (0.47 net), including 3 wells in progress at year-end 2015, completed as producers, and 3 wells (0.35 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 our 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 our risk limits, we 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 2016, we participated in the drilling of 12 exploratory wells with 1 well (0.16 net) completed as a producer, 1 well in progress at the end of 2016 and 10 wells (1.4 net) completed as dry holes.

 

For a summation of exploratory and development wells drilled in 2016 or planned for in 2017, 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, 2015.”

 

Customers

 

In 2016, the Company had two customers whose total purchases were greater than 10% of revenues from oil and gas sales. Redland Resources, LLC purchases were $1,289,760 or 24% of total oil and gas sales and Luff Exploration Company purchases were $576,787 or 11% 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.

 

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 we have an interest; rather, we partner 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 us to participate in exploration and development activities we could not undertake on our own due to financial and personnel limits and allows us to maintain low overhead costs.

 

Regulation

 

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

 

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

 

Environmental Protection and Climate Change

 

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

 

 
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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. We 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 our 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 our 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 and Other Investments” and Item 8, Notes 2, 7 and 13 to the accompanying financial statements for a discussion of other business including guarantees.

 

Employees

 

At December 31, 2016, the Company had eight employees, including officers. See the Proxy Statement for additional information. During 2016, all of our employees devoted a portion of their time to duties with affiliated companies, and we were 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. We have interests in approximately 900 producing properties with 39% of them being working interest properties and the remaining 61% being royalty interest properties. About 80% of all properties are located in Oklahoma and Texas and account for approximately 71% of our annual oil and gas sales. About 16% of the properties are located in Arkansas, Kansas and South Dakota and account for approximately 27% of our annual oil and gas sales. The remaining 4% of these properties are located in Colorado, Montana, and Nebraska and account for about 2% of our annual oil and gas sales. No individual property provides more than 8% of our annual oil and gas sales. See discussion of revenues from Robertson County, Texas, royalty interest properties in Item 7, “Operating Revenues” for additional information about significant properties.

 

OIL AND NATURAL GAS OPERATIONS

 

Oil and Gas Reserves

 

Reference is made to the Unaudited Supplemental Financial Information beginning on Page 31 for working interest reserve quantity information.Since January 1, 2016, 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 2015 Annual Report on Form 10-K and federal income tax return for the year ended December 31, 2015. Those reserve estimates were identical.

 

 
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Production

 

The average sales price of oil and gas production for the Company’s royalty and working interests, as well as the average working interest production cost (lifting cost) per equivalent thousand cubic feet (MCF) of gas, are presented in the table below for the years ended December 31, 2016, 2015 and 2014. Equivalent MCF was calculated using approximate relative energy content.

 

   

Royalties

   

Working Interests

 
   

Sales Price

   

Sales Price

   

Average Production

 
   

Oil

   

Gas

   

Oil

   

Gas

   

Cost per

 
   

Per Bbl

   

Per MCF

   

Per Bbl

   

Per MCF

   

Equivalent MCF

 
                                         

2016

  $ 38.53     $ 2.21     $ 36.49     $ 2.16     $ 1.85  

2015

  $ 47.57     $ 2.46     $ 43.09     $ 2.53     $ 1.93  

2014

  $ 90.62     $ 4.23     $ 86.34     $ 4.46     $ 1.83  

 

At December 31, 2016, the Company had working interests in 214 gross (26.44 net) wells producing primarily gas and 230 gross (22.83 net) wells producing primarily oil. These interests were in 86,009 gross (9,854 net) producing acres. These wells include 48 gross (1.43 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, 2016.

 

   

Acreage

 
   

Gross

   

Net

 
                 

Non-producing Mineral Interests

    256,335       88,288  

Undeveloped Leaseholds

    77,787       13,875  

 

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, 2014 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 2016 include the 6 wells still drilling at the end of 2015. As indicated in the “Development Program” on Page 3 and “Exploration Program” on Page 4, 3 development wells and 1 exploratory well 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

 
                                 

2016

    0.16       1.41       0.47       ---  

2015

    0.61       0.78       0.68       ---  

2014

    0.73       0.41       2.80       ---  

 

Recent Activities

 

See Item 7, under the subheading “Update of Oil and Gas Exploration and Development Activity from December 31, 2015” for a summary of recent activities related to oil and natural gas operations.

 

Item 3.     Legal Proceedings

 

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

 

 
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Item 4.

MINE SAFETY DISCLOSURES

 

Not applicable.

 

 

PART II

 

 

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

 
                 

03/31/15

  $ 395     $ 340  

06/30/15

  $ 375     $ 330  

09/30/15

  $ 338     $ 241  

12/31/15

  $ 271     $ 218  

03/31/16

  $ 220     $ 151  

06/30/16

  $ 199     $ 178  

09/30/16

  $ 190     $ 182  

12/31/16

  $ 200     $ 183  

 

There was limited public trading in the Company’s common stock in 2016 and 2015. There were 9 brokered trades appearing in the Company’s transfer ledger for 2016 and 10 in 2015.

 

At March 24, 2017, the Company had approximately 1,810 record holders of its common stock. The Company paid dividends on its common stock in the amount of $5.00 per share in the second quarter of 2016 and $10.00 per share in the second quarter of 2015. 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 2017, if any, 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, 2016

    8     $ 150       ---       ---  
 

November 1 to November 30, 2016

    41     $ 150       ---       ---  
 

December 1 to December 31, 2016

    13     $ 150       ---       ---  
 

Total

    62     $ 150       ---       ---  

 

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.

 

 

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.

 

 
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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 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 our 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 our 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 we receive for our product is based upon the spot market price, which in the past has experienced significant fluctuations. Management anticipates 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 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 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 filing date of this Form 10-K. 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 2017 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, we have 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 impairment, depreciation, depletion, and amortization described below. Additionally, the estimated economic life for each producing property from the reserve estimates is used in the calculation of asset retirement obligations.

 

 

The provisions for depreciation, depletion, and amortization of oil and gas properties all constitute critical accounting estimates. Non-producing leaseholds are amortized over the life of the leases using a straight line method; however, when leases are impaired or condemned, an appropriate adjustment to the provision is made at that time.

 

 

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

 

 
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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, our 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 our 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) and Lochbuie Limited Liability Company (LLTD). 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.

 

Robert T. McLain and Jerry Crow, directors of the Company, are directors of Mesquite and Mid-American. Kyle McLain, Cameron R. McLain and John McLain are brothers and directors of the Company. Kyle McLain and Cameron McLain each own more than 5% of the common stock of the Company and are officers. Kyle McLain and Cameron McLain are officers and directors of Mesquite and Mid-American. Robert T. McLain owns an approximate 33% interest in LLTD. Kyle McLain, Cameron R. McLain and John McLain each own an approximate 11% interest in LLTD. Robert T. McLain and John McLain are not employees of any of the above entities and devote only a small amount of time conducting their business.

