______________________________________________________________________________________________
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
| [X] | ANNUAL REPORT PURSUANT TO SECTION 13 OR 5(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| For the Year ended December 31, 2019 |
OR
| [ ] | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE TRANSITION PERIOD FROM TO
Commission File Number 000-08187
NEW CONCEPT ENERGY, INC.
(Exact name of registrant as specified in its charter)
| Nevada | 75-2399477 | |||||||||
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(State or Other Jurisdiction of Incorporation or Organization) |
(I.R.S. Employer Identification No.) | |||||||||
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1603 LBJ Freeway Suite 800 Dallas, Texas | ||||||||||
| (Address of principal executive offices) | ||||||||||
| 75234 | ||||||||||
| (Zip Code) | ||||||||||
| (972) 407-8400 | ||||||||||
| (Registrant’s telephone number, including area code) | ||||||||||
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Securities registered pursuant to Section 12(b) of the Exchange Act:
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| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||||
| Common Stock, par value $0.01 | GBR | NYSE AMERICAN | ||||||||
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [ ] No [X]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [X]
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 [X] No [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website 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 [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) 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. [X]
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes [ ] No [X]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act. Yes [ ] No [X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition 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 | __X___ |
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The aggregate market value of the shares of voting and non-voting common equity held by non-affiliates of the Registrant, computed by reference to the closing price at which the common equity was last sold which was the sales price of the Common Stock on the NYSE American as of June 30, 2019 (the last business day of the Registrant’s most recently completed second fiscal quarter) was $3,582,,000 based upon a total of 1,946,935 shares held as of June 30, 2019 by persons believed to be non-affiliates of the Registrant. The basis of the calculation does not constitute a determination by the Registrant as defined in Rule 405 of the Securities Act of 1933, as amended, such calculation, if made as of a date within sixty days of this filing, would yield a different value.
As of March 25, 2020 there were 5,131,934 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: NONE
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NEW CONCEPT ENERGY, INC.
Index to Annual Report on Form 10-K
Fiscal year ended December 31, 2019
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NEW CONCEPT ENERGY, INC.
Certain statements in this Form 10-K are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934. The words “estimate”, “plan”, “intend”, “expect”, “anticipate”, “and believe” and similar expressions are intended to identify forward-looking statements. These forward-looking statements are found at various places throughout this Report and in the documents incorporated herein by reference. New Concept Energy, Inc. disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Although we believe that our expectations are based upon reasonable assumptions, we can give no assurance that our goals will be achieved. Important factors that could cause our actual results to differ from estimates or projections contained in any forward-looking statements are described under Item 1A. Risk Factors beginning on page 5.
New Concept Energy, Inc. (“New Concept”, “NCE” or the “Company” or “we” or “us”) was incorporated in Nevada on May 31, 1991, under the name Medical Resource Companies of America, Inc. The Company is the successor-by-merger to Wespac Investors Trust, a California business trust that began operating in 1982. On March 26, 1996, the name was changed to Greenbriar Corporation. On February 8, 2005, the name of the Company was changed to CabelTel International Corporation. On May 21, 2008, the name of the company was changed to New Concept Energy, Inc.
Recent Stock Issuance; Change in Control
"See Item 12 below for a description of the sale by the Company of 3,000,000 shares of common stock on December 4, 2018 to a now related party and the resulting change in control of the Company."
Oil and Gas Operations
The Company, through its wholly owned subsidiaries Mountaineer State Energy, Inc. and Mountaineer State Operations, LLC, owns and operates oil and gas wells and mineral leases in Athens and Meigs Counties in Ohio and in Calhoun, Jackson and Roane Counties in West Virginia. The majority of our oil & gas operation was acquired through the acquisition of the Carl E. Smith Companies in 2008.
As of December 31, 2019 the Company has 153 producing wells, 44 non-producing wells and related equipment and mineral leases covering approximately 20,000 acres.
Business Strategy
The Company is a Nevada corporation which owns and operates oil and gas wells in Ohio and West Virginia.
The Company intends to continue to pursue acquisition of undervalued or distressed oil and gas related businesses, as well as additional acquisitions of oil and gas leases. The Company may choose to develop or resell the acquired acreage as management deems most beneficial to the Company. The Company’s strategy is dependent on available financing as well as the market price for oil and gas.
Insurance
The Company currently maintains property and liability insurance intended to cover claims in its oil and gas operations, and corporate operations. The provision of personal services entails an inherent risk of liability compared to more institutional long-term care communities. The Company also carries property insurance on each of its owned and leased properties, as appropriate.
Employees
At December 31, 2019, the Company employed the services of 5 people with the remainder of the work contracted to third parties. The Company believes it maintains good relationships with its employees. None of the Company’s employees are represented by a collective bargaining group.
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The Company’s operations are subject to the Fair Labor Standards Act. Many of the Company’s employees are paid at rates related to the minimum wage and any increase in the minimum wage will result in an increase in labor costs.
Management is not aware of any non-compliance by the Company as regards applicable regulatory requirements that would have a material adverse effect on the Company’s financial condition or results of operations.
Quality Assurance
Energy Philosophy – The Company is committed to the preservation and enhancement of the environment in which we operate. We are philosophically and operationally focused to continually prioritize the sensitivity of our ecological system in which we develop resources for our generation as well as our children’s. Management’s legacy is to prove that the energy industry can develop the earth’s natural resources with clean and efficient technologies while preserving its fragile beauty. Our technologies directly and significantly reduce the impact of our operations on nature and wildlife by minimizing surface disturbance.
Regular Property Inspections – Property inspections are conducted by corporate personnel. These inspections cover the appearance of the exterior and grounds, the appearance and cleanliness of the interior, the professionalism and friendliness of staff and notes on maintenance.
Marketing
The Company sells its oil and natural gas production to a limited number of purchasers. While there is an available market for crude oil and natural gas production, we cannot be assured that the loss of these purchasers would not have a material impact on the Company. Further a reduction in the market price for oil and gas will have a negative effect on the Company’s financial position.
Government Regulation
Management is not aware of any non-compliance by the Company of applicable regulatory requirements that would have a material adverse effect on the Company’s financial condition or results of operations.
Competition
The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and personnel substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.
We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. We are unable to predict when, or if, such shortages may again occur or how they would affect our development and exploitation program.
Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete satisfactorily. Many large oil companies have been actively marketing some of their existing producing properties for sale to independent producers. We regularly evaluate acquisition opportunities and submit bids as part of our growth strategy.
Available Information
The Company maintains an internet website at www.newconceptenergy.com. The Company has available through the website, free of charge, Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, reports filed pursuant to Section 16 of the Securities Exchange Act of 1934 (the “Exchange Act”) and amendments to those reports as soon as rea-sonably practicable after we electronically file or furnish such materials to the Securities and Exchange Commission. In addition, the Company has posted the charters for our Audit Committee, Compensation Committee and Governance and Nominating Committee, as well as our Code of Business Conduct and Ethics, Corporate Governance Guidelines on Director Independence and other information on the website. These charters and principles are not incorporated in this Report by reference. The Company will also provide a copy of these documents free of charge to stockholders upon request. The Company issues Annual Reports containing audited financial statements to its common stockholders.
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Risks Related to the Company
During 2020, a strain of coronavirus (“COVID – 19”) was reported worldwide, resulting in decreased economic activity and concerns about the pandemic, which would adversely affect the broader global economy. At this point, the extent to which COVID – 19 may impact the global economy and our business is uncertain, but pandemics or other significant public health events could have a material adverse effect on our business and results of operations.
An investment in our securities involves various risks. An investor should carefully consider the following risk factors in conjunction with the other information in this report before trading our securities.
The oil & gas industry is highly competitive. Competition for leasehold interests, subcontractors and qualified employees are keen and we are competing against companies that are larger, more experienced and better capitalized than we are.
The oil & gas industry faces exposure from changes in oil and gas prices due to market fluctuations beyond the Company’s control.
Our governing documents contain anti-takeover provisions that may make it more difficult for a third party to acquire control of us. Our Articles of Incorporation contain provisions designed to discourage attempts to acquire control of the Company by a merger, tender offer, proxy contest or removal of incumbent management without the approval of our Board of Directors. As a result, a transaction which otherwise might appear to be in your best interests as a stockholder could be delayed, deferred or prevented altogether, and you may be deprived of an opportunity to receive a premium for your shares over prevailing market rates. The provisions contained in our Articles of Incorporation include:
| ● | the requirement of an 80% vote to make, adopt, alter, amend, change or repeal our Bylaws or certain key provisions of the Articles of Incorporation that embody, among other things, the anti-takeover provisions; |
| ● | the so-called business combination “control act” requirements involving the Company and a person that beneficially owns 10% or more of the outstanding common stock except under certain circumstances; and |
| ● | the requirement of holders of at least 80% of the outstanding Common Stock to join together to request a special meeting of stockholders. |
Item 1B. Unresolved Staff Comments
Not applicable.
The Company’s principal offices are located at 1603 LBJ Freeway Suite 800, Dallas, Texas 75234. The Company believes this space is presently suitable, fully utilized and will be adequate for the foreseeable future.
Oil and Gas
Reserve Estimation
The Company’s producing properties have been in production for over 20 years. Because individual well production volumes were not available, composite production decline curves were constructed for each of the five counties in which these wells are located. All five composite decline curves exhibit well-established production decline trends. After reviewing all available information, it was determined that the most reliable method of estimating the Proved Developed Producing Reserves was by extrapolation of the existing production decline trends to the economic limit of production.
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The Company’s reserve reports are prepared by independent petroleum engineers. The process used to control the information provided to the independent petroleum engineers includes an initial compilation of production data by experienced senior management personal in the Company’s field office. This data is independently reviewed by appropriate personal in the Company’s corporate office prior to being submitted to the independent petroleum engineer. The submitted data is ultimately compared to the final reserve report and then agreed to the financial statement disclosures prepared by the Company.
The Company uses the petroleum engineering firm of Lee Keeling and Associates, Inc. to prepare its reserve estimates and future net revenues from its oil and gas properties. The work is performed by a registered professional engineer who is a member of the Society of Petroleum Engineers.
According to our independent reserve engineering firm, Lee Keeling & Associates, Inc. as of December 31, 2019, our Proved Reserves in Ohio and West Virginia were approximately 354,000 Mcf of natural gas and 29,105 Bbls of oil. As of December 31, 2019, the related PV-10 of our total Reserves was approximately $1 million from Ohio & West Virginia.
Additional Oil and Gas Information
Production
| 2019 – 129,000 Mcf of natural gas and 4,000 Bbls of oil | |
| 2018 – 130, 000 Mcf of natural gas and 4, 200 Bbls of oil | |
| 2017 – 178, 000 Mcf of natural gas and 5, 100 Bbls of oil |
Average sales price per unit
| 2019 - $2.79 per Mcf and $52.89 per Bbls | |
| 2018 - $2.91 per Mcf and $61.46 per Bbls | |
| 2017 - $3.81 per Mcf and $46.96 per Bbls |
Productive wells
| 2019 – 153 | |
| 2018 – 153 | |
| 2017 – 153 |
Developed acreage – approximately 20,000 acres
Drilling activity – The Company acquired the operations in Ohio and West Virginia in October 2008 and has, for the most part, focused on improving production from wells. Since the acquisition the Company has drilled 15 wells.
Development plan
In September 2008, the Company through its acquisition of Carl E. Smith, Inc. (now known as Mountaineer State Energy, Inc.) acquired 20,000 acres of mineral rights in Ohio and West Virginia. The 20,000 acres are both surrounded and interspersed of hundreds of existing wells of which 138 producing wells were owned by the Company and other non-related entities owned the rest of such wells. The entire area has pipelines in place and decades of information regarding reserves.
In connection with the acquisition, the Company formulated a development plan to rework existing wells, to improve production using modern technology, and to follow up with the drilling of new wells. The Company’s plan is to use the current knowledge of the area and new technologies available to rework its existing wells.
The decision as to whether to rework existing wells is based upon a number of factors including available financing and the market price for both oil and gas. During the last several years the Company has suspended expansion activity for its existing acreage until the price for both oil and gas stabilizes.
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Oil & Gas Reserves
The following table presents our estimated Oil & Gas Reserves as of December 31, 2019. These estimates correspond with the method used in presenting the “Supplemental Information on Oil and Gas Operations” in Note L to our consolidated financial statements included in this report.
| Gas | Oil | |||||||
| (MMCF) | (MBBLS) | |||||||
| Oil & Gas Reserves | ||||||||
| U.S. Onshore | ||||||||
| Proved Producing | 353 | 29 | ||||||
| Proved Non Producing | 1 | — | ||||||
| Total Oil & Gas Reserves | 354 | 29 | ||||||
Well Statistics
The following table sets forth our wells (all natural gas) as of December 31, 2019.
| Wells | ||||||||
| Gross (1) | Net (2) | |||||||
| U.S. Onshore | ||||||||
| Producing | 153 | 148 | ||||||
| Non-Producing | 44 | 44 | ||||||
| Total wells | 197 | 192 | ||||||
(1) Gross wells are the sum of all wells in which we own an interest.
(2) Net wells are gross wells multiplied by our fractional working interests on the well.