 

The above named officers, directors, and employees as a group beneficially own approximately 27% of the common stock of the Company, approximately 35% of the common stock of Mesquite, and approximately 20% 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 AND OTHER INVESTMENTS 

 

The Company has a 33% partnership interest in Broadway Sixty-Eight, Ltd. (the “Partnership”), which it accounts for on the equity method. In using the equity method, the Company records the original investment in an entity as an asset and adjusts the asset balance for the Company’s share of any income or loss, as well as any additional contributions to or distributions from the entity. The 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.

 

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.

 

The Company’s Equity Investments also include a 47% ownership in Grand Woods Development, LLC (the “LLC”) an Oklahoma limited liability company acquired in November 2015. The LLC owns approximately 26.3 acres of undeveloped real estate in northeast Oklahoma City. The Company has guaranteed a loan for which the proceeds were used to purchase a portion of the undeveloped real estate acreage.

 

 
9

 

 

Other Investments are mostly investments in limited liability companies (“LLC’s”) with smaller ownership interests that do not allow the Company to significantly influence the operations or management of the LLC’s. These investments are recorded at cost and cash distributions from the investment are recognized as income when received. The names of these investments, including ownership interest, investment amounts, the year acquired and a brief description of each, follows.

 

OKC Industrial Properties (“OKC”), 10%, $56,164, acquired in 1992. OKC originally owned approximately 260 acres of undeveloped land in north Oklahoma City and over time has sold all but approximately 46 acres. The most recent sale of approximately 45 acres occurred in January, 2017. See Item 8, Note 13 to the accompanying financial statements for the income from this sale recorded in 2017.

 

Bailey Hilltop Pipeline (“Bailey”), 10%, $80,377, acquired in 2008. Bailey is a gas gathering system pipeline for the Bailey Hilltop Prospect oil and gas properties in Grady County, Oklahoma.

 

Cloudburst Solutions (“Solutions”), 8.125%, $1,250,000 total, initial investment of $500,000 acquired in 2014 and an additional investment of $750,000 acquired in 2016. Solutions owns exclusive rights to a water purification process technology that is being developed and currently tested.

  

Ocean’s NG (“Ocean”), 13.333%, $200,000, acquired in 2015. Ocean is developing an underground Compressed Natural Gas (“CNG”) storage and delivery system for retail sales of CNG.

 

QSN Office Park (“QSN”), 20%, $280,000, acquired in 2016. QSN is constructing and selling office buildings in a new office park.

 

 

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 2016, 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 2016, net cash provided by operating activities was $2,776,128. Sales (including lease bonuses), net of production costs, general and administrative costs and income taxes paid were $2,499,327, which accounted for 90% of net cash provided by operations. The remaining components provided 10% of cash flow. In 2016, net cash applied to investing activities was $7,630,988. In 2016, dividend payments and treasury stock purchases totaled $1,010,501 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 $62,983 (15%) to $473,707 in 2016 from $410,724 in 2015. The net increase is due to $82,159 in unrealized gains, which represent the change in the fair value of the securities from their original cost, offset by $19,176 of 2016 net losses.

 

Refundable income taxes increased $48,746 (10%) to $536,798 in 2016 from $488,052 in 2015.

 

Receivables increased $119,773 (19%) to $764,641 in 2016 from $644,868 in 2015. The increase was due primarily to the use of higher product prices for oil and gas sales accrual estimates for year-end 2016 compared to 2015. Additional information about oil and gas sales for 2016 is included in the “Results of Operations” section that follows.

 

Accounts payable decreased $63,899 (28%) to $161,749 in 2016 from $225,648 in 2015. This decrease was primarily due to decreased drilling activity.

 

 
10

 

 

The following is a discussion of material changes in cash flow by activity between the years ended December 31, 2016 and 2015. 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 2016 were $2,776,128, which, when compared to the $5,425,939 provided in 2015, represents a net decrease of $2,649,811 or 49%. The decrease was mostly due to a decrease in oil and gas sales cash flows of $3,793,121 and a $391,290 decrease in cash from Life Insurance Policy benefits. These were offset by a decrease in production costs of $531,958 and taxes of $720,036. Additional discussion of the significant items follows.

 

Discussion of Selected Material Line Items Resulting in a Decrease in Cash Flows. The $3,793,121 (42%) decrease in cash received from oil and gas sales to $5,346,837 in 2016 from $9,139,958 in 2015 was the result of a decrease in both 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.

 

Cash received for lease bonuses increased $62,994 (8%) to $872,974 in 2016 from $809,980 in 2015.

 

The 2016 cash distribution from our equity investment in Broadway Sixty-Eight, Ltd., of $165,000 included our share of operating profits plus the profits from the sale of the last small office building on some land adjacent to our current office building. The 2015 cash distribution of $82,500 was primarily for our share of operating profits. See Item 8, Note 7 to the accompanying financial statements for additional information regarding Broadway Sixty-Eight, Ltd.

 

Cash from Life Insurance Policy benefits was $391,290 in 2015 with none in 2016.

 

Discussion of Selected Material Line Items Resulting in an Increase in Cash Flows. Cash paid for production costs decreased $531,958 (20%) to $2,132,055 in 2016 from $2,664,013 in 2015. This decrease was due to lower lease operating expense of $437,083 and lower production taxes of $94,875 as a result of the decrease in oil and gas sales discussed above.

 

Cash paid for estimated income taxes decreased $720,036 (100%) to $508 in 2016 from $720,544 in 2015. The lower payments were mostly due to lower net income and current taxable income in 2016.

 

Investing Activities

 

Net cash applied to investing activities increased $2,613,432 (52%) to $7,630,988 in 2016 from $5,017,556 in 2015. This $2,613,432 increase was due primarily to a $6,788,803 increase in cash applied to the purchase of available-for-sale securities as a result of the rising short-term interest rates offset by the $3,974,970 maturity of additional available-for-sale securities and a $169,560 increase in purchases of equity and other investments. See “Equity and Other Investments” discussion on pages 9 and 10 for additional information regarding the investments purchased in 2015 and 2016.

 

Financing Activities

  

Cash applied to financing activities decreased $664,225 (40%) to $1,010,501 in 2016 from $1,674,726 in 2015. Cash applied to financing activities consist of cash dividends on common stock and cash used for the purchase of treasury stock. In 2016, cash dividends paid on common stock amounted to $921,667 as compared to $1,627,930 in 2015. Dividends of $5.00 per share were paid in 2016 and $10.00 per share were paid in 2015. Cash applied to purchase treasury stock increased $42,038 to $88,834 in 2016 from $46,796 in 2015.

 

Forward-Looking Summary

 

The Company’s latest estimate of business to be done in 2017 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.

 

 
11

 

 

RESULTS OF OPERATIONS

 

As disclosed in the Statements of Operations in Item 8 of this Form 10-K, in 2016 the Company had a net loss of ($84,225) as compared to net loss of ($1,885,332) in 2015. Net loss per share, basic and diluted, was ($0.53) in 2016, an increase of $11.36 per share from ($11.89) in 2015. Material line item changes in the Statements of Operations will be discussed in the following paragraphs.