Acreage Statistics
The following table sets forth our developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2019.
| Acres | ||||||||
| Gross (1) | Net (2) | |||||||
| U. S Onshore | ||||||||
| Developed | 19,375 | 19,375 | ||||||
| Undeveloped | — | — | ||||||
| Total Acreage | 19,375 | 19,375 | ||||||
(1) Gross acres are the sum of all acres in which we own an interest.
(2) Net acres are gross acres multiplied by our fractional working interests on the acreage.
(3) Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves are as likely as not to be recovered.
(4) Possible reserves are those additional reserves that are less certain to be recovered than probable reserves
The Company has been named as a defendant in lawsuits in the ordinary course of business. Management is of the opinion that these lawsuits will not have a material effect on the financial condition, results of operations or cash flows of the Company.
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Item 4. Mine Safety Disclosures
Not Applicable
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
The common stock of the Company is listed and traded on the NYSE American using the symbol “GBR”. The following table sets forth the high and low sales prices as reported in the reporting system of the NYSE American and other published financial sources
| 2019 | 2018 | |||||||||||||||
| High | Low | High | Low | |||||||||||||
| First Quarter | $ | 2.24 | $ | 1.50 | $ | 2.45 | $ | 1.26 | ||||||||
| Second Quarter | $ | 2.39 | $ | 1.66 | $ | 4.75 | $ | 1.23 | ||||||||
| Third Quarter | $ | 1.88 | $ | 1.41 | $ | 6.25 | $ | 1.91 | ||||||||
| Fourth Quarter | $ | 1.47 | $ | 1.20 | $ | 2.96 | $ | 1.36 | ||||||||
On March 25, 2020 the closing price of the Company’s Common Stock was $0.64 per share. According to the Transfer Agent’s records, at February 17, 2019 the Company’s Common Stock was held by approximately 2,545 holders of record.
Dividends
The Company paid no dividends on its Common Stock in 2019 or 2018. The Company has not paid cash dividends on its Common stock during at least the last ten fiscal years and it has been the policy of the Board of Directors of the Company to retain all earnings to pay down debt and finance future expansion and development of its businesses. The payment of dividends, if any, will be determined by the Board of Directors in the future in light of conditions then existing, including the Company’s financial condition and requirements, future prospects, restrictions in financing agreements, business conditions and other factors deemed relevant by the Board of Directors.
Purchases of Equity Securities
The Board of Directors has not authorized the repurchase of any shares of its Common Stock under any share repurchase program, except when stockholders owning less than one round lot (100 shares) so request, the Company will purchase shares at market closing on the last trading day prior to receipt of the certificate(s). The Company repurchased no shares during 2018.
Item 6. Selected Financial Data
The selected consolidated financial data presented below are derived from the Company’s audited financial statements.
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| Year Ended December 31, | ||||||||||||
| 2019 | 2018 | 2017 | ||||||||||
| (amounts in thousands, except per share data) | ||||||||||||
| Operating Revenue | $ | 590 | $ | 682 | $ | 791 | ||||||
| Operating expenses | 3,383 | 1,197 | 4,061 | |||||||||
| Operating Profit (loss) | (2,793 | ) | (515 | ) | (3,270 | ) | ||||||
| Earnings (loss) from continuing operations | (2,352 | ) | (484 | ) | (3,241 | ) | ||||||
| Earnings (loss) from discontinued operations | — | — | (5 | ) | ||||||||
| NET EARNINGS (LOSS) | $ | (2,352 | ) | $ | (484 | ) | $ | (3,246 | ) | |||
| Net earnings per share | $ | (0.46 | ) | $ | (0.21 | ) | $ | (1.59 | ) | |||
| Basic weighted average common share | 5,132 | 2,358 | 2,037 | |||||||||
| Balance Sheet Data | ||||||||||||
| Total Assets | $ | 5,790 | $ | 7,882 | $ | 4,205 | ||||||
| Long-term debt | 177 | 201 | 248 | |||||||||
| Asset Retirement obligation | 2,770 | 2,770 | 2,770 | |||||||||
| Total liabilities | 3,381 | 3,121 | 3,569 | |||||||||
| Total stockholders equity | $ | 2,409 | $ | 4,761 | $ | 636 | ||||||
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation
Overview
The Company, through its wholly owned subsidiaries Mountaineer State Energy, Inc. and Mountaineer State Operations, LLC, owns and operates oil and gas wells and mineral leases in Athens and Meigs Counties in Ohio and in Calhoun, Jackson and Roane Counties in West Virginia. The majority of our oil & gas operation was acquired through the acquisition of the Carl E. Smith Companies in 2008.
As of December 31, 2019 the Company has 153 producing gas wells, 44 non-producing wells and related equipment and mineral leases covering approximately 20,000 acres.
Critical Accounting Policies and Estimates
The Company’s discussion and analysis of its financial condition and results of operations are based upon the Company’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Certain of the Company’s accounting policies require the application of judgment in selecting the appropriate assumptions for calculating financial estimates. By their nature, these judgments are subject to an inherent degree of uncertainty. These judgments and estimates are based upon the Company’s historical experience, current trends and information available from other sources that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.
The Company believes the following critical accounting policies are more significant to the judgments and estimates used in the preparation of its consolidated financial statements. Revisions in such estimates are recorded in the period in which the facts that give rise to the revisions become known.
Oil and Gas Property Accounting
The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas properties (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred.
The full cost method requires the Company to calculate quarterly, by cost center, a “ceiling,” or limitation on the amount of properties that can be capitalized on the balance sheet. To the extent capitalized costs of oil and natural gas properties, less accumulated depletion and related deferred taxes exceed the sum of the discounted future net revenues of proved oil and natural gas reserves, the lower of cost or estimated fair value of unproved properties subject to amortization, the cost of properties not
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being amortized, and the related tax amounts, such excess capitalized costs are charged to expense. Beginning December 31, 2009, full cost companies use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date to calculate the future net revenues of reserves.
The Company assesses any unproved oil and gas properties on an annual basis for possible impairment or reduction in value. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment of unproved properties not subject to amortization, the associated costs incurred to date for such properties are then included in unproved properties subject to amortization.
Oil and Gas Reserves
Our oil and gas reserves are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof, including evaluations and extrapolations of well flow rates and reservoir pressure. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because reserves are required to be estimated using prices at the date of the evaluation, estimated reserve quantities can be significantly impacted by changes in product prices.
Depreciation, depletion and amortization (“DD&A”) of producing properties is computed on the unit-of-production method based on estimated oil and gas reserves. While total DD&A expense for the life of a property is limited to the property’s total cost, reserve revisions result in a change in timing of when DD&A expense is recognized. Downward revisions of reserves result in an acceleration of DD&A expense, while upward revisions tend to lower the rate of DD&A expense recognition.
The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include using average annual oil and gas prices and year-end costs for estimated future development and production expenditures. Discounted future net cash flows are calculated using a 10% rate. Changes in any of these assumptions could have a significant impact on the standardized measure. Accordingly, the standardized measure does not represent management’s estimated current market value of reserves.
The Company’s allowance for doubtful accounts receivable and notes receivable is based on an analysis of the risk of loss on specific accounts. The analysis places particular emphasis on past due accounts. Management considers such information as the nature and age of the receivable, the payment history, customer or other debtor and the financial condition of the debtor. Management’s estimate of the required allowance, which is reviewed on a quarterly basis, is subject to revision as these factors change.
Deferred Tax Assets
Significant management judgment is required in determining the provision for income taxes, deferred tax assets and liabilities and any valuation allowance recorded against net deferred tax assets. The future recoverability of the Company’s net deferred tax assets is dependent upon the generation of future taxable income prior to the expiration of the loss carry forwards. At December 31, 2019, the Company had a deferred tax asset due to tax deductions available to it in future years. However, as management could not determine that it was more likely than not that the benefit of the deferred tax asset would be realized, a 100% valuation allowance was established.
Liquidity and Capital Resources
At December 31, 2019, the Company had current assets of $4,141,000 (largely due to the sale of 3,000,000 shares of common stock on December 4, 2018 and current liabilities of $434,000.
Cash and cash equivalents totaled $22,000 at December 31, 2019 and $361,000 at December 31, 2018. New Concept’s principal sources of cash are, sales of oil and gas, interest and proceeds from sales of assets
Net cash provided (used) by continuing operating activities was $369,000, in 2019, ($637,000) in 2018 and $202,000 in 2017.
Net cash provided (used) in investing activities was ($664,000) in 2019, ($3,960,000) in 2018 and $14,000 in 2017.
Net cash provided (used) in financing activities was ($44,000) 2019, $4,539,000 in 2018 and $90,000 in 2017.
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Results of Operations
Fiscal 2019 as compared to 2018
Revenues: Total revenues from the oil & gas operation was $590,000 in 2019 and $682,000 in 2018. The decrease was due to the rate the Company received for the sale of its natural gas during 2019.
Operating Expenses: Operating expenses for continuing oil & gas operations was $686,000 in 2019 and $844,000 in 2018. This decrease was principally due to a reduction of depreciation and depletion expense of $166,000.
In 2019 pursuant to the requirements of the “full cost ceiling test” for oil & gas companies we recorded a non-cash charge to operations of $ $2.3 million to write down its investment in West Virginia. In September 2019 the Company unsuccessfully drilled a well which resulted in dry hole. As the well did not prove up the estimated probable and possible reserves, the Company had to deem the applicable reserve estimates as impaired. In the third quarter the company booked an impairment expense of $2,285,000 which represents a reduction of both the estimated probable and possible reserves as well as the cost of drilling the failed well. This charge to earnings was caused by a revaluation of the Company’s non- producing oil and gas reserves.
Corporate Expenses were $412,000 in 2019 and $353,000 in 2018. The increase was principally due to an increase in consulting expenses.
Interest Income: Interest Income was $237,000 in 2019 as compared to $37,000 in 2018. The increase was due to the interest earned from investing the proceeds from the issuance and sale of common stock in December 2018.
Fiscal 2018 as compared to 2017
Revenues: Total revenues from the oil & gas operation was $682,000 in 2018 and $791,000 in 2017. The decrease was due to the rate the Company received for the sale of its natural gas during 2018.
Operating Expenses: Operating expenses for continuing oil & gas operations was $844,000 in 2018 and $1,027, 000 in 2017. This decrease was principally due to a reduction of depreciation and depletion expense of $73,000. The remaining decrease was the result of an overall reduction in operating expenses.
In 2017 pursuant to the requirements of the “full cost ceiling test” for oil & gas companies we recorded a non-cash charge to operations of $ $2.6 million to write down its investment in Ohio and West Virginia. This charge to earnings was caused by a revaluation of the Company’s non- producing oil and gas reserves.
Corporate Expenses were $353,000 in 2018 and $408,000 in 2017. The decrease was principally due to a reduction in payroll expenses.
Interest Expense: Interest Expense was $18,000 in 2018 as compared to $24,000 in 2017. The decrease was due to a reduction in the long term debt.
Other Income & (Expense): Other income & (expense) was $28,000 for 2017 as compared to ($110,000) in 2016. In 2017 the most significant item was the receipt of $64,000 for a receivable the Company had previously written off. .The expenses in 2016 were principally the write off assets pertaining to the termination of the lease at the retirement center.
Item 7a: Quantitative and Qualitative Disclosures about Market Risk
All of the Company’s debt is financed at fixed rates of interest. Therefore, the Company has minimal risk from exposure to changes in interest rates.
The consolidated financial statements required by this Item begin at page 24 of this Report.
Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
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Evaluation of Disclosure Controls and Procedures
Based on an evaluation by our management (with the participation of our Principal Executive Officer and Principal Financial Officer), as of the end of the period covered by this report, our Principal Executive Officer and Principal Financial Officer concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) were effective to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and that such information is accumulated and communicated to our management, including our Principal Executive Officer and Principal Financial Officer, to allow timely decisions regarding required disclosures.
There has been no change in our internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)) during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. There are inherent limitations to the effectiveness of any system of internal control over financial reporting. These limitations include the possibility of human error, the circumvention of overriding of the system and reasonable resource constraints. Because of its inherent limitations, our internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting. In making this assessment, management used the criteria set forth in Internal Control - Integrated Framework -2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on management’s assessments and those criteria, management has concluded that Company’s internal control over financial reporting was effective as of December 31, 2019.
This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial report. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.
Changes in Internal Control over Financial Reporting
In preparation for management’s report on internal control over financial reporting, we documented and tested the design and operating effectiveness of our internal control over financial reporting. There were no changes in our internal controls over financial reporting (as such term is defined in Exchange Act Rule 13a-15(f)) that occurred during the quarter ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Not applicable.
Item 10. Directors, Executive Officers and Corporate Governance
Directors
The affairs of the Company are managed by the Board of Directors. The directors are elected at the Annual Meeting of Stockholders or appointed by the incumbent Board and serve until the next Annual Meeting of Stockholders, until a successor has been elected or approved, or until earlier resignation, removal or death.
It is the Board’s objective that a majority of the Board consists of independent directors. For a director to be considered “independent”, the Board must determine that the director does not have any direct or indirect material relationship with the Company. The Board has established guidelines to assist it in determining director independence, which conform to, or are more
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exacting than, the independence requirements in the NYSE American Stock Exchange listing rules. The independence guidelines are set forth in the Company’s “Corporate Governance Guidelines”. The text of this document has been posted on the Company’s internet website at http://www.newconceptenergy.com, and is available in print to any stockholder who requests it. In addition to applying these guidelines, the Board will consider all relevant facts and circumstances in making an independent determination.
The Company has adopted a code of conduct that applies to all directors, officers and employees, including our principal executive officer, principal financial officer and principal accounting officer. Stockholders may find our Code of Conduct on our internet website address at http://www.newconceptenergy.com. We will post any amendments to the Code of Conduct as well as any waivers that are required to be disclosed by the rules of the SEC or the NYSE AMERICAN on our website.
Our Board of Directors has adopted charters for our Audit, Compensation and Governance and Nominating Committees of the Board of Directors. Stockholders may find these documents on our website by going to the website address http://www.newconceptenergy.com. Stockholders may also obtain a printed copy of the materials referred to by contacting us at the following address:
New Concept Energy, Inc.
Attn: Investor Relations
1603 LBJ Freeway, Suite 750
Dallas, Texas 75234
972-407-8400 (Telephone)
The Audit Committee of the Board of Directors is an “audit committee” for the purposes of Section 3(a) (58) of the Exchange Act. The members of that Committee are Dan Locklear (Chairman), Raymond D. Roberts, Cecilia Maynard and Victor L. Lund. Mr. Locklear is qualified as an “audit committee financial expert” within the meaning of SEC regulations and the Board has determined that he has the accounting and related financial management expertise within the meaning of the listing standards of the NYSE American. All of the members of the Audit Committee meet the independence and experience requirements of the listing standards of the NYSE American.
All members of the Audit Committee, Compensation Committee and the Governance and Nominating Committee must be independent directors. Members of the Audit Committee must also satisfy additional independence requirements which provide (i) that they may not accept, directly or indirectly, any consulting, advisory or compensatory fee from the Company or any of its subsidiaries other than their director’s compensation (other than in their capacity as a member of the Audit Committee, the Board of Directors or any other Committee of the Board), and (ii) no member of the Audit Committee may be an “affiliated person” of the Company or any of its subsidiaries, as defined by the Securities and Exchange Commission.
The current directors of the Company are listed below, together with their ages, terms of service, all positions and offices with the Company, their principal occupations, business experience and directorships with other companies during the last five years or more. The designation “affiliated”, when used below with respect to a director, means that the director is an officer or employee of the Company or one of its subsidiaries. The designation “independent”, when used below with respect to a director, means that the director is neither an officer of the Company nor a director, officer or employee of a subsidiary of the Company, although the Company may have certain business or professional relationships with the director as discussed in Item 13. Certain Relationships and Related Transactions. No family relationship exists between any executive officer and any of the directors of the company.
Raymond D. Roberts, age 88, (Independent) Director since June 2015
Mr. Roberts is recently retired. For more than the past five years, he has been Director of Aviation of Stellar Aviation, Inc., a privately held Nevada Corporation, engaged in the business of aircraft (Boeing 737) and logistical management. Mr. Roberts is also a director of American Realty Investors, Inc. (“ARL”), Transcontinental Realty Investors, Inc. (“TCI”) and Income Opportunity Realty Investors, Inc. (IOR”) ARL and TCI common stock are listed and traded on the New York Stock Exchange and IOR common stock is listed and traded on the NYSE American Exchange. Mr. Roberts was also elected as a member of the Governance and Nominating Committee of the Board of Directors of the Registrant.
Gene S. Bertcher, age 72, (Affiliated) Director November 1989 to September 1996 and since June 1999
Mr. Bertcher was elected President and Chief Financial Officer effective November 1, 2004. He was elected Chairman and Chief Executive Officer in December 2006. Mr. Bertcher has been Chief Financial Officer and Treasurer of the Company since November 1989 and Executive Vice President from November 1989 until he was elected President. Also, Mr. Bertcher is Executive Vice-President and Chief Financial Officer of American Realty Investors, Inc. and Transcontinental Realty Investors, Inc., both of which are traded on the NYSE. In addition Mr. Bertcher is Executive Vice-President and Chief Financial Officer Income Opportunity Realty Investors, Inc. which is traded on the NYSE American exchange, positions he has occupied since February 2008. He has been a certified public accountant since 1973.
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Dan Locklear, age 67, (Independent) Director since December 2003
Mr. Locklear has been Chief Financial Officer of Sunridge Management Group, a real estate management company, for more than five years. Mr. Locklear was formerly employed by Johnstown Management Company, Inc. and Trammel Crow Company. Mr. Locklear has been a certified public accountant since 1981 and a licensed real estate broker in the State of Texas since 1978.
Victor L. Lund, age 90, (Independent) Director since March 1996
Mr. Lund founded Wedgwood Retirement Inns, Inc. (“Wedgwood”) in 1977, which became a wholly owned subsidiary of the Company in 1996. For most of Wedgwood’s existence, Mr. Lund was Chairman of the Board, President and Chief Executive Officer, positions he held until Wedgwood was acquired by the Company.
Cecilia Maynard, age 68, Director since January 2019
Ms. Maynard was employed by Pillar Income Asset Management, Inc. (“Pillar”) from January 2011 through December 31, 2018. Pillar is a Nevada corporation which provides management services to other entities. Ms. Maynard has also (since May 31, 2018) been a director, Vice President and Secretary of First Equity Properties, Inc., a Nevada corporation, the common stock of which is registered under Section 12(g) of the Securities Exchange Act of 1934.
Board Committees
The Board of Directors held six meetings during 2019. For such year, no incumbent director attended fewer than 75% of the aggregate of (i) the total number of meetings held by the Board during the period for which he or she had been a director, and (ii) the total number of meetings held by all Committees of the Board on which he or she served during the period that he or she served.
The Board of Directors has standing Audit, Compensation and Governance and Nominating Committees. The Audit Committee was formed on December 12, 2003, and its function is to review the Company’s operating and accounting procedures. A Charter of the Audit Committee has been adopted by the Board. The current members of the Audit Committee, all of whom are independent within the SEC regulations, the listing standards of the NYSE American and the Company’s Corporate Governance Guidelines are Messrs. Locklear (Chairman), Roberts and Lund. Mr. Dan Locklear is qualified as an Audit Committee financial expert within the meaning of SEC regulations, and the Board has determined that he has the accounting and related financial management expertise within the meaning of the listing standards of the NYSE American. The Audit Committee met four times in 2019.
The Governance and Nominating Committee is responsible for developing and implementing policies and practices relating to the corporate governance, including reviewing and monitoring implementation of the Company’s Corporate Governance Guidelines. In addition, the Committee develops and reviews background information on candidates for the Board and makes recommendations to the Board regarding such candidates. The Committee also prepares and supervises the Board’s annual review of director independence and the Board’s performance and self-evaluation. The Charter of the Governance and Nominating Committee was adopted on October 20, 2004. The members of the Committee are Messrs. Lund (Chairman), Roberts and Ms. Maynard. The Governance and Nominating Committee met twice in 2019.
The Board has also formed a Compensation Committee of the Board of Directors, adopted a Charter for the Compensation Committee on October 20, 2004, and selected Mr. Roberts (Chairman) and Messrs. Locklear and Ms. Maynard as members of that Committee. The Compensation Committee met twice in 2019.
The members of the Board of Directors at the date of this Report and the Committees of the Board on which they serve are identified below:
| Director | Audit Committee | Governance and Nominating Committee | Compensation Committee |
| Raymond D Roberts | P | P | Chairman |
| Gene S. Bertcher | |||
| Cecilia Maynard | P | P | |
| Dan Locklear | Chairman | P | P |
| Victor L. Lund | P | Chairman |
Executive Officers
The following person currently serves as the sole executive officer of the Company: Gene S. Bertcher, Chairman of the Board, President, Chief Executive Officer and Treasurer. His position with the Company is not subject to a vote of stockholders. His age, term of service and all positions and offices with the Company, other principal occupations, business experience and
| 15 |
directorships with other companies during the last five years or more are listed under the caption “Directors” above.
In addition to the foregoing officers, the Company has other officers not listed herein who are not considered executive officers.
Code of Ethics
The Board of Directors has adopted a code of ethics entitled “Code of Business Conduct and Ethics” that applies to all directors, officers and employees of the Company and its subsidiaries. In addition, the Company has adopted a code of ethics entitled “Code of Ethics for Senior Financial Officers” that applies to the principal executive officer, president, principal financial officer, chief financial officer, principal accounting officer and controller. The text of these documents is posted on the Company’s internet website address at http://www.newconceptenergy.com and is available in print to any stockholder who requests them.
Section 16(a) Beneficial Ownership Reporting Compliance
Based solely upon a review of Forms 3, 4 and 5 furnished to the Company pursuant to Rule 16a-3(e) promulgated under the Securities Exchange Act of 1934 (the “Exchange Act“), upon written representations received by the Company, the Company is not aware of any failure by any director, officer or beneficial owner of more than 10% of the Company’s common stock to file with the Securities and Exchange Commission on a timely basis.
Item 11. Executive Compensation
The following tables set forth the compensation in all categories paid by the Company for services rendered during the fiscal years ended December 31, 2019, 2018 and 2017 by the Chief Executive Officer of the Company and to the other executive officers and Directors of the Company whose total annual salary in 2018 exceeded $50,000.
| SUMMARY COMPENSATION TABLE | ||||||||||||||||||||||||||||||||||||
| Change in | ||||||||||||||||||||||||||||||||||||
| Non- | Pension | |||||||||||||||||||||||||||||||||||
| Equity | Value and | |||||||||||||||||||||||||||||||||||
| Name | Incentive | Nonqualified | All | |||||||||||||||||||||||||||||||||
| and | Plan | Deferred | Other | |||||||||||||||||||||||||||||||||
| Principal | Stock | Option | Compen- | Compensation | Compen- | |||||||||||||||||||||||||||||||
| Position | Year | Salary | Bonus | Awards | Awards | sation | Earnings | sation | Total | |||||||||||||||||||||||||||
Gene S. Bertcher (1) Chairman, President & Chief Financial Officer | 2019 2018 2017 | $ $ $ | 56,500 56,500 53,650 | $ $ $ | 56,500 56,500 53,650 | |||||||||||||||||||||||||||||||
| (1) | The salary in the above table represents Mr. Bertcher’s compensation paid by the Company; he also receives additional compensation for services to three other publicly traded entities which are unrelated to the Company. |
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GRANTS OF PLAN-BASED AWARDS
None
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
None
OPTION EXERCISES AND STOCK VESTED
None
PENSION BENEFITS
None
NONQUALIFIED DEFERRED COMPENSATION
None
| 17 |
| DIRECTOR COMPENSATION | ||||||||||||||||||
| Name | Fees Earned Or Paid in Cash | Stock Awards | Option Awards | Non-Equity Incentive Plan Compensation | Change in Pension Value and Nonqualified Deferred Compensation Earnings | All Other Compensation | Total | |||||||||||
| Gene S. Bertcher | $ | — | $ | — | ||||||||||||||
| Raymond D Roberts | $ | 10,500 | $ | 10,500 | ||||||||||||||
| Dan Locklear | $ | 10,500 | $ | 10,500 | ||||||||||||||
| Victor L. Lund | $ | 10,500 | $ | 10,500 | ||||||||||||||
| Cecilia Maynard | $ | 10,500 | $ | 10,500 | ||||||||||||||
MANAGEMENT AND CERTAIN SECURITY HOLDERS
None
Compensation of Directors
The Company pays each non-employee director a fee of $2,500 per year, plus a meeting fee of $2,000 for each board meeting attended. Employee directors serve without compensation.
Item 12. Security Ownership of Certain Beneficial Owners
The following table sets forth the ownership of the Company’s Common Stock, both beneficially and of record, both individually and in the aggregate, for those persons or entities known by the Company to be the beneficial owners of more than 5% of its outstanding Common Stock as of the close of business on March 25, 2020.
|
Name and Address of Beneficial Owner |
Amount and Nature of Beneficial Ownership |
Approximate Percent of Class * |
|
Realty Advisors, Inc. |
3,060,000 shares |
59.63% |
| · | based on 5,131,934 shares outstanding at March 25, 2020. |
Security Ownership of Management
The following table sets forth the ownership of the Company’s Common Stock, both beneficially and of record, both individually and in the aggregate for the directors and executive officers of the Company, as of the close of business on March 25, 2020.
|
Name and Address of Beneficial Owner |
Amount and Nature of Beneficial Ownership* |
Approximate Percent of Class** |
|
Gene S. Bertcher |
- |
0% |
|
Raymond Roberts |
- |
0% |
|
Dan Locklear |
- |
0% |
|
Victor L. Lund |
- |
0% |
|
Cecilia Maynard |
- |
0%
|
|
All directors and executive officers as a group (5 people)
|
- |
0%
|
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|
* Beneficial Ownership means the sole or shared power to vote, or to direct the voting of, a security or investment power with respect to a security, or any combination thereof.