 

Operating Revenues

 

Operating revenues decreased $2,159,848 (26%) to $6,291,138 in 2016 from $8,450,986 in 2015. Oil and gas sales decreased $2,222,842 (29%) to $5,418,164 in 2016 from $7,641,006 in 2015. Lease bonuses and other revenues increased $62,994 (8%) to $872,974 in 2016 from $809,980 in 2015. The decrease in oil and gas sales is discussed in the following paragraphs.

 

The $2,222,842 decrease in oil and gas sales was the net result of a $698,042 decrease in gas sales, a $1,505,392 decrease in oil sales and a $19,408 decrease 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 2016 to 2015. Miscellaneous oil and gas product sales of $159,970 in 2016 and $179,378 in 2015 are not included in the analysis.

 

           

Variance

         

Production

 

2016

   

Price

   

Volume

   

2015

 

Gas –

                               

MCF (000 omitted)

    971               (148)       1,119  

$ (000 omitted)

  $ 2,112     $ (327)     $ (371)     $ 2,810  

Unit Price

  $ 2.17     $ (0.34)             $ 2.51  
                                 

Oil –

                               

Bbls (000 omitted)

    85               (21)       106  

$ (000 omitted)

  $ 3,146     $ (605)     $ (901)     $ 4,652  

Unit Price

  $ 36.90     $ (7.10)             $ 44.00  

 

The $698,042 (25%) decrease in natural gas sales to $2,112,079 in 2016 from $2,810,121 in 2015 was the result of a decrease in both gas sales volumes and the average price received per thousand cubic feet (MCF). The average price per MCF of natural gas sales decreased $0.34 per MCF to $2.17 per MCF in 2016 from $2.51 per MCF in 2015, resulting in a negative gas price variance of $327,186. A negative volume variance of $370,856 was the result of a decrease in natural gas volumes sold of 147,751 MCF to 971,441 MCF in 2016 from 1,119,192 MCF in 2015. The decrease in the volume of gas production was the net result of new 2016 production of about 44,000 MCF, offset by a decline of about 192,000 MCF in production from previous wells. About 42,000 MCF (22%) of this decline is from working interest wells in Van Buren County, Arkansas, and another decline of about 63,000 MCF (33%) occurred in working interest wells in Roger Mills County, Oklahoma. 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 not adequate to replace working interest reserves produced in 2015 or 2016.

 

The gas production for 2015 and 2016 includes production from about 100 royalty interest properties drilled by various operators in Robertson County, Texas. These properties accounted for approximately 244,000 MCF and $621,000 of the 2015 gas sales and approximately 216,000 MCF and $468,000 of the 2016 gas sales. These properties accounted for about 23% of the Company’s gas revenues in 2016 versus 20% in 2015. The Company has no control over the timing of future drilling on the acreage in which we hold mineral interests.

 

The $1,505,392 (32%) decrease in crude oil sales to $3,146,115 in 2016 from $4,651,507 in 2015 was the result of a decrease in both the average price per barrel (Bbl) and the oil sales volumes. The average price received per Bbl of oil decreased $7.10 to $36.90 in 2016 from $44.00 in 2015, resulting in a negative oil price variance of $604,941. A decline in oil sales volumes of 20,465 Bbls to 85,251 Bbls in 2016 from 105,716 Bbls in 2015 resulted in a negative volume variance of $900,451. The decrease in the oil volume production was the net result of new 2016 production of about 3,400 Bbls, offset by a 24,000 Bbl decline in production from previous wells. Of the new 2016 production, approximately 1,200 Bbls (36%) was from new working interest wells in Chase County, Nebraska. 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 not adequate to replace working interest reserves produced in 2016 or 2015.

 

 
12

 

 

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

 

Operating Costs and Expenses

 

Operating costs and expenses decreased $5,046,775 (42%) to $6,870,641 in 2016 from $11,917,416 in 2015, primarily due to a decrease in depreciation, depletion and amortization expense. The material components of operating costs and expenses are discussed below.

 

Production Costs. Production costs decreased $460,288 (18%) to $2,140,756 in 2016 from $2,601,044 in 2015. The decrease was primarily the result of a $94,875 (31%) decrease in gross production tax to $216,046 in 2016 from $310,921 in 2015 and a decrease in lease operating expense of $287,711 (16%) to $1,501,022 in 2016 from $1,788,733 in 2015. Of the decrease in lease operating expense, $296,611 was the result of decreased expenses for existing wells offset by $8,900 of expenses for new wells. Gross production taxes are state taxes, which are calculated as a percentage of gross proceeds from the sale of products from each producing oil and gas property; therefore, they fluctuate with the change in the dollar amount of revenues from oil and gas sales.

 

Exploration 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 $1,110,426 in 2016 and $1,467,772 in 2015. See Item 8, Note 8 to the accompanying financial statements for a breakdown of these costs. Exploration costs charged to operations were $429,210 in 2016 and $584,705 in 2015, inclusive of unsuccessful exploratory well costs of $253,460 in 2016 and $374,066 in 2015, and geological and geophysical costs of $175,749 in 2016 and $210,639 in 2015.

  

Update of Oil and Gas Exploration and Development Activity from December 31, 2015. For the year ended December 31, 2016, the Company participated in the drilling of 12 gross exploratory and 7, including 4 in progress at the end of 2015, gross development working interest wells with working interests ranging from a high of 16% to a low of 8%. Of the 12 exploratory wells, 1 was completed as a producing well, 10 as dry holes and 1 was in progress. Of the 7 development wells, 4 were completed as producing wells and 3 were in progress.

 

The following is a summary as of March 8, 2017, updating both exploration and development activity from December 31, 2015, for the period ended December 31, 2016.

 

The Company participated with 10.3% and 10.7% working interests in the completion of two development wells on a Woods County, Oklahoma prospect. The wells were drilled in 2015. Both wells are commercial producers, one gas and the other oil and gas. Capitalized costs for the period were $40,589.

 

The Company participated with 8% and 16% working interests in the drilling of two development wells on a Woods County, Oklahoma prospect. Completions are in progress on both wells. Capitalized costs for the period were $80,800. 

 

The Company participated with its 8.4% interest in the acquisition of additional 3-D seismic data on a Thomas County, Kansas prospect and in the drilling of two exploratory wells on the prospect. The first well was completed as a dry hole and the second, started in 2017, is awaiting completion. Dry hole costs for the period were $29,747. Capitalized costs for the period were $23,402.

 

The Company participated with its 10.5% interest in a 3-D seismic survey on a Thomas County, Kansas prospect and in the drilling of two exploratory wells on the prospect. One of the wells was drilled in 2017. Both wells were completed as dry holes. Dry hole costs for the period were $28,979.

 

The Company participated with its 16% working interest in the drilling of two step-out wells on a Chase County, Nebraska prospect. Both wells were completed as commercial oil producers. Capitalized costs for the period were $115,547.

 

The Company is participating with its 14% interest in the development of a Hansford County, Texas prospect for waterflooding. The initial well has been drilled and completed as an oil producer. The second well has been drilled and will be completed as the first of five planned injection wells. Capitalized costs for the period were $146,598. 

 

The Company participated with its 14% working interest in the drilling of an exploratory well and a salt water disposal well on a Creek County, Oklahoma prospect. The exploratory well was started in 2017 and a completion is in progress. Capitalized costs for the period were $15,365.

 

 
13

 

 

Since February 2016, the Company has paid $161,067 for a 16% interest in 13,804.7 net acres of leasehold on a Chase County, Nebraska prospect. A 3-D seismic survey of the prospect has been completed. The Company participated in the drilling of an exploratory well on the prospect that was completed as a dry hole. A second exploratory well will be drilled starting in March 2017. Seismic costs for the period were $92,599 and dry hole costs were $38,256.

 

In March 2016, the Company purchased a 35% interest in 16,472.55 net acres of leasehold on a Crockett and Val Verde Counties, Texas prospect for $345,923. The Company is participating in the development of the prospect and a geologic study of the prospect area has been completed. The Company is currently engaged in efforts to sell a portion of its interest. Geological and geophysical costs for the period were $14,158.

 

In April 2016, the Company purchased a 14% interest in three prospects in Okfuskee and Seminole Counties, Oklahoma for $57,415. The Company participated in the drilling of an exploratory well on each of the prospects. All three wells were completed as dry holes. Dry hole costs for the period were $69,948.

 

In May 2016, the Company purchased a 14% interest in 640 net acres of leasehold and 3-D seismic data on a Lavaca County, Texas prospect for $56,000. The Company participated in the drilling of an exploratory well on the prospect that is awaiting completion. Capitalized costs for the period were $182,357.

 

In July 2016, the Company purchased a 16% interest in 2,071.6 net acres of leasehold on a Kingman County, Kansas prospect for $26,516. The Company participated in the re-entry and washdown of two old wellbores on the prospect. Both re-entries were unsuccessful and have been plugged. Dry hole costs for the period were $41,738.

 

In October 2016, the Company purchased a 35% interest in 2,240 net acres of leasehold on a Crockett County, Texas prospect for $47,454. A geologic study of the prospect area is in progress, and the Company is currently engaged in efforts to sell a portion of its interest.

 

In December 2016, the Company purchased a 14% interest in 1,280 net acres of leasehold on a Hodgeman County, Kansas prospect for $14,336 and in January 2017 paid $10,888 in estimated seismic costs. A 3-D seismic survey of the prospect area has been completed and an exploratory well will be drilled in April 2017.

 

In January 2017, the Company purchased a 14% interest in 2,443.84 net acres of leasehold on a Leflore County, Oklahoma prospect for $119,748. The Company participated in the drilling of an exploratory well on the prospect in 2017 that was completed as a dry hole.

 

In March 2017, the Company purchased a 16% interest in 587.6 net acres of leasehold on a Harvey County, Kansas prospect for $7,521 and paid $11,931 in estimated seismic costs. A 3-D seismic survey of the prospect area has been completed and an exploratory well will be drilled in November 2017.

 

In March 2017, the Company agreed to purchase a 13% interest in a 3-D seismic prospect covering approximately 35,000 acres in San Patricio County, Texas. The Company’s share of land and seismic costs is estimated to be $580,000 over a two-year period. Exploratory drilling should start sometime in 2018.

 

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 $390,584 in 2016 and $329,871 in 2015. Of the 2016 provision, $334,831 was due to the annual amortization of undeveloped leaseholds and $55,753 was due to specific leasehold impairments. The 2015 provision was due to the annual amortization of undeveloped leaseholds of $301,052 and specific leasehold impairments of $28,819.

 

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 2016 and 2015. The 2016 impairment loss was $727,845 and the 2015 impairment loss was $3,726,267. The $2,998,422 decrease in impairments in 2016 was mainly due to fairly stable oil and natural gas prices.

 

 
14

 

 

The depletion and depreciation of oil and gas properties are computed by the units-of-production method. The amount expensed in any year will fluctuate with the change in estimated reserves of oil and gas, a change in the rate of production or a change in the basis of the assets. The Company did not participate in any horizontal working interest wells in 2015 or 2016. 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 declined $1,432,221 (48%) to $1,570,972 in 2016 from $3,003,193 in 2015. This decrease is due to the reasons discussed above. The provision also includes $113,578 for 2016 and $135,088 for 2015 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, Net. See Item 8, Note 11 to the accompanying financial statements for an analysis of the components of this line item for 2016 and 2015. Other income, net increased $229,314 (326%) to $299,592 in 2016 from $70,278 in 2015. The line items responsible for this net increase are described below.

 

Net realized and unrealized gain (loss) on trading securities increased $97,470 to a net gain of $61,729 in 2016 from a net loss of ($35,741) in 2015. 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 2016, the Company had realized losses of $20,430 and unrealized gains of $82,159. In 2015, the Company had realized gains of $31,902 and unrealized losses of $67,643.

 

Income from investments increased $95,000 to $155,000 in 2016 from $60,000 in 2015.

 

Gains on asset sales decreased $46,364 to $22,123 in 2016 from $68,487.

 

Interest income increased $33,017 to $46,370 in 2016 from $13,353 in 2015. This increase was the result of a rise in the average interest rate and an increase 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 interest rate increased from 0.11% in 2015 to 0.33% in 2016. The average balance outstanding increased $1,994,941 to $13,845,418 in 2016 from $11,850,477 in 2015.

 

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 2016, the Company had an estimated income tax benefit of $172,886 as the result of a current tax benefit of $57,676, plus a deferred tax benefit of $115,210. In 2015, the Company had an estimated income tax benefit of $1,472,545 as the result of a current tax provision of $386,886, offset by a deferred tax benefit of $1,859,431.

 

 

ITEM 7A.

QUANTITATIVE AND QUALiTATIVE DISCLOSURES ABOUT MARKET RISKS

 

Not applicable.

 

 

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

Index to Financial Statements  
   

 

Page

Report of Independent Registered Public Accounting Firm, HoganTaylor LLP

16

Balance Sheets – December 31, 2016 and 2015

17

Statements of Operations – Years Ended December 31, 2016 and 2015

19

Statements of Stockholders’ Equity – Years Ended December 31, 2016 and 2015

20

Statements of Cash Flows – Years Ended December 31, 2016 and 2015

21

Notes to Financial Statements

23

Unaudited Supplemental Financial Information

32

 

 
15

 

 

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, 2016 and 2015, and the related statements of operations, stockholders’ equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our 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, 2016 and 2015, 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 29, 2017

 

 
16

 

 

THE RESERVE PETROLEUM COMPANY

 

BALANCE SHEETS

 

ASSETS

 
   

December 31,

 
   

2016

   

2015

 

Current Assets:

               

Cash and Cash Equivalents (Note 2)

  $ 8,071,854     $ 13,937,215  

Available-for-Sale Securities (Notes 2 & 5)

    13,443,636       8,642,053  

Trading Securities (Notes 2 & 5)

    473,707       410,724  

Refundable Income Taxes

    536,798       488,052  

Receivables (Note 2)