** Percentages are based upon 5,131, 934 shares of Common Stock outstanding at March 25, 2020. |
Item 13. Certain Relationships and Related Transactions, and Director Independence
Beginning in 2011 Pillar became the contractual advisor to three other publically traded entities which are related to Realty Advisors, Inc. (“RAI”) through stock ownership by RAI. In addition the relationship with Mr. Bertcher New Concept conducts business with Pillar whereby Pillar provided the Company with services including processing payroll, acquiring insurance and other administrative matters. The Company believes that by purchasing these services through certain large entities it can get lower costs and better service. Pillar does not charge the Company a fee for providing these services. Pillar is a wholly owned subsidiary of Realty Advisors, Inc.
Except as set forth above, the Reporting Persons do not have any contracts, arrangements, understandings or relationships, legal or otherwise, with any person with respect to any securities of the Issuer, including but not limited to, transfer or voting of any of the securities, finders’ fees, joint ventures, loan or option arrangements, puts or calls, guarantees of profits, divisions of profits or losses, or the giving or withholding of proxies.
It is the policy of the Company that all transactions between the Company and any officer or director, or any of their affiliates, must be approved by independent members of the Board of Directors of the Company. All of the transactions described above were so approved.
See Item 10. Directors, Executive Officers and Corporate Governance for information on the independence of Directors and the standards of the NYSE American Exchange.
Item 14. Principal Accounting Fees and Services
The following table sets forth the aggregate fees for professional services rendered to the Company for the years 2018 and 2017 by the Company’s principal accounting firm Swalm & Associates, P.C.:
| Type of Fees | 2019 | 2018 | ||||||
| Audit Fees | $ | 69,000 | $ | 67,000 | ||||
| Tax Fees | 9,000 | 12,000 | ||||||
| Total Fees | $ | 78,000 | $ | 79,000 | ||||
All services rendered by the principal auditors are permissible under applicable laws and regulations and were pre-approved by either of the Board of Directors or the Audit Committee, as required by law. The fees paid to principal auditors for services described in the above table fall under the categories listed below:
Audit Fees: These are fees for professional services performed by the principal auditor for the audit of the Company’s annual financial statements and review of financial statements included in the Company’s Form 10-Q filings and services that are normally provided in connection with statutory and regulatory filings or engagements.
Audit-Related Fees: These are fees for assurance and related services performed by the principal auditor that are reasonably related to the performance of the audit or review of the Company’s financial statements. These services include attestation by the principal auditor that is not required by statute or regulation and consulting on financial accounting/reporting standards.
Tax Fees: These are fees for professional services performed by the principal auditor with respect to tax compliance, tax planning, tax consultation, returns preparation and reviews of returns. The review of tax returns includes the Company and its consolidated subsidiaries.
All Other Fees: These are fees for other permissible work performed by the principal auditor that does not meet the above category descriptions.
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These services are actively monitored (as to both spending level and work content) by the Audit Committee to maintain the appropriate objectivity and independence in the principal auditor’s core work, which is the audit of the Company’s consolidated financial statements.
Financial Information Systems Design and Implementation Fees
Swalm & Associates, P.C. did not render professional services to the Company in 2019 with respect to financial information systems design and implementation.
Under the Sarbanes-Oxley Act of 2002 (the “SO Act”), and the rules of the Securities and Exchange Commission (the “SEC”), the Audit Committee of the Board of Directors is responsible for the appointment, compensation and oversight of the work of the independent auditor. The purpose of the provisions of the SO Act and the SEC rules for the Audit Committee’s role in retaining the independent auditor is two-fold. First, the authority and responsibility for the appointment, compensation and oversight of the auditors should be with directors who are independent of management. Second, any non-audit work performed by the auditors should be reviewed and approved by these same independent directors to ensure that any non-audit services performed by the auditor do not impair the independence of the independent auditor. To implement the provisions of the SO Act, the SEC issued rules specifying the types of services that an independent auditor may not provide to its audit client, and governing the Audit Committee’s administration of the engagement of the independent auditor. As part of this responsibility, the Audit Committee is required to pre-approve the audit and non-audit services performed by the independent auditor in order to assure that they do not impair the auditor’s independence. Accordingly, the Audit Committee has adopted a pre-approval policy of audit and non-audit services (the “Policy”), which sets forth the procedures and conditions pursuant to which services to be performed by the independent auditor are to be pre-approved. Consistent with the SEC rules establishing two different approaches to pre-approving non-prohibited services, the Policy of the Audit Committee covers pre-approval of audit services, audit-related services, international administration tax services, non-U.S. income tax compliance services, pension and benefit plan consulting and compliance services, and U.S. tax compliance and planning. At the beginning of each fiscal year, the Audit Committee will evaluate other known potential engagements of the independent auditor, including the scope of work proposed to be performed and the proposed fees, and the approve or reject each service, taking into account whether services are permissible under applicable law and the possible impact of each non-audit service on the independent auditor’s independence from management. Typically, in addition to the generally pre-approved services, other services would include due diligence for an acquisition that may or may not have been known at the beginning of the year. The Audit Committee has also delegated to any member of the Audit Committee designated by the Board or the financial expert member of the Audit Committee responsibilities to pre-approve services to be performed by the independent auditor not exceeding $25,000 in value or cost per engagement of audit and non-audit services, and such authority may only be exercised when the Audit Committee is not in session.
| 20 |
Item 15. Exhibits, Financial Statement and Supplementary Schedules
INDEX TO FINANCIAL STATEMENTS
| Page | ||
| FINANCIAL STATEMENTS | ||
| Report of Swalm & Associates, P.C. | 22 | |
| Consolidated Balance Sheets | 23 | |
| Consolidated Statements of Operations | 25 | |
| Consolidated Statements of Cash Flows | 26 | |
| Consolidated Statements of Changes in Stockholders’ Equity | 27 | |
| Notes to Consolidated Financial Statements | 28 | |
|
FINANCIAL STATEMENT SCHEDULES: Other financial statement schedules have been omitted because they are not required, are not applicable, or the information required is included in the Consolidated Financial Statements or the notes thereto. Optional and not included herein.
| ||
| 21 |
REPORT OF THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the board of directors of
New Concept Energy, Inc.
Dallas, Texas
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of New Concept Energy, Inc. and Subsidiaries as of December 31, 2019 and 2017, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2019, and the related notes collectively referred to as the “financial statements.” In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of New Concept Energy, Inc. as of December 31, 2019 and 2017 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with U.S. generally accepted accounting principles.
Basis of Opinion
These consolidated financial statements are the responsibility of Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting, 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.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Emphasis of Related Party Transactions
As described in the notes to the financial statements, New Concept Energy, Inc. has significant transactions with and balances due to and from related parties.
| /s/ Swalm & Associates, P.C. | |
| Swalm & Associates, P.C. | |
| We have served as the Company’s auditor since 2008. | |
| Richardson, Texas | |
| March 25, 2020 |
| 22 |
| 23 |
| NEW CONCEPT ENERGY, INC. AND SUBSIDIARIES | ||||||||
| CONSOLIDATED BALANCE SHEETS - CONTINUED | ||||||||
| (amounts in thousands, except share amounts) | ||||||||
| December 31, | ||||||||
| 2019 | 2018 | |||||||
| Liabilities and stockholders' equity | ||||||||
| Current liabilities | ||||||||
| Accounts payable - trade (including $180 and $37 in 2019 and 2018 due to related parties) | $ | 355 | $ | 59 | ||||
| Accrued expenses | 35 | 32 | ||||||
| Current portion of long term debt | 44 | 59 | ||||||
| Total current liabilities | 434 | 150 | ||||||
| Long-term debt | ||||||||
| Notes payable less current portion | 177 | 201 | ||||||
| Asset retirement obligation | 2,770 | 2,770 | ||||||
| Total liabilities | 3,381 | 3,121 | ||||||
| Stockholders' equity | ||||||||
| Series B convertible preferred stock, $10 par value, liquidation value | ||||||||
| of $100 authorized 100 shares, issued and outstanding one share | 1 | 1 | ||||||
| Common stock, $.01 par value; authorized, 100,000,000 | ||||||||
| shares; issued and outstanding, 5,131,934 shares | ||||||||
| at December 31, 2019 and 2018 | 51 | 51 | ||||||
| Additional paid-in capital | 63,579 | 63,579 | ||||||
| Accumulated deficit | (61,222 | ) | (58,870 | ) | ||||
| 2,409 | 4,761 | |||||||
| Total liabilities & stockholders' equity | $ | 5,790 | $ | 7,882 | ||||
| The accompanying notes are an integral part of these consolidated financial statements. | ||||||||
| 24 |
| 25 |
| 26 |
| 27 |
New Concept Energy Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2019
NOTE A – BUSINESS DESCRIPTION AND PRESENTATION
The Company, through its wholly owned subsidiaries Mountaineer State Energy, Inc. and Mountaineer State Operations, LLC, operates oil and gas wells and mineral leases in Athens and Meigs Counties in Ohio and in Calhoun, Jackson and Roane Counties in West Virginia. As of December 31, 2019 the Company has 153 producing oil & gas wells, 44 non-producing wells and related equipment and mineral leases covering approximately 20,000 acres.
The Company engaged the firm of independent oil and gas engineers Lee Keeling & Associates, Inc. to estimate the net oil and gas reserves. On the basis of their study, the estimates of future net revenues using a present value discount of 10% were estimated to be $767,000 at December 31, 2019.
The Company’s ability to meet current cash obligations relies on cash received from operations and the collection of notes receivable, including a $4 million dollar receivable from a related party. Further the Company is reviewing its potential opportunities to increase its cash reserves during 2020 including the sale of surplus land and fixed assets as well as issuing additional common stock in a private placement.
NOTE B - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows:
Principles of Consolidation
The consolidated financial statements include the accounts of New Concept Energy, Inc. and its majority-owned subsidiaries (collectively, the “Company”, New Concept or “NCE”) and are prepared on the basis of accounting principles generally accepted in the United States of America “GAAP”. All significant intercompany transactions and accounts have been eliminated. Certain accounting balances have been reclassified to conform to the current year presentation.
Depreciation
Depreciation is provided for in amounts sufficient to relate the cost of property and equipment to operations over their estimated service lives, ranging from 3 to 40 years. Depreciation is computed by the straight-line method.
Depreciation expense, which is included in operations, was $20,000, $43,000 and $55,000 for 2019, 2018 and 2017, respectively.
Depreciation, Depletion and Amortization of Oil & Gas Properties
Depreciation, depletion and amortization (“DD&A”) of producing properties is computed on the unit-of-production method based on estimated oil and gas reserves. While total DD&A expense for the life of a property is limited to the property’s total cost, reserve revisions result in a change in timing of when DD&A expense is recognized.
The Company recorded depletion of mineral rights of $61,000, $204,000 and $259,000 in 2019, 2018 and 2017 respectively.
Segments
The Company operates one primary business segment: oil and gas operations. Segment data is provided in “Note H” to these consolidated financial statements.
Major Purchaser
The Company sells most of its natural gas production to one purchaser and all of its oil production to one purchaser. While there is an available market for crude oil and natural gas production, we cannot be assured that the loss of this purchaser would not have a material impact on the Company.
| 28 |
Oil and Gas Reserves
Our oil and gas reserves are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof, including evaluations and extrapolations of well flow rates and reservoir pressure. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because reserves are required to be estimated using recent prices of the evaluation, estimated reserve quantities can be significantly impacted by changes in product prices.
The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include using recent oil and gas prices and year-end costs for estimated future development and production expenditures. Discounted future net cash flows are calculated using a 10% rate. Changes in any of these assumptions could have a significant impact on the standardized measure. Accordingly, the standardized measure does not represent management’s estimated current market value of reserves.
Full cost accounting
The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas properties (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred.
The full cost method requires the Company to calculate quarterly, by cost center, a “ceiling,” or limitation on the amount of properties that can be capitalized on the balance sheet. To the extent capitalized costs of oil and natural gas properties, less accumulated depletion and related deferred taxes exceed the sum of the discounted future net revenues of proved oil and natural gas reserves, the lower of cost or estimated fair value of unproved properties subject to amortization, the cost of properties not being amortized, and the related tax amounts, such excess capitalized costs are charged to expense. Beginning December 31, 2009, full cost companies use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date to calculate the future net revenues of reserves. Prior to December 31, 2009, companies used the price in effect at the calculation date and had the option, under certain circumstances, to elect to use subsequent commodity prices if they increased after the calculation date.
The Company assesses any unproved oil and gas properties on an annual basis for possible impairment or reduction in value. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of reserves; and the economic viability of development if reserves are assigned. During any period in which these factors indicate an impairment of unproved properties not subject to amortization, the associated costs incurred to date for such properties are then included in unproved properties subject to amortization.
Gas gathering assets
Gas gathering assets are capitalized as part of the depletable pool and ratably charged to earnings along with other capitalized exploration, drilling and development costs.
Office and field equipment
Office and field equipment are capitalized at cost and depreciated on a straight line basis over their estimated useful lives. Office and field equipment useful lives range from 5 to 30 years.
Revenue recognition and gas imbalances
We use the sales method of accounting for oil and natural gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. Gas imbalances at December 31, 2019 were not significant. New Concept also follows the sales method of accounting for natural gas production imbalances and would recognize a liability if the existing reserves were not adequate to cover an imbalance.