    764,641       644,868  

Total Current Assets

    23,290,636       24,122,912  
                 

Investments:

               

Equity Investments (Notes 2 & 7)

    822,570       964,770  

Other, at Cost

    1,906,856       876,856  

Total Investments

    2,729,426       1,841,626  
                 

Property, Plant and Equipment (Notes 2, 8 & 10):

               

Oil and Gas Properties, at Cost,

               

Based on the Successful Efforts Method of Accounting –

               

Unproved Properties

    2,180,018       1,874,283  

Proved Properties

    53,030,034       52,735,721  

Oil and Gas Properties, Gross

    55,210,052       54,610,004  
                 

Less – Accumulated Depreciation, Depletion, Amortization and Valuation Allowance

    44,456,113       42,535,199  

Oil and Gas Properties, Net

    10,753,939       12,074,805  

Other Property and Equipment, at Cost

    406,430       392,918  
                 

Less – Accumulated Depreciation

    231,887       244,362  

Other Property and Equipment, Net

    174,543       148,556  

Total Property, Plant and Equipment

    10,928,482       12,223,361  

Total Assets

  $ 36,948,544     $ 38,187,899  

 

See Accompanying Notes

 

 
17

 

 

THE RESERVE PETROLEUM COMPANY

 

BALANCE SHEETS

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 
                 
   

December 31,

 
   

2016

   

2015

 

Current Liabilities:

               

Accounts Payable

  $ 161,749     $ 225,648  

Other Current Liabilities

    25,590       26,006  

Total Current Liabilities

    187,339       251,654  
                 

Long-Term Liabilities:

               

Asset Retirement Obligation (Note 2)

    1,710,677       1,677,328  

Dividends Payable (Note 3)

    1,278,266       1,407,959  

Deferred Tax Liability, Net (Note 6)

    1,511,160       1,626,370  

Total Long-Term Liabilities

    4,500,103       4,711,657  

Total Liabilities

    4,687,442       4,963,311  
                 

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

    33,600,718       34,475,369  

Stockholders’ Equity Before Treasury Stock

    33,758,086       34,632,737  
                 

Less – Treasury Stock, at Cost

    1,496,984       1,408,149  

Total Stockholders’ Equity

    32,261,102       33,224,588  

Total Liabilities and Stockholders’ Equity

  $ 36,948,544     $ 38,187,899  

 

See Accompanying Notes

 

 
18

 

 

THE RESERVE PETROLEUM COMPANY

 

STATEMENTS OF OPERATIONS

 
                 
                 
                 
   

Year Ended December 31,

 
   

2016

   

2015

 
                 

Operating Revenues:

               

Oil and Gas Sales

  $ 5,418,164     $ 7,641,006  

Lease Bonuses and Other

    872,974       809,980  

Total Operating Revenues

    6,291,138       8,450,986  
                 

Operating Costs and Expenses:

               

Production

    2,140,756       2,601,044  

Exploration

    429,210       584,705  

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

    2,719,899       7,091,552  

General, Administrative and Other

    1,580,776       1,640,115  

Total Operating Costs and Expenses

    6,870,641       11,917,416  

Loss from Operations

    (579,503 )     (3,466,430 )

Equity Income in Investees (Note 7)

    22,800       38,275  

Other Income, Net (Note 11)

    299,592       70,278  

Loss Before Income Taxes

    (257,111 )     (3,357,877 )

Income Tax Benefit (Notes 2 & 6)

    (172,886 )     (1,472,545 )

Net Loss

  $ (84,225 )   $ (1,885,332 )
                 

Per Share Data (Note 2):

               

Net Loss, Basic and Diluted

  $ (0.53 )   $ (11.89 )

Cash Dividends

  $ 5.00     $ 10.00  

Weighted Average Shares Outstanding, Basic and Diluted

    158,107       158,557  

 

See Accompanying Notes

 

 
19

 

 

THE RESERVE PETROLEUM COMPANY

 

STATEMENTS OF STOCKHOLDERS’ EQUITY

 

FOR THE YEARS ENDED DECEMBER 31, 2016 AND 2015

 
                                         
                                         
                                         
           

Additional

                         
   

Common

   

Paid-in

   

Retained

   

Treasury

         
   

Stock

   

Capital

   

Earnings

   

Stock

   

Total

 
                                         

Balance at December 31, 2014

  $ 92,368     $ 65,000     $ 37,946,212     $ (1,361,353 )   $ 36,742,227  
                                         

Net Loss

    ---       ---       (1,885,332 )     ---       (1,885,332 )

Dividends Declared

    ---       ---       (1,585,511 )     ---       (1,585,511 )

Purchase of Treasury Stock

    ---       ---       ---       (46,796 )     (46,796 )
                                         

Balance at December 31, 2015

    92,368       65,000       34,475,369       (1,408,149 )     33,224,588  
                                         

Net Loss

    ---       ---       (84,225 )     ---       (84,225 )

Dividends Declared

    ---       ---       (790,426 )     ---       (790,426 )

Purchase of Treasury Stock

    ---       ---       ---       (88,835 )     (88,835 )
                                         

Balance at December 31, 2016

  $ 92,368     $ 65,000     $ 33,600,718     $ (1,496,984 )   $ 32,261,102  

 

See Accompanying Notes

 

 
20

 

 

THE RESERVE PETROLEUM COMPANY

 

STATEMENTS OF CASH FLOWS

 
                 
                 
                 
   

Year Ended December 31,

 
   

2016

   

2015

 
                 

Cash from Operating Activities:

               

Cash Received –

               

Oil and Gas Sales

  $ 5,346,837     $ 9,139,958  

Lease Bonuses and Other

    872,974       809,980  

Sale of Trading Securities

    858,921       561,844  

Interest Received

    42,228       14,995  

Agricultural Rentals and Other

    60,648       11,193  

Dividends Received on Trading Securities

    1,254       1,032  

Cash Distributions from Equity Investments

    165,000       82,500  

Cash from Life Insurance Policy Benefits

    ---       391,290  

Tax Refunds

    9,438       ---  

Cash Paid –

               

Production Costs

    (2,132,055 )     (2,664,013 )

General Suppliers, Employees and Taxes, Other than Income Taxes

    (1,587,921 )     (1,638,948 )

Purchase of Trading Securities

    (860,175 )     (562,832 )

Income Taxes Paid, Net

    (508 )     (720,544 )

Farm Expense and Other

    (513 )     (516 )

Net Cash Provided by Operating Activities

    2,776,128       5,425,939  
                 
                 

Cash Provided by/(Applied to) Investing Activities:

               

Maturity of Available-for-Sale Securities

    17,283,067       13,308,097  

Purchase of Available-for-Sale Securities

    (22,084,650 )     (15,295,847 )

Proceeds from Disposal of Property, Plant and Equipment

    23,774       70,981  

Purchase of Property, Plant and Equipment

    (1,978,179 )     (2,300,347 )

Cash Distributions from Other Investments

    155,000       60,000  

Purchase of Equity and Other Investments

    (1,030,000 )     (860,440 )

Net Cash Applied to Investing Activities

    (7,630,988 )     (5,017,556 )

 

See Accompanying Notes

 

 
21

 

 

THE RESERVE PETROLEUM COMPANY

 

STATEMENTS OF CASH FLOWS

 
                 
                 
                 
   

Year Ended December 31,

 
   

2016

   

2015

 
                 

Cash Applied to Financing Activities:

               

Dividends Paid to Stockholders

  $ (921,667 )   $ (1,627,930 )

Purchase of Treasury Stock

    (88,834 )     (46,796 )

Total Cash Applied to Financing Activities

    (1,010,501 )     (1,674,726 )
                 

Net Change in Cash and Cash Equivalents

    (5,865,361 )     (1,266,343 )
                 

Cash and Cash Equivalents at Beginning of Year

    13,937,215       15,203,558  

Cash and Cash Equivalents at End of Year

  $ 8,071,854     $ 13,937,215  
                 
                 

Reconciliation of Net Loss to Net Cash Provided by Operating Activities:

               

Net Loss

  $ (84,225 )   $ (1,885,332 )

Net Loss Increased (Decreased) by Net Change in –

               

Net Unrealized Holding (Gains)/Losses on Trading Securities

    (82,159 )     67,643  

Accounts Receivable

    (70,046 )     1,499,203  

Interest and Dividends Receivable

    (4,142 )     (1,715 )

Refundable Income Taxes

    (48,746 )     (333,659 )

Accounts Payable

    5,911       (54,408 )

Trading Securities

    19,176       (32,891 )

Deferred Taxes

    (115,210 )     (1,859,431 )

Other Liabilities

    46,602       46,814  

Income from Equity and Other Investments

    (177,800 )     (98,275 )

Cash Distribution from Equity Investments

    165,000       82,500  

Cash from Life Insurance Policy Benefits

    ---       391,290  

Exploratory Costs

    377,112       355,780  

Disposition of Property, Plant and Equipment

    24,756       156,868  

Depreciation, Depletion, Amortization and Valuation Provisions

    2,719,899       7,091,552  

Net Cash Provided by Operating Activities

  $ 2,776,128     $ 5,425,939  

 

See Accompanying Notes

 

 
22

 

  

THE RESERVE PETROLEUM COMPANY

NOTES TO FINANCIAL STATEMENTS

 

Note 1 – NATURE OF OPERATIONS

 

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

 

Note 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Cash and Cash Equivalents

 

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

 

Investments

 

Marketable Securities:

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

 

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

 

Unrealized gains and losses on available-for-sale securities, which consist entirely of U.S. Government securities, are reported as a component of other comprehensive income when significant to the financial statements. There are no significant cumulative unrealized gains or losses on available-for-sale securities as of December 31, 2016 or 2015. 

 

Equity and Cost Investments:

The Company accounts for its non-marketable investment in partnerships on the equity method if ownership allows the Company to exercise significant influence, or the cost method, if not. See Note 7 for additional information on equity investments.

 

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.

 

 
23 

 

 

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

 

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

  

Office furniture and fixtures (years)

5 to

10

Automotive equipment (years)

5 to

8

 

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 quarterly. 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 2013, 2014 and 2015 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 2016 and 2015, 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 2016 whose purchases were 35% of total oil and gas sales, compared to one in 2015 with 27% of total sales.

 

The Company maintains its cash in bank deposit accounts, which at times may exceed federally insured limits. The Company has not experienced any losses in such accounts, and believes that it is not exposed to any significant credit risk with respect to cash and cash equivalents.

 

Use of Estimates

 

The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include oil and natural gas reserve quantities that form the basis for the calculation of amortization of oil and natural gas properties. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories. Actual results could differ from the estimates and assumptions used in the preparation of the Company’s financial statements.

 

Gas Balancing

 

Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability is recorded when the Company’s excess takes of natural gas volumes exceed our estimated remaining recoverable reserves (over-produced). No receivables are recorded for those wells where the Company has taken less than our ownership share of gas production (under-produced).

 

Guarantees

 

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

 

 
24

 

  

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, inflating it over the life of the property and discounting the estimated obligation to its present value. 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 2016 and 2015:

 

   

2016

   

2015

 

Beginning balance at January 1

  $ 1,677,328     $ 1,645,597  

Liabilities incurred

    18,321       49,275  

Liabilities settled (wells sold or plugged)

    (20,542 )     (17,214 )

Accretion expense

    47,018       47,531  

Revision to estimate

    (11,448 )     (47,861 )

Ending balance at December 31

  $ 1,710,677     $ 1,677,328  

 

New Accounting Pronouncements

 

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers. ASU 2014-09 clarifies the principles for recognizing revenue and develops a common revenue standard under U.S. Generally Accepted Accounting Principles (“GAAP”) under which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 (as amended) is effective for the Company beginning January 1, 2018. The new standard allows application either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. Management is currently assessing the adoption method and the impact ASU 2014-09 will have on the Company, but it is not expected to have a material effect on the Company’s financial position, results of operations or cash flows.

 

In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes. The update requires that deferred income tax assets and liabilities be classified as noncurrent in the balance sheet. For public entities, the guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The Company early adopted ASU 2015-17 as of December 31, 2016, on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified $61,710 and $12,487 as of December 31, 2016, and December 31, 2015, respectively, from "Other Current Liabilities" in current liabilities to “Deferred Tax Liability, Net” in long term liabilities on the balance sheets. Adoption of ASU 2015-17 had no impact on the Company's current and previously reported shareholders' equity, results of operations or cash flows. The affected prior period deferred income tax account balances presented throughout this report on Form 10-K have been adjusted to reflect the retroactive adoption of ASU 2015-17.

 

In January, 2016, the FASB issued ASU No. 2016-01, Recognition and Measurement of Financial Assets and Liabilities. The update simplifies the accounting and disclosures related to equity investments. The amendments in ASU 2016-01 are effective for fiscal years beginning after December 15, 2017 and for interim periods therein. Adoption of this update will not have a material impact on the Company’s financial position, results of operations or cash flows.

 

In February 2016, the FASB issued ASU No. 2016-02, Leases with new lease accounting guidance. Under the new guidance, at the commencement date, lessees will be required to recognize a lease liability, which is a lessee‘s obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The new guidance is not applicable for leases with a term of 12 months or less. Lessor accounting is largely unchanged. ASU 2016-02 is effective for the Company beginning after December 15, 2018, including interim periods within those fiscal years. The Company currently has no capital or operating leases. Accordingly, we do not expect this new guidance to have any impact on the Company’s financial position, results of operations or cash flows.

 

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which addresses certain issues where diversity in practice was identified and may change how an entity classifies certain cash receipts and cash payments on its statement of cash flows. The new guidance also clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. This guidance will generally be applied retrospectively and is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those years. Early adoption is permitted. All of the amendments in ASU 2016-15 are required to be adopted at the same time. The Company does not expect this new guidance to have a material impact on the Company’s statement of cash flows.