Accounting for Leases
Leases of property, plant and equipment where the Company assumes substantially all the benefits and risks of ownership are classified as finance leases. Finance leases are capitalized at the estimated present value of the underlying lease payments. Each lease payment is allocated between the liability and finance charges so as to achieve a constant rate on the finance balance outstanding. The corresponding rental obligations, net of finance charges, are included in other long-term payables. The interest element of the finance charge is charged to the income statement over the lease period. Property, plant and equipment acquired under finance leasing contracts are depreciated over the useful life of the asset.
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Leases of assets under which all the risks and benefits of ownership are effectively retained by the lessor are classified as operating leases. Payments made under operating leases are charged to the income statement on a straight-line basis over the period of the lease. When an operating lease is terminated before the lease period has expired, any payment required to be made to the lessor by way of penalty is recognized as an expense in the period in which termination takes place.
Revenue Recognition
Rental income for residential property leases is recorded when due from residents and is recognized monthly as it is earned, which is not materially different than on a straight-line basis as lease terms are generally for periods of one year or less.
Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. Costs associated with revenues are recorded in cost of revenues. Production volumes of natural gas are sold immediately and transported via pipeline. Royalties on the production of natural gas either paid in cash or settled through the delivery of volumes. The Company includes royalties in its revenues and cost of revenues when settlement of the royalties is paid in cash, while royalties settled by the delivery of volumes are excluded from revenues and cost of revenues.
The Company follows the sales method of accounting for natural gas production imbalances and would recognize a liability if the existing reserves were not adequate to cover an imbalance.
Use of Estimates
In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash Equivalents
The Company considers all short-term deposits and money market investments with a maturity of less than three months to be cash equivalents.
Other Intangible Assets
The cost of acquired patents, trademarks and licenses is capitalized and amortized using the straight-line method over their useful lives. The carrying amount of each intangible asset is reviewed annually and adjusted for permanent impairment where it is considered necessary.
Impairment of Notes Receivable
Notes receivable are identified as impaired when it is probable that interest and principal will not be collected according to the contractual terms of the note agreements. The accrual of interest is discontinued on such notes, and no income is recognized until all past due amounts of principal and interest are recovered in full.
Impairment of Long-Lived Assets
The Company reviews its long-lived assets and certain identifiable intangibles for impairment when events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. In reviewing recoverability, the Company estimates the future cash flows expected to result from use of the assets and eventually disposing of them. If the sum of the expected future cash flows (undiscounted and without interest charges) is less than the carrying amount of the asset, an impairment loss is recognized based on the asset’s fair value.
The Company determines the fair value of assets to be disposed of and records the asset at the lower of fair value less disposal costs or carrying value. Assets are not depreciated while held for disposal.
Sales of Real Estate
Gains on sales of real estate are recognized to the extent permitted by Accounting Standards Codification Topic 360-20, “Real Estate Sales – Real Estate Sales”, (“ASC 360-20”). Until the requirements of ASC 360-20 have been met for full profit recognition, sales are accounted for by the installment or cost recovery method, whichever is appropriate.
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Real Estate Held for Sale
Accounting Standards Codification Topic 360, “Property, Plant, & Equipment” (“ASC 360”)requires that properties held for sale be reported at the lower of carrying amount or fair value less costs of sale. If a reduction in a held for sale property’s carrying amount to fair value less costs of sale is required, a provision for loss is recognized by a charge against earnings. Subsequent revisions, either upward or downward, to a held for sale property’s estimated fair value less costs of sale are recorded as an adjustment to the property’s carrying amount, but not in excess of the property’s carrying amount when originally classified as held for sale. A corresponding charge against or credit to earnings is recognized. Properties held for sale are not depreciated.
Asset Retirement Obligation
The Company records an asset retirement obligation liability on the consolidated balance sheets and capitalizes a portion of the cost in “Oil and natural gas properties” during the period in which the obligation is incurred. The asset retirement obligation is further described in Note K.
Income Taxes
The Company accounts for income taxes in accordance with Accounting Standards Codification, (“ASC”) No. 740, “Accounting for Income Taxes”. ASC 740 requires an asset and liability approach to financial accounting for income taxes. In the event differences between the financial reporting basis and the tax basis of the Company’s assets and liabilities result in deferred tax assets, ASC 740 requires an evaluation of the probability of being able to realize the future benefits indicated by such assets. A valuation allowance is provided for a portion or all of the deferred tax assets when there is an uncertainty regarding the Company’s ability to recognize the benefits of the assets in future years. Recognition of the benefits of deferred tax assets will require the Company to generate future taxable income. There is no assurance that the Company will generate earnings in future years. Since management could not determine the likelihood that the benefit of the deferred tax asset would be realized, no deferred tax asset was recognized by the Company.
Recent Accounting Pronouncements
In December 2019, the FASB issued ASU 2019-12. Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. The amendments in this Update simplify the accounting for income taxes by removing certain exceptions from ASC 740. Also, the amendments in this Update simplify the accounting for income tax by requiring that an entity recognize a franchise tax (or similar tax) that is partially based on income as an income-based tax, requiring that an entity evaluate when a step up in the tax basis of goodwill should be considered part of the business combination, and other targeted changes. The effective date of the amendments is for fiscal years, and interim periods within those years, beginning after December 15, 2020. The Company is currently evaluating the impact that the adoption of ASU 2019-12 may have on its consolidated financial statements.
NOTE C– RELATED PARTIES
Commencing in February 2008, three publicly traded entities needed a chief financial officer, American Realty Investors, Inc. (“ARL”), Transcontinental Realty Investors, Inc. (“TCI”) and Income Opportunity Realty Investors, Inc. (“IOR”), Mr. Bertcher, is a certified public accountant and has a long history in their industry. New Concept made arrangements with the three entities whereby, in addition to his responsibilities to New Concept Mr. Bertcher would be Chief Financial Officer for the three entities. Mr. Bertcher was paid directly for such services by the contractual advisor for the three companies. Mr. Bertcher resigned as an officer of American Realty Investors, Inc. (“ARI”) and Transcontinental Realty Investors, Inc. (“TCI”) on June 30, 2019, but continued on as an officer of Income Opportunity Realty Investors, Inc. (“IOR”).
Beginning in 2011 Pillar Income Asset Management (“Pillar”) became the contractual advisor to the three publically traded entities. Pillar is a wholly owned subsidiary of RAI. In addition to the relationship with Mr. Bertcher, New Concept conducts business with Pillar whereby Pillar provided the Company with services including processing payroll, acquiring insurance and other administrative matters. The Company believes that by purchasing these services through certain large entities it can get lower costs and better service. Pillar does not charge the Company a fee for providing these services. The Company reimburses Pillar for the direct cost for such services. In December 2019 the Company had accumulated a balance due to Pillar of approximately $450,000 which was repaid from the proceeds of a stock offering. Mr. Bertcher was an officer of Pillar until June 30, 2019.
Realty Advisors, Inc., (“RAI”) is a privately owned investment company and by virtue of its stock ownership, the controlling shareholder for the three public entities. Mr. Bertcher was an officer of RAI until June 30, 2019.
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NOTE D– NOTES RECEIVABLE
Notes Receivable are comprised of the following (in thousands):
| Interest | ||||||||||||
| Rate | 2019 | 2018 | ||||||||||
| American Realty Investors, Inc. (a related party) payable upon maturity in September 2019 | 6 | % | $ | 4,005 | $ | 4,017 | ||||||
| Third Party payable monthly matures in July 2025 | 6 | % | 255 | 297 | ||||||||
| 4,260 | 4,314 | |||||||||||
| less: current portion of notes receivable | 4,046 | 4,063 | ||||||||||
| Notes Receivable | $ | 214 | $ | 251 | ||||||||
The Company holds a note receivable from a non related party. The original note was $415,000 payable in 120 monthly payments at 6% interest. Balance due at December 31, 2019 is $255,000 with $41,000 due currently.
NOTE E – FIXED ASSETS AND OIL AND NATURAL GAS PROPERTIES
Land, building and furniture, fixtures and equitpment are recorded at cost incurred to acquire the assets.
At December 31, 2019, fixed assets are as follows:
| Oil and Gas Properties | 2019 | 2018 | ||||||
| Land and improvements | $ | 432 | $ | 432 | ||||
| Buildings and improvements | 341 | 272 | ||||||
| Equipment and furnishings | 528 | 565 | ||||||
| Total fixed assets | 1,301 | 1,269 | ||||||
| Less: Accumulated depletion | (633 | ) | (651 | ) | ||||
| Net Fixed Assets | $ | 668 | $ | 618 | ||||
| Oil and natural gas properties | 2019 | 2018 | ||||||
| Investment in Oil and gas properties | $ | 4,805 | $ | 6,493 | ||||
| Less: Accumulated depreciation | (4,038 | ) | (3,976 | ) | ||||
| Net oil and gas properties | $ | 767 | $ | 2,517 | ||||
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NOTE F – NOTES PAYABLE
Notes payable is comprised of the following (in thousands):
| 2019 | 2018 | |||||||
| Bank Debt | 245 | 289 | ||||||
| Deferred Borrowing Costs | $ | (24 | ) | $ | (29 | ) | ||
| $ | 221 | $ | 260 | |||||
Bank debt represent loans from a bank to finance drilling and equipment at the Company’s oil and gas operation. The interest rate ranges from 5% to 5 ½ %. The loans are collateralized by the Company’s oil & gas leases as well as real property and equipment.
Aggregate annual principal maturities of long-term debt at December 31, 2019 are as follows (in thousands):
| 2019 | 44 | |||||
| 2020 | 36 | |||||
| 2021 | 32 | |||||
| 2022 | 29 | |||||
| 2023 | 26 | |||||
| Thereafter | 78 | |||||
| $ | 245 | |||||
| Deferred borrowing costs | (24 | ) | ||||
| $ | 221 |
– INCOME TAXES
At December 31, 2019, the Company had net operating loss carry forwards of approximately $10.5 million, which expire between 2019 and 2034.
Forms 1120, U.S, Corporation Income Tax Returns, for the years ending December 31, 2019, 2017, 2016 are subject to examination, by the IRS, generally for three years after they are filed.
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The following table presents the principal reasons for the difference between the Company's effective tax rate and the United States statutory income tax rate.
| 2019 | 2018 | 2017 | ||||||||||
| Earned income tax at statutory rate | $ | — | $ | — | $ | — | ||||||
| Net operating loss utilization | — | — | — | |||||||||
| Deferred tax asset from NOL carry forwards | 2,200 | 2,183 | 2,058 | |||||||||
| Valuation allowance | (2,200 | ) | (2,183 | ) | (2,058 | ) | ||||||
| Reported income tax expense (benefit) | $ | 0 | $ | 0 | $ | 0 | ||||||
| Effective income tax rate | 0.00 | % | 0.00 | % | 0.00 | % | ||||||
The Company believes that it is more likely than not the benefit of NOL carryforwards will not be realized.
Therefore, a valuation allowance on the related deferred tax assets has been recorded.
NOTE H – STOCKHOLDERS’ EQUITY
Outstanding Preferred Stock
Preferred stock consists of the following (amounts in thousands):
| Year Ended | ||||||||
| December 31, | ||||||||
| 2019 | 2018 | |||||||
| Series B convertible preferred stock, $10 par value, liquidation value of $100, authorized 100 shares, issued and outstanding one share | 1 | 1 | ||||||
The Series B preferred stock has a liquidation value of $100 per share. The right to convert expired April 30, 2003. Dividends at a rate of 6% are payable in cash or preferred shares at the option of the Company.
Outstanding Common Stock
On December 4, 2018, the Company issued an additional 3,000,000 shares of Common Stock to Realty Advisors, Inc. (“RAI”) a related party, for cash of $4,500,000 to increase stockholders’ equity by $4,440,000 after issuance costs. The issuance of 3,000,000 shares of Common Stock resulted in a change in control of the Company, as RAI now owns approximately 59.6% of the outstanding Common Stock. The issuance of the 3,000,000 shares of Common Stock to RAI increased the total number of shares issued and outstanding to 5,131,935 shares.
NOTE I – CONTINGENCIES
The Company has been named as a defendant in lawsuits in the ordinary course of business. Management is of the opinion that these lawsuits will not have a material effect on the financial condition, results of operations or cash flows of the Company.