 

 
25

 

 

Note 3 – DIVIDENDS PAYABLE

 

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

 

Note 4 – COMMON STOCK

 

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

 

           

Shares of

         
   

Shares

   

Treasury

   

Shares

 
   

Issued

   

Stock

   

Outstanding

 

January 1, 2015, $.50 par value stock, 200,000 shares authorized

    184,735       26,063       158,672  

Purchase of stock

    ---       214       (214 )

December 31, 2015, $.50 par value stock, 200,000 shares authorized

    184,735       26,277       158,458  

Purchase of stock

    ---       554       (554 )

December 31, 2016, $.50 par value stock, 200,000 shares authorized

    184,735       26,831       157,904  

 

Note 5 – MARKETABLE SECURITIES

 

At December 31, 2016, 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 2016 the Company recorded realized losses of $20,430 and unrealized gains of $82,159. In 2015 the Company recorded realized gains of $31,902 and unrealized losses of $67,643.

 

Note 6 – INCOME TAXES

 

Components of deferred taxes are as follows:

 

   

December 31,

 
   

2016

   

2015

 

Assets:

               

Net Leasehold Impairment Reserves

  $ 290,167     $ 298,061  

Gas Balance Receivable

    52,379       52,379  

Long-Lived Asset Impairment

    1,745,936       2,163,449  

Deferred Geological and Geophysical Expense

    62,720       110,107  

Other

    406,579       385,307  

Total Assets

    2,557,781       3,009,303  

  

 
26

 

 

Liabilities:

               

Receivables

    91,622       70,335  

Intangible Drilling Costs

    2,856,294       3,434,057  

Depletion, Depreciation and Other

    1,121,025       1,131,281  

Total Liabilities

    4,068,941       4,635,673  

Net Deferred Tax Liability

  $ (1,511,160 )   $ (1,626,370 )

 

The decrease in the deferred tax liability for 2016 reflected in the above table is primarily the result of a decline of intangible drilling costs.

 

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

 

   

Year Ended December 31,

 
   

2016

   

2015

 

Current Tax Provision/(Benefit):

               

Federal

  $ (57,494 )   $ 402,676  

State

    (182 )     (15,790 )

Total Current Provision/(Benefit)

    (57,676 )     386,886  

Deferred Tax Benefit

    (115,210 )     (1,859,431 )

Total Benefit

  $ (172,886 )   $ (1,472,545 )

  

The total income tax benefit expressed as a percentage of loss before income tax was 67% for 2016 and 44% for 2015. These amounts differ from the amounts computed by applying the statutory U.S. federal income tax rate of 34% for 2016 and 2015 to loss before income tax as summarized in the following reconciliation:

 

   

Year Ended December 31,

 
   

2016

   

2015

 
                 

Computed Federal Tax Benefit

  $ (87,418 )   $ (1,141,678 )
                 

Increase (Decrease) in Tax From:

               

Allowable Depletion in Excess of Basis

    (83,460 )     (359,552 )

Dividend Received Deduction

    (878 )     (723 )

State Income Tax Benefit

    (182 )     (15,790 )

Other

    (948 )     45,198  

Income Tax Benefit

  $ (172,886 )   $ (1,472,545 )

Effective Tax Rate

    67%       44%  

 

Excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, reduces estimated taxable income projected for any year. When a provision for income taxes is recorded, federal excess percentage depletion benefits decrease the effective tax rate. When a benefit for income taxes is recorded, federal excess percentage depletion benefits increase the effective tax rate. The benefit of federal excess percentage depletion is not directly related to the amount of pre-tax income recorded in a period. Accordingly, in periods where a recorded pre-tax income is relatively small or a pre-tax loss, the proportional effect of these items on the effective tax rate may be significant.

 

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

 

The Company’s Equity Investments include a 33% ownership interest in Broadway Sixty-Eight, Ltd. (the “Partnership”), an Oklahoma limited partnership, which owns and operates an office building in Oklahoma City, Oklahoma. Although the Company invested as a limited partner, it agreed, jointly and severally, with all other limited partners to reimburse the general partner for any losses suffered from operating the Partnership. The indemnity agreement provides no limitation to the maximum potential future payments. To date, no monies have been paid with respect to this agreement.

 

The Company leases its corporate office from the Partnership. The operating lease, under which the space was rented, expired February 28, 1994, and the space is currently rented on a year-to-year basis under the terms of the expired lease. Rent expense for lease of the corporate office from the Partnership was approximately $30,000 for 2016 and 2015.

 

The Company’s Equity Investments also include a 47% ownership in Grand Woods Development, LLC (the “LLC”) an Oklahoma limited liability company acquired in November 2015. The LLC owns approximately 26.3 acres of undeveloped real estate in northeast Oklahoma City. The Company has guaranteed a loan for which the proceeds were used to purchase a portion of the undeveloped real estate acreage.

 

 
27

 

  

Note 8 – COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION, AND DEVELOPMENT ACTIVITIES

 

All of the Company’s oil and gas operations are within the continental United States. In connection with its oil and gas operations, the following costs were incurred:

 

   

Year Ended December 31,

 
   

2016

   

2015

 

Acquisition of Properties:

               

Unproved

  $ 715,520     $ 360,685  

Proved

    ---       108,384  

Exploration Costs

    856,075       846,879  

Development Costs

    254,351       620,893  

Asset Retirement Obligation

    18,321       49,275  

 

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 2016 and 2015 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, 2016 and 2015, the Company’s assets reported at fair value on a recurring basis are summarized as follows:

 

   

2016

 
                         
   

Level 1 Inputs

   

Level 2 Inputs

   

Level 3 Inputs

 

Financial Assets:

                       

Available-for-Sale Securities –

                       

U.S. Treasury Bills Maturing in 2017

  $ ---     $ 13,443,636     $ ---  

Trading Securities –

                       

Domestic Equities

    333,516       ---       ---  

International Equities

    83,948       ---       ---  

Others

    56,243       ---       ---  

  

 
28

 

 

   

2015

 
                         
   

Level 1 Inputs

   

Level 2 Inputs

   

Level 3 Inputs

 

Financial Assets:

                       

Available-for-Sale Securities –

                       

U.S. Treasury Bills Maturing in 2016

  $ ---     $ 8,642,053     $ ---  

Trading Securities –

                       

Domestic Equities

    292,820       ---       ---  

International Equities

    100,920       ---       ---  

Others

    16,984       ---       ---  

 

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 $18,321 in 2016 and $49,275 in 2015 and was calculated using Level 3 inputs. See Note 2 for more information about this liability and the inputs used for calculating fair value.

 

The fair value of oil and gas properties used in estimating impairment losses of $727,845 for 2016 and $3,726,267 for 2015 were based on Level 3 inputs. See Note 10 for the procedure 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, 2016 and 2015, the historical cost of cash and cash equivalents, trade receivables, trade payables, and dividends payable are considered to be representative of their respective fair values due to the short-term maturities of these items.