NOTE J – OPERATING SEGMENTS
The following table reconciles the segment information to the corresponding amounts in the Consolidated Statements of Operations and assets from continuing operations:
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| Year ended December 31, 2019 | Oil and Gas Operations | Corporate | Total | |||||||||||||
| Operating revenue | $ | 590 | $ | — | $ | 590 | ||||||||||
| Operating expenses | 599 | 412 | 1,011 | |||||||||||||
| Depreciation, depletion and amortization | 87 | — | 87 | |||||||||||||
| Impairment of oil and gas properties | 2,285 | — | 2,285 | |||||||||||||
| Total Operating Expenses | 2,971 | 412 | 3,383 | |||||||||||||
| Interest income | 257 | — | 257 | |||||||||||||
| Interest expense | (15 | ) | — | (15 | ) | |||||||||||
| Other income (expense), net | — | — | — | |||||||||||||
| Segment operating income (loss) | $ | (2,139 | ) | $ | (412 | ) | $ | (2,551 | ) | |||||||
| Assets | $ | — | $ | — | $ | — | ||||||||||
| Year ended December 31, 2018 | Oil and Gas Operations | Corporate | Total | |||||||||||||
| Operating revenue | $ | 682 | $ | — | $ | 682 | ||||||||||
| Operating expenses | 597 | 353 | 950 | |||||||||||||
| Depreciation, depletion and amortization | 247 | — | 247 | |||||||||||||
| Impairment of oil and gas properties | — | — | — | |||||||||||||
| Total Operating Expenses | 844 | 353 | 1,197 | |||||||||||||
| Interest income | 37 | — | 37 | |||||||||||||
| Interest expense | (18 | ) | — | (18 | ) | |||||||||||
| Other income (expense), net | — | 12 | 12 | |||||||||||||
| Segment operating income (loss) | $ | (143 | ) | $ | (341 | ) | $ | (484 | ) | |||||||
| Assets | $ | 3,596 | $ | 4,286 | $ | 7,882 | ||||||||||
| Year ended December 31, 2017 | Oil and Gas Operations | Corporate | Total | Discontinued Operations Retirement Facility | ||||||||||||
| Operating revenue | $ | 791 | $ | — | $ | 791 | $ | 659 | ||||||||
| Operating expenses | 707 | 408 | 1,115 | 358 | ||||||||||||
| Depreciation, depletion and amortization | 320 | — | 320 | 101 | ||||||||||||
| Lease of Retirement Center | — | — | — | 205 | ||||||||||||
| Impairment of oil and gas properties | 2,626 | — | 2,626 | — | ||||||||||||
| Total Operating Expenses | 3,653 | 408 | 4,061 | 664 | ||||||||||||
| Interest income | 25 | — | 25 | — | ||||||||||||
| Interest expense | (24 | ) | — | (24 | ) | — | ||||||||||
| Other income (expense), net | — | 28 | 28 | — | ||||||||||||
| Segment operating income (loss) | $ | (2,861 | ) | $ | (380 | ) | $ | (3,241 | ) | $ | (5 | ) | ||||
| Assets | $ | 3,903 | $ | 302 | $ | 4,205 | $ | — | ||||||||
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NOTE K - QUARTERLY DATA (UNAUDITED)
The table below reflects the Company’s selected quarterly information for the years ended December 31, 2019, 2017 and 2016. Amounts shown are in thousands except per share amounts.
| First | Second | Third | Fourth | |||||||||||||
| Year ended December 31, 2019 | Quarter | Quarter | Quarter | Quarter | ||||||||||||
| Revenue | $ | 180 | $ | 164 | $ | 127 | $ | 119 | ||||||||
| Operating (expense) | (179 | ) | (231 | ) | (176 | ) | (100 | ) | ||||||||
| Corporate general and administrative expense | (88 | ) | (134 | ) | (92 | ) | (98 | ) | ||||||||
| Impairment of natural gas and oil properties | — | — | (2,285 | ) | — | |||||||||||
| Other income (expense) net | 213 | 60 | 106 | 62 | ||||||||||||
| Income (loss) allocable to common shareholders | 126 | (141 | ) | (2,320 | ) | (17 | ) | |||||||||
| Income (loss) per common share – basic | $ | 0.02 | $ | (0.03 | ) | $ | (0.45 | ) | $ | 0.00 | ||||||
| First | Second | Third | Fourth | |||||||||||||
| Year ended December 31, 2018 | Quarter | Quarter | Quarter | Quarter | ||||||||||||
| Revenue | $ | 204 | $ | 173 | $ | 167 | $ | 138 | ||||||||
| Operating (expense) | (275 | ) | (239 | ) | (186 | ) | (144 | ) | ||||||||
| Corporate general and administrative expense | (75 | ) | (108 | ) | (99 | ) | (71 | ) | ||||||||
| Impairment of natural gas and oil properties | — | — | — | — | ||||||||||||
| Other income (expense) net | 12 | — | (3 | ) | 22 | |||||||||||
| Income (loss) allocable to common shareholders | $ | (134 | ) | $ | (174 | ) | $ | (121 | ) | $ | (55 | ) | ||||
| Income (loss) per common share – basic | $ | (0.07 | ) | $ | (0.08 | ) | $ | (0.06 | ) | $ | 0.00 | |||||
| First | Second | Third | Fourth | |||||||||||||
| Year ended December 31, 2017 | Quarter | Quarter | Quarter | Quarter | ||||||||||||
| Revenue | $ | 195 | $ | 243 | $ | 194 | $ | 159 | ||||||||
| Operating (expense) | (256 | ) | (256 | ) | (254 | ) | (261 | ) | ||||||||
| Corporate general and administrative expense | (100 | ) | (122 | ) | (95 | ) | (91 | ) | ||||||||
| Impairment of natural gas and oil properties | — | — | — | (2,626 | ) | |||||||||||
| Other income (expense) net | (11 | ) | 11 | 65 | (30 | ) | ||||||||||
| Net income (loss) from continuing operations | (172 | ) | (124 | ) | (90 | ) | (2,849 | ) | ||||||||
| Net income (loss) from discontinued operations | 13 | (11 | ) | (11 | ) | (2 | ) | |||||||||
| Income (loss) allocable to common shareholders | $ | (159 | ) | $ | (135 | ) | $ | (101 | ) | $ | (2,851 | ) | ||||
| Income (loss) per common share – basic | $ | (0.08 | ) | $ | (0.07 | ) | $ | (0.05 | ) | $ | (1.39 | ) | ||||
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NOTE L - SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
The following table reflects revenues and expenses directly associated with our oil and gas producing activities, including general and administrative expenses directly related to such producing activities. They do not include any allocation of interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net earnings of our oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil and gas sales after deducting costs, including depreciation, depletion and amortization and after giving effect to permanent differences.
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| 2019 | ||||||||
Gas (MMCF) | Oil (MBBLS) | |||||||
| Proved developed and undeveloped reserves - January 1,2019 | 2,268 | 28 | ||||||
| Purchase of oil and natural gas properties in place | — | — | ||||||
| Discoveries and exclusions | — | — | ||||||
| Revisions | (1,785 | ) | 4 | |||||
| Sales of oil and gas properties in place | — | (4 | ) | |||||
| Production | (129 | ) | — | |||||
| Proved developed and undeveloped reserves - December 31,2019 | 354 | 28 | ||||||
| Probable reserves | — | — | ||||||
| Possible reserves | — | — | ||||||
| Total reserves - December 31, 2019 | 354 | 28 | ||||||
| Proved developed at beginning of year | 180 | 28 | ||||||
| Proved developed reserves at end of year | 354 | 28 | ||||||
In 2019 pursuant to the requirements of the “full cost ceiling test” for oil & gas companies we recorded a non-cash charge to operations of $2.3 million to write down its investment in West Virginia. In September 2019 the Company unsuccessfully drilled a well which resulted in dry hole. As the well did not prove up the estimated probable and possible reserves, the Company had to deem the applicable reserve estimates as impaired. In the third quarter the company booked an impairment expense of $2.3 which represents a reduction of both the estimated probable and possible reserves as well as the cost of drilling the failed well. This charge to earnings was caused by a revaluation of the Company’s non- producing oil and gas reserves.
| 2018 | ||||||||
Gas (MMCF) | Oil (MBBLS) | |||||||
| Proved developed and undeveloped reserves - January 1,2018 | 830 | 69 | ||||||
| Purchase of oil and natural gas properties in place | — | — | ||||||
| Discoveries and exclusions | (520 | ) | (37 | ) | ||||
| Revisions | — | — | ||||||
| Sales of oil and gas properties in place | — | — | ||||||
| Production | (130 | ) | (4 | ) | ||||
| Proved developed and undeveloped reserves - December 31,2018 | 180 | 28 | ||||||
| Probable reserves | 1,566 | — | ||||||
| Possible reserves | 522 | — | ||||||
| Total reserves - December 31, 2018 | 2,268 | 28 | ||||||
| Proved developed at beginning of year | 830 | 69 | ||||||
| Proved developed reserves at end of year | 180 | 28 | ||||||
| 2019 | 2018 | |||||||
| Oil and gas sales | $ | 590 | $ | 682 | ||||
| Operating expenses | (599 | ) | (597 | ) | ||||
| Depreciation, depletion and amortization | (87 | ) | (247 | ) | ||||
| Impairment of oil & gas properties | (2,285 | ) | — | |||||
| Results of operations | $ | (2,381 | ) | $ | (162 | ) | ||
The following table reflects the standardized measure of future net cash flows related to our proved reserves
| 2019 | 2018 | |||||||
| Future oil and gas cash inflows | $ | 2,526 | $ | 8,292 | ||||
| Future oil & gas operating expenses | (611 | ) | (1,478 | ) | ||||
| Future development costs | 0 | (1,400 | ) | |||||
| Future tax expense | (159 | ) | (590 | ) | ||||
| Future net cash flows | $ | 1,756 | $ | 4,824 | ||||
| 10% discount to reflect timing of cash flows | (806 | ) | (1,853 | ) | ||||
| $ | 950 | $ | 2,971 |
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(1) Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves are as likely as not to be recovered.
(2) Possible reserves are those additional reserves that are less certain to be recovered than probable reserves
NOTE M – ASSET RETIREMENT OBLIGATION
The Company records an asset retirement obligation (ARO) when the total depth of a drilled well is reached and the Company can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs. The Company records the ARO liability on the consolidated balance sheets and capitalizes a portion of the cost in “Oil and natural gas properties” during the period in which the obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date and adjusted for the Company’s credit risk. This amount is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for the Company. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds. The additional capitalized costs are depreciated on a unit-of-production basis or straight-line basis.
In 2012, the Company re-evaluated its method of plugging abandoned wells and determined by doing so in-house it could lower the cost. Based upon the Company’s current calculations, we have established a sufficient reserve, for accounting purposes, to plug the existing wells when necessary.
| 2019 | 2018 | ||||
| Asset retirement obligation, January 1 | $2,770 | $2,770 | |||
| Acquisition of oil and gas properties | - | - | |||
| Revisions in the estimated cash flows | - | - | |||
| Liability incurred upon acquiring and drilling wells | - | - | |||
| Liability settled upon plugging and abandoning wells | - | - | |||
| Accretion of discounnt expense | - | - | |||
| Asset retirement obligation, December 31 | $2,770 | $2,770 |
NOTE N – SUBSEQUENT EVENTS
During 2020, a strain of coronavirus (“COVID – 19”) was reported worldwide, resulting in decreased economic activity and concerns about the pandemic, which would adversely affect the broader global economy. At this point, the extent to which COVID – 19 may impact the global economy and our business is uncertain, but pandemics or other significant public health events could have a material adverse effect on our business and results of operations.
The Company has evaluated subsequent events through March 25, 2019, the date the financial statements were available to be issued, and has determined that there are none to be reported.
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The following documents are filed as exhibits (or are incorporated by reference as indicated) into this Report:
| Exhibit Designation | Exhibit Description | |
| 3.1 | Articles of Incorporation of Medical Resource Companies of America (incorporated by reference to Exhibit 3.1 to Registrant’s Form S-4 Registration Statement No. 333-55968 dated December 21, 1992) | |
| 3.2 | Amendment to the Articles of Incorporation of Medical Resource Companies of America (incorporated by reference to Exhibit 3.5 to Registrant’s Form 8-K dated April 1, 1993) | |
| 3.3 | Restated Articles of Incorporation of Greenbriar Corporation (incorporated by reference to Exhibit 3.1.1 to Registrant’s Form 10-K dated December 31, 1995) | |
| 3.4 | Amendment to the Articles of Incorporation of Medical Resource Companies of America (incorporated by reference to Exhibit to Registrant’s PRES 14-C dated February 27, 1996) | |
| 3.5 | Certificate of Decrease in Authorized and Issued Shares effective November 30, 2001 (incorporated by reference to Exhibit 2.1.7 to Registrant’s Form 10-K dated December 31, 2002) | |
| 3.6 | Certificate of Designations, Preferences and Rights of Preferred Stock dated May 7, 1993 relating to Registrant’s Series B Preferred Stock (incorporated by reference to Exhibit 4.1.2 to Registrant’s Form S-3 Registration Statement No. 333-64840 dated June 22, 1993) | |
| 3.7 | Certificate of Voting Powers, Designations, Preferences and Rights of Registrant’s Series F Senior Convertible Preferred Stock dated December 31, 1997 (incorporated by reference to Exhibit 2.2.2 of Registrant’s Form 10-KSB for the fiscal year ended December 31, 1997) | |
| 3.8 | Certificate of Voting Powers, Designations, Preferences and Rights of Registrant’s Series G Senior Non-Voting Convertible Preferred Stock dated December 31, 1997 (incorporated by reference to Exhibit 2.2.3 of Registrant’s Form 10-KSB for the fiscal year ended December 31, 1997) | |
| 3.9 | Certificate of Designations dated October 12, 2004 as filed with the Secretary of State of Nevada on October 13, 2004 (incorporated by reference to Exhibit 3.4 of Registrant’s Current Report on Form 8-K for event occurring October 12, 2004) | |
| 3.10 | Certificate of Amendment to Articles of Incorporation effective February 8, 2005 (incorporated by reference to Exhibit 3.5 of Registrant’s Current Report on Form 8-K for event occurring February 8, 2005) | |
| 3.11 | Certificate of Amendment to Articles of Incorporation effective March 21, 2007 (incorporated by reference to Exhibit 3.13 of Registrant’s Current Report on Form 8-K for event occurring March 21, 2005) | |
| 3.12 | Amended and restated bylaws of New Concept Energy, Inc. dated November 18, 2008. | |
| 10.1 | Registrant’s 1997 Stock Option Plan (filed as Exhibit 4.1 to Registrant’s Form S-8 Registration Statement, Registration No. 333-33985 and incorporated herein by this reference). | |
| 10.2 | Registrant’s 2000 Stock Option Plan (filed as Exhibit 4.1 to Registrant’s Form S-8 Registration Statement, Registration No. 333-50868 and incorporated herein by this reference) | |
| 14.0 | Code of Ethics for Senior Financial Officers (incorporated by reference to Exhibit 14.0 to Registrant’s Annual Report on Form 10-K for the fiscal year ended December 31, 2003) | |
| 21.1* | Subsidiaries of the Registrant | |
| 31.1* | Rule 13a-14(a) Certification by Principal Executive Officer and Chief Financial Officer | |
| 32.1* | Certification of Principal Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |
| 99.1* | Reserve Study dated March 16, 2015 prepared by Lee Keeling and Associates, Inc is included as an exhibit | |
| 99.2 | Shared Services Agreement effective December 31, 2010 (incorporated by reference to Exhibit 99.2 to Registrants Form 10K/A for the year ended December 31, 2011 filed March 21, 2013) | |
| 101 | Interactive data files pursuant to Rule 405 of Regulation S-T | |
| *Filed herewith. | ||
| 40 |
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| NEW CONCEPT ENERGY, INC. | |
| March 25, 2019 | by:/s/ Gene S. Bertcher |
| Gene S. Bertcher | |
| Principal Executive Officer | |
| President and Chief Financial Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.
| Signature | Title | Date |
|
/s/ Gene S. Bertcher Gene S. Bertcher |
Chairman, President, Principal Executive Officer, Chief Financial Officer and Director | March 25, 2019 |
|
/s/ Raymond D Roberts Raymond D Roberts |
Director | March 25, 2019 |
|
/s/ Victor L. Lund Victor L. Lund |
Director | March 25, 2019 |
|
/s/ Dan Locklear Dan Locklear |
Director | March 25, 2019 |
|
/s/ Cecilia Maynard Cecilia Maynard |
Director | March 25, 2019 |
EXHIBIT 21.1
SUBSIDIARIES OF REGISTRANT
| Entity Name | State or County | % Owned |
| Cardinal Oil & Gas, Inc. | Nevada | 100% |
| Mockingbird Energy, LLC | Nevada | 100% |
| Mountaineer State Energy, Inc. | West Virginia | 100% |
| Mountaineer State Operations, LLC | Nevada | 100% |
| CERTIFICATIONS | EXHIBIT 31.1 |
PRINCIPAL EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER’S RULE 13a-14(a)/15d-14(a)
I, Gene S. Bertcher, certify that:
1) I have reviewed this annual report of Form 10-K of New Concept Energy, Inc.;
2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made in light of the circumstances under which such statements were made, and is not misleading with respect to the period covered by this report;
3) Based on my knowledge, the financial statements and other financial information included in this report fairly present, in all material respects, the financial condition, results of operations and cash flows of the Registrant as of and for the periods presented in this report;
4) I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13-15(e) and 15(d)-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15(d)-15(f)) for the Registrant and have:
(a) Designed such disclosure controls and procedures, or used such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principals;
(c) Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the controls and procedures as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting.
5) I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of Registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal controls.
| Dated: March 25, 2020 | ||
| /s/ Gene S. Bertcher | ||
| Gene S. Bertcher | ||
| Principal Executive Officer, President | ||
| and Chief Financial Officer |
EXHIBIT 32.1
CERTIFICATION PURSUANT TO 18 U.S.C. § 1350, AS ADOPTED
PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of New Concept Energy, Inc. (the “Company”) of Form 10-K for the period ended December 31, 2019, as filed with the Securities Exchange Commission on the date hereof (the “Report”), I, Gene S. Bertcher, President and Chief Financial Officer of the Company, do hereby certify pursuant to 18 U.S.C. §1350 that:
(i) The Report fully complies with the requirements of Section 13(a) or I 5(d) of the Securities Exchange Act of 1934, as amended; and
(ii) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company, at the end of the period indicated and for the periods indicated.
| Dated: March 25, 2020 | ||
| /s/ Gene S. Bertcher | ||
| Gene S. Bertcher | ||
| Principal Executive Officer, President | ||
| and Chief Financial Officer |
Exhibit 99.1
ESTIMATED RESERVES AND FUTURE NET REVENUE
OIL AND GAS PROPERTIES
Owned By
MOUNTAINEER STATE ENERGY, INC.
LOCATED IN
ATHENS, MEIGS AND MORGAN COUNTIES, OHIO AND
CALHOUN, JACKSON, PLEASANTS AND ROANE COUNTIES, WEST VIRGINIA
Effective Date 12/31/2019
INDEX
ESTIMATED RESERVES AND FUTURE NET REVENUE
MOUNTAINEER STATE ENERGY, INC.
INDEX
LETTER SCHEDULES
Summary Forecasts of Production, Income and Estimated 1
Future Net Revenue Discounted at 10 Per Cent
Maximum to Minimum One-line Summary 2
Alphabetical One-line Summary of Properties 3
LETTER
LEE KEELING AND ASSOCIATES, INC.
PETROLEUM CONSULTANTS
First Place Tower
15 East Fifth Street • Suite 3500 Tulsa, Oklahoma 74103-4350
(918) 587-5521 • Fax: (918) 587-2881
www.lkaengineers.com
March 10, 2020
New Concept Energy, Inc. 1603 LBJ Freeway, Suite 300
Dallas, Texas 75234
| Attn: | Mr. Gene Bertcher Chief Executive Officer |
| Re: | Estimated Reserves and Future Net Revenue Proved Producing Reserves |
Oil and Gas Properties Owned by Mountaineer State Energy, Inc.
Gentlemen:
In accordance with your request, we have prepared an estimate of net proved producing reserves and the future net revenue to be realized from the interests owned by Mountaineer State Energy, Inc. (Mountaineer) in oil and gas properties located in the states of Ohio and West Virginia. Our estimate includes all of Mountaineer’s net reserves. The effective date of this estimate is December 31, 2019, and the results are summarized as follows:
| ESTIMATED REMAINING NET RESERVES | FUTURE NET REVENUE | |||||||||||||||
| Reserve Classification | Oil (BBLS) | Gas (MCF) | Total ($) | Present Worth Disc. @ 10% ($) | ||||||||||||
| Proved Developed Producing | ||||||||||||||||
| Non-Operated | — | 847 | 2,208 | 891 | ||||||||||||
| Operated | 29,105 | 352,903 | 1,752,389 | 949,188 | ||||||||||||
| Total All Reserves | 29,105 | 353,750 | 1,754,597 | 950,079 | ||||||||||||
| Note: Totals may not agree with schedules due to roundoff | ||||||||||||||||
Future net revenue is the amount, exclusive of state and federal income taxes, which will accrue to the subject interests from continued operation of the properties to depletion. It should not be construed as a fair market or trading value.
No attempt has been made to determine whether the wells and facilities are in compliance with various governmental regulations, nor have costs been included in the event they are not.
This report consists of various summaries. Schedule No. 1 presents summary forecasts by operator type of annual gross and net production, severance and ad valorem taxes, operating
| 1 |
income and net revenue. Schedule No. 2 is a sequential listing of the forecast entities based on operator type and discounted future net revenue. A one-line alphabetical listing of the forecast entities is presented on Schedule No. 3.
BACKGROUND
This estimate is concerned with approximately one hundred fifty-nine (159) gas and oil wells of which one hundred forty-nine (149) were selling gas with ten (10) producing oil on the effective date. Several additional wells are shut-in. Composite production decline curves have been prepared of gas production (sales) for the wells operated by Mountaineer in the Ohio counties of Athens and Meigs, and the West Virginia counties of Calhoun, Jackson and Roane. Individual production decline curves with cash flows have been prepared for the ten Berea oil wells and the one Mountaineer operated gas well located in Jackson County, West Virginia. Production decline curves and cash flows are also included for the wells not operated by Mountaineer, in various Ohio and West Virginia counties. These decline curves are the “forecast entities” referred to in the preceding paragraphs.
CLASSIFICATION OF RESERVES
Reserves assigned to the various leases and/or wells have been classified as “proved developed” in accordance with the definitions of the proved reserves as promulgated by the Securities and Exchange Commission (SEC). See the attached Appendix: SEC Petroleum Reserve Definitions.
Proved Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.
ESTIMATION OF RESERVES
All of Mountaineer’s active gas wells have been producing for a considerable length of time and all have well-defined production declining trends. Reserves attributable to these wells were based upon extrapolation of these decline trends to an economic limit. Reserves attributable to the oldest of the Berea oil wells were estimated by extrapolation of the production decline trend to the economic limit.
Reserves anticipated from newer wells were based upon analogy with nearby wells which are producing from the same horizons in the respective areas.
Our estimate of reserves used all methods and procedures considered necessary, under the circumstances, to prepare this report.
FUTURE NET REVENUE
Oil and Gas Income
Income from the recovery and sale of the estimated oil and gas reserves were based on the average of prices received on the first day of each month for January 2019 through December 2019, as provided by the staff of Mountaineer.
These prices were $52.89 per barrel of oil, and $2.79 per MCF for gas in Ohio and West Virginia. The prices were held constant, but provisions were made for state severance and ad valorem taxes.
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Operating Expenses
Anticipated monthly expenses were based on expenses supplied by Mountaineer. Expenses were not escalated but held constant for the various recovery periods.
GENERAL
The assumptions, data, methods and procedures used are appropriate for the purpose served by the report.
Information upon which this estimate of net reserves and future net revenue has been based was furnished by the staff of Mountaineer or was obtained by us from outside sources we consider to be reliable. This information is assumed to be correct. No attempt has been made to verify title or ownership of the subject properties. Wells were not inspected by a representative of this firm, nor were they tested under our supervision; however, the performance of the majority of the wells was discussed with the employees of Mountaineer.
This report has been prepared utilizing methods and procedures regularly used by petroleum engineers to estimate oil and gas reserves for properties of this type and character. The recovery of oil and gas reserves and projection of producing rates are dependent upon many variable factors including prudent operation, compression of gas when needed, market demand, installation of lifting equipment, and remedial work when required. The reserves included in this report have been based upon the assumption that the wells will be operated in a prudent manner under the same conditions existing on the effective date. Actual production results and future well data may yield additional facts, not presently available to us, which may require an adjustment to our estimates.
The projection of cash flow has been made assuming constant prices. There is no assurance that prices will not vary. For this reason and those listed in the previous paragraph, the future net cash from the sale of production from the subject properties may vary from the estimates contained in this report.
The information developed during the course of this investigation, basic data, maps and worksheets showing recovery determinations are available for inspection in our office.
We appreciate this opportunity to be of service to you.
Very truly yours,
Lee Keeling and Associates, Inc.
Lee Keeling and Associates, Inc.
LKA7859
| 3 |
SEC Petroleum Reserve Definitions
§210.4-10 Financial accounting and reporting for oil and gas producing activities pursuant to the Federal securities laws and the Energy Policy and Conservation Act of 1975.
This section prescribes financial accounting and reporting standards for registrants with the Commission engaged in oil and gas producing activities in filings under the Federal securities laws and for the preparation of accounts by persons engaged, in whole or in part, in the production of crude oil or natural gas in the United States, pursuant to section 503 of the Energy Policy and Conservation Act of 1975 (42 U.S.C. 6383) (EPCA) and section 11(c) of the Energy Supply and Environmental Coordination Act of 1974 (15 U.S.C. 796) (ESECA), as amended by section 505 of EPCA. The application of this section to those oil and gas producing operations of companies regulated for ratemaking purposes on an individual-company-cost-of-service basis may, however, give appropriate recognition to differences arising because of the effect of the ratemaking process.
Exemption. Any person exempted by the Department of Energy from any record-keeping or reporting requirements pursuant to section 11(c) of ESECA, as amended, is similarly exempted from the related provisions of this section in the preparation of accounts pursuant to EPCA. This exemption does not affect the applicability of this section to filings pursuant to the Federal securities laws.
DEFINITIONS
| (a) | Definitions. The following definitions apply to the terms listed below as they are used in this section: |
(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.
(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:
| (i) | Same geological formation (but not necessarily in pressure communication with the reservoir of interest); |
| (ii) | Same environment of deposition; |
| (iii) | Similar geological structure; and |
| (iv) | Same drive mechanism. |
Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.
(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.
(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
| (6) | Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered: |
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
| (iv) | Provide improved recovery systems. |
(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
| 1 |
(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or G&G costs.