 

Note 10 – LONG-LIVED ASSETS IMPAIRMENT LOSS

 

Certain oil and gas producing properties have been deemed to be impaired because the assets, evaluated on a property-by-property basis, are not expected to recover their entire carrying value through future cash flows. Impairment losses totaling $727,845 for 2016 and $3,726,267 for 2015 are included in the Statements of Operations in the line item Depreciation, Depletion, Amortization and Valuation Provisions. The impairments for 2016 and 2015 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 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:

 

   

2016

   

2015

 

Net Realized and Unrealized Gain (Loss) on Trading Securities

  $ 61,729     $ (35,741 )

Gains on Asset Sales

    22,123       68,487  

Interest Income

    46,370       13,353  

Settlements of Class Action Lawsuits

    55,048       5,593  

Agricultural Rental Income

    5,600       5,600  

Dividend Income

    1,254       1,033  

Income from Other Investments

    155,000       60,000  

Interest and Other Expenses

    (47,532 )     (48,047 )

Other Income, Net

  $ 299,592     $ 70,278  

  

 
29

 

 

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) and Lochbuie Limited Liability Company (LLTD). 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 2016 in the amount of $182,926 each by Mesquite, Mid-American and LLTD. Reimbursements in 2015 were $194,686 each by Mesquite, Mid-American and LLTD. Included in the 2016 amounts, Mesquite, Mid-American and LLTD each paid $132,215 for their share of salaries. In 2015, the share of salaries paid by Mesquite, Mid-American and LLTD was $132,611 each.

 

Note 13 – SUBSEQUENT EVENTS 

 

In January 2017, the Company received $440,000 from OKC Industrial Properties (OKC) as its share of profit from the sale of some undeveloped real estate by OKC. The Company owns 10% of OKC and our investment of $56,164 is included in the balance sheet line item “Investments: Other, at Cost.” The $440,000 will be included as income in the operating results for the quarter ending March 31, 2017.

 

 
30

 

 

UNAUDITED SUPPLEMENTAL FINANCIAL INFORMATION

 

 
31

 

 

 SUPPLEMENTAL SCHEDULE 1

 

THE RESERVE PETROLEUM COMPANY

WORKING INTEREST RESERVE QUANTITY INFORMATION

(Unaudited)

 

   

Year Ended December 31,

 
   

2016

   

2015

 

Oil and Condensate (Bbls)

               

Proved Developed and Undeveloped Reserves:

               

Beginning of Year

    462,241       523,871  

Revisions of Previous Estimates

    (1,977 )     (580 )

Extensions and Discoveries

    9,148       23,159  

Purchase of Reserves

    ---       ---  

Production

    (67,828 )     (84,209 )

End of Year

    401,584       462,241  

Proved Developed Reserves:

               

Beginning of Year

    415,402       482,717  

End of Year

    358,822       415,402  
                 

Gas (MCF)

               

Proved Developed and Undeveloped Reserves:

               

Beginning of Year

    3,637,626       4,477,027  

Revisions of Previous Estimates

    (49,227 )     (154,733 )

Extensions and Discoveries

    71,715       73,220  

Purchase of Reserves

    ---       ---  

Production

    (636,360 )     (757,888 )

End of Year

    3,023,754       3,637,626  

Proved Developed Reserves:

               

Beginning of Year

    3,309,750       4,188,946  

End of Year

    2,809,944       3,309,750  

 

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 17,423 Bbls of oil and 335,081 MCF of gas for 2016 and 21,507 Bbls of oil and 361,304 MCF of gas for 2015.

 

 

2.

The preceding table sets forth estimates of the Company’s proved oil and gas reserves, together with the changes in those reserves, as prepared by the Company’s engineer for 2016 and 2015. 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 2016 summary reserve report was tested by comparison to 2016 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,

 
   

2016

   

2015

 

Future Cash Inflows

  $ 20,452,614     $ 26,969,731  

Future Production and Development Costs

    (11,392,251 )     (13,382,527 )

Future Asset Retirement Obligation

    (1,802,124 )     (1,873,242 )

Future Income Tax Benefit (Expense)

    369,553       (1,057,870 )

Future Net Cash Flows

    7,627,792       10,656,092  

10% Annual Discount for Estimated Timing of Cash Flows

    (2,373,717 )     (3,250,586 )

Standardized Measure of Discounted Future Net Cash Flows

  $ 5,254,075     $ 7,405,506  

 

 

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 2015 and 2016, 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,

 
   

2016

   

2015

 

Standardized Measure, Beginning of Year

  $ 7,405,506     $ 21,693,023  

Sales and Transfers, Net of Production Costs

    (1,935,438 )     (3,145,463 )

Net Change in Sales and Transfer Prices, Net of Production Costs

    (1,992,946 )     (17,350,045 )

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

    347,007       745,025  

Revisions of Quantity Estimates

    (62,357 )     (226,084 )

Accretion of Discount

    1,006,978       2,921,430  

Purchases of Reserves in Place

    ---       ---  

Net Change in Income Taxes

    1,009,435       4,836,078  

Net Change in Asset Retirement Obligation

    (13,669 )     15,800  

Changes in Production Rates (Timing) and Other

    (510,441 )     (2,084,258 )

Standardized Measure, End of Year

  $ 5,254,075     $ 7,405,506  

 

 
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, 2016.

 

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 (2013) 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, 2016.

 

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 29, 2017   March 29, 2017

 

 
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, 2016 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.

 

 

ITEM 9B.

OTHER INFORMATION

 

None.

  

PART III

 

 

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 

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

 

 

ITEM 11.

EXECUTIVE COMPENSATION

 

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

 

 

ITEM 12.

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

 

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

 

 

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

 

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

 

 

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

 

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

 

 
37

 

 

PART IV

 

 

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 

The following documents are exhibits to this Form 10-K. Each document marked by an asterisk is filed electronically herewith.

 

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 for Senior Officers incorporated by reference to Exhibit 14 of The Reserve Petroleum Company’s Annual Report on Form 10-KSB (Commission File No. 0-8157) filed March 30, 2006.

     

31.1*

 

Certification of Principal Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as amended.

     

31.2*

 

Certification of Principal Financial Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as amended.

     

32*

 

Certification of Principal Executive Officer and Principal Financial Officer Pursuant to 18 U.S.C. Section 1350.

     

101.INS*

 

XBRL Instance Document

     

101.SCH*

 

XBRL Taxonomy Extension Schema Document

     

101.CAL*

 

XBRL Taxonomy Calculation Linkbase Document

     

101.DEF*

 

XBRL Taxonomy Definition Linkbase Document

     

101.LAB*

 

XBRL Taxonomy Label Linkbase Document

     

101.PRE*

 

XBRL Taxonomy Presentation Linkbase Document

       
    * Filed electronically herewith.

 

 

ITEM 16.

FORM 10-K SUMMARY

 

None. 

 

 
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 29, 2017

 

 

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 29, 2017

 

 

March 29, 2017

 

 

 

 

 

 

 

 

/s/ Robert L. Savage

 

 

/s/ William M. Smith

 

Robert L. Savage (Director)

 

 

William M. Smith (Director)

 

March 29, 2017

 

 

March 29, 2017

 

 

 

39