(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
| (iii) | Dry hole contributions and bottom hole contributions. |
| (iv) | Costs of drilling and equipping exploratory wells. |
| (v) | Costs of drilling exploratory-type stratigraphic test wells. |
(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.
| (14) | Extension well. An extension well is a well drilled to extend the limits of a known reservoir. |
(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
| (16) | Oil and gas producing activities. (i) Oil and gas producing activities include: |
(A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;
(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
| (1) | Lifting the oil and gas to the surface; and |
| (2) | Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and |
(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:
a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.
| (ii) | Oil and gas producing activities do not include: |
| (A) | Transporting, refining, or marketing oil and gas; |
(B) Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
| (D) | Production of geothermal steam. |
| (17) | Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. |
(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
| 2 |
(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
| (iv) | See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. |
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
(20) Production costs. (i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
| (A) | Costs of labor to operate the wells and related equipment and facilities. |
| (B) | Repairs and maintenance. |
| (C) | Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. |
| (D) | Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. |
| (E) | Severance taxes. |
(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.
| (21) | Proved area. The part of a property to which proved reserves have been specifically attributed. |
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
| (i) | The area of the reservoir considered as proved includes: |
| (A) | The area identified by drilling and limited by fluid contacts, if any, and |
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
| 3 |
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
| (B) | The project has been approved for development by all necessary parties and entities, including governmental entities. |
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
| (23) | Proved properties. Properties with proved reserves. |
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
NOTE TO PARAGRAPH (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.
(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
(32) Unproved properties. Properties with no proved reserves. SUCCESSFUL EFFORTS METHOD
(b) A reporting entity that follows the successful efforts method shall comply with the accounting and financial reporting disclosure requirements of FASB ASC Topic 932, Extractive Activities—Oil and Gas.
FULL COST METHOD
(c) Application of the full cost method of accounting. A reporting entity that follows the full cost method shall apply that method to all of its operations and to the operations of its subsidiaries, as follows:
| 4 |
| (1) | Determination of cost centers. Cost centers shall be established on a country-by-country basis. |
| (2) | Costs to be capitalized. All costs associated with property acquisition, exploration, and development activities (as defined in paragraph |
(a) of this section) shall be capitalized within the appropriate cost center. Any internal costs that are capitalized shall be limited to those costs that can be directly identified with acquisition, exploration, and development activities undertaken by the reporting entity for its own account, and shall not include any costs related to production, general corporate overhead, or similar activities.
(3) Amortization of capitalized costs. Capitalized costs within a cost center shall be amortized on the unit-of-production basis using proved oil and gas reserves, as follows:
(i) Costs to be amortized shall include (A) all capitalized costs, less accumulated amortization, other than the cost of properties described in paragraph (ii) below; (B) the estimated future expenditures (based on current costs) to be incurred in developing proved reserves; and (C) estimated dismantlement and abandonment costs, net of estimated salvage values.
(ii) The cost of investments in unproved properties and major development projects may be excluded from capitalized costs to be amortized, subject to the following:
(A) All costs directly associated with the acquisition and evaluation of unproved properties may be excluded from the amortization computation until it is determined whether or not proved reserves can be assigned to the properties, subject to the following conditions:
(1) Until such a determination is made, the properties shall be assessed at least annually to ascertain whether impairment has occurred. Unevaluated properties whose costs are individually significant shall be assessed individually. Where it is not practicable to individually assess the amount of impairment of properties for which costs are not individually significant, such properties may be grouped for purposes of assessing impairment. Impairment may be estimated by applying factors based on historical experience and other data such as primary lease terms of the properties, average holding periods of unproved properties, and geographic and geologic data to groupings of individually insignificant properties and projects. The amount of impairment assessed under either of these methods shall be added to the costs to be amortized.
| (2) | The costs of drilling exploratory dry holes shall be included in the amortization base immediately upon determination that the well is dry. |
(3) If geological and geophysical costs cannot be directly associated with specific unevaluated properties, they shall be included in the amortization base as incurred. Upon complete evaluation of a property, the total remaining excluded cost (net of any impairment) shall be included in the full cost amortization base.
(B) Certain costs may be excluded from amortization when incurred in connection with major development projects expected to entail significant costs to ascertain the quantities of proved reserves attributable to the properties under development (e.g., the installation of an offshore drilling platform from which development wells are to be drilled, the installation of improved recovery programs, and similar major projects undertaken in the expectation of significant additions to proved reserves). The amounts which may be excluded are applicable portions of (1) the costs that relate to the major development project and have not previously been included in the amortization base, and (2) the estimated future expenditures associated with the development project. The excluded portion of any common costs associated with the development project should be based, as is most appropriate in the circumstances, on a comparison of either (i) existing proved reserves to total proved reserves expected to be established upon completion of the project, or (ii) the number of wells to which proved reserves have been assigned and total number of wells expected to be drilled. Such costs may be excluded from costs to be amortized until the earlier determination of whether additional reserves are proved or impairment occurs.
(C) Excluded costs and the proved reserves related to such costs shall be transferred into the amortization base on an ongoing (well-by-well or property-by-property) basis as the project is evaluated and proved reserves established or impairment determined. Once proved reserves are established, there is no further justification for continued exclusion from the full cost amortization base even if other factors prevent immediate production or marketing.
(iii) Amortization shall be computed on the basis of physical units, with oil and gas converted to a common unit of measure on the basis of their approximate relative energy content, unless economic circumstances (related to the effects of regulated prices) indicate that use of units of revenue is a more appropriate basis of computing amortization. In the latter case, amortization shall be computed on the basis of current gross revenues (excluding royalty payments and net profits disbursements) from production in relation to future gross revenues, based on current prices (including consideration of changes in existing prices provided only by contractual arrangements), from estimated production of proved oil and gas reserves. The effect of a significant price increase during the year on estimated future gross revenues shall be reflected in the amortization provision only for the period after the price increase occurs.
(iv) In some cases it may be more appropriate to depreciate natural gas cycling and processing plants by a method other than the unit-of- production method.
(v) Amortization computations shall be made on a consolidated basis, including investees accounted for on a proportionate consolidation basis. Investees accounted for on the equity method shall be treated separately.
(4) Limitation on capitalized costs. (i) For each cost center, capitalized costs, less accumulated amortization and related deferred income taxes, shall not exceed an amount (the cost center ceiling) equal to the sum of:
(A) The present value of estimated future net revenues computed by applying current prices of oil and gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions; plus
| (B) | the cost of properties not being amortized pursuant to paragraph (i)(3)(ii) of this section; plus |
| (C) | the lower of cost or estimated fair value of unproven properties included in the costs being amortized; less |
(D) income tax effects related to differences between the book and tax basis of the properties referred to in paragraphs (i)(4)(i) (B) and (C) of this section.
(ii) If unamortized costs capitalized within a cost center, less related deferred income taxes, exceed the cost center ceiling, the excess shall be charged to expense and separately disclosed during the period in which the excess occurs. Amounts thus required to be written off shall not be reinstated for any subsequent increase in the cost center ceiling.
| 5 |
(5) Production costs. All costs relating to production activities, including workover costs incurred solely to maintain or increase levels of production from an existing completion interval, shall be charged to expense as incurred.
(6) Other transactions. The provisions of paragraph (h) of this section, “Mineral property conveyances and related transactions if the successful efforts method of accounting is followed,” shall apply also to those reporting entities following the full cost method except as follows:
(i) Sales and abandonments of oil and gas properties. Sales of oil and gas properties, whether or not being amortized currently, shall be accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. For instance, a significant alteration would not ordinarily be expected to occur for sales involving less than 25 percent of the reserve quantities of a given cost center. If gain or loss is recognized on such a sale, total capitalization costs within the cost center shall be allocated between the reserves sold and reserves retained on the same basis used to compute amortization, unless there are substantial economic differences between the properties sold and those retained, in which case capitalized costs shall be allocated on the basis of the relative fair values of the properties. Abandonments of oil and gas properties shall be accounted for as adjustments of capitalized costs; that is, the cost of abandoned properties shall be charged to the full cost center and amortized (subject to the limitation on capitalized costs in paragraph (b) of this section).
(ii) Purchases of reserves. Purchases of oil and gas reserves in place ordinarily shall be accounted for as additional capitalized costs within the applicable cost center; however, significant purchases of production payments or properties with lives substantially shorter than the composite productive life of the cost center shall be accounted for separately.
(iii) Partnerships, joint ventures and drilling arrangements. (A) Except as provided in paragraph (i)(6)(i) of this section, all consideration received from sales or transfers of properties in connection with partnerships, joint venture operations, or various other forms of drilling arrangements involving oil and gas exploration and development activities (e.g., carried interest, turnkey wells, management fees, etc.) shall be credited to the full cost account, except to the extent of amounts that represent reimbursement of organization, offering, general and administrative expenses, etc., that are identifiable with the transaction, if such amounts are currently incurred and charged to expense.
(B) Where a registrant organizes and manages a limited partnership involved only in the purchase of proved developed properties and subsequent distribution of income from such properties, management fee income may be recognized provided the properties involved do not require aggregate development expenditures in connection with production of existing proved reserves in excess of 10% of the partnership's recorded cost of such properties. Any income not recognized as a result of this limitation would be credited to the full cost account and recognized through a lower amortization provision as reserves are produced.
(iv) Other services. No income shall be recognized in connection with contractual services performed (e.g. drilling, well service, or equipment supply services, etc.) in connection with properties in which the registrant or an affiliate (as defined in §210.1-02(b)) holds an ownership or other economic interest, except as follows:
(A) Where the registrant acquires an interest in the properties in connection with the service contract, income may be recognized to the extent the cash consideration received exceeds the related contract costs plus the registrant's share of costs incurred and estimated to be incurred in connection with the properties. Ownership interests acquired within one year of the date of such a contract are considered to be acquired in connection with the service for purposes of applying this rule. The amount of any guarantees or similar arrangements undertaken as part of this contract should be considered as part of the costs related to the properties for purposes of applying this rule.
(B) Where the registrant acquired an interest in the properties at least one year before the date of the service contract through transactions unrelated to the service contract, and that interest is unaffected by the service contract, income from such contract may be recognized subject to the general provisions for elimination of inter-company profit under generally accepted accounting principles.
(C) Notwithstanding the provisions of paragraphs (i)(6)(iv) (A) and (B) of this section, no income may be recognized for contractual services performed on behalf of investors in oil and gas producing activities managed by the registrant or an affiliate. Furthermore, no income may be recognized for contractual services to the extent that the consideration received for such services represents an interest in the underlying property.
(D) Any income not recognized as a result of these rules would be credited to the full cost account and recognized through a lower amortization provision as reserves are produced.
| (7) | Disclosures. Reporting entities that follow the full cost method of accounting shall disclose all of the information required by paragraph |
(k) of this section, with each cost center considered as a separate geographic area, except that reasonable groupings may be made of cost centers that are not significant in the aggregate. In addition:
(i) For each cost center for each year that an income statement is required, disclose the total amount of amortization expense (per equivalent physical unit of production if amortization is computed on the basis of physical units or per dollar of gross revenue from production if amortization is computed on the basis of gross revenue).
(ii) State separately on the face of the balance sheet the aggregate of the capitalized costs of unproved properties and major development projects that are excluded, in accordance with paragraph (i)(3) of this section, from the capitalized costs being amortized. Provide a description in the notes to the financial statements of the current status of the significant properties or projects involved, including the anticipated timing of the inclusion of the costs in the amortization computation. Present a table that shows, by category of cost, (A) the total costs excluded as of the most recent fiscal year; and (B) the amounts of such excluded costs, incurred (1) in each of the three most recent fiscal years and (2) in the aggregate for any earlier fiscal years in which the costs were incurred. Categories of cost to be disclosed include acquisition costs, exploration costs, development costs in the case of significant development projects and capitalized interest.
(8) For purposes of this paragraph (c), the term “current price” shall mean the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
| 6 |
INCOME TAXES
(d) Income taxes. Comprehensive interperiod income tax allocation by a method which complies with generally accepted accounting principles shall be followed for intangible drilling and development costs and other costs incurred that enter into the determination of taxable income and pretax accounting income in different periods.
| 7 |
SCHEDULE 1
| ESTIMATED RESERVES AND FUTURE NET REVENUE | DATE : 03/09/2020 |
| MOUNTAINEER STATE ENERGY | TIME : 14:51:25 |
| OHIO AND WEST VIRGINIA PROPERTIES | DBS : MountaineerSt |
| ALL RESERVES | SETTINGS : LKA0120 |
| Scenario : LKA0120 |
R E S E R V E S A N D E C O N O M I C S
AS OF DATE: 01/2020
--END-- MO-YEAR |
GROSS OIL PRODUCTION | GROSS GAS PRODUCTION | NET OIL PRODUCTION | NET GAS PRODUCTION | NET OIL PRICE | NET GAS PRICE | NET OIL SALES | NET GAS SALES | TOTAL NET SALES |
| ------ | ---MBBLS--- | ---MMCF--- | ---MBBLS--- | ---MMCF--- | ---$/BBL--- | ---$/MCF--- | ---M$--- | ---M$--- | ---M$--- |
| 12-2020 | 3.227 | 86.903 | 2.535 | 74.569 | 52.890 | 2.790 | 134.075 | 208.047 | 342.122 |
| 12-2021 | 2.929 | 78.871 | 2.293 | 67.678 | 52.890 | 2.790 | 121.289 | 188.821 | 310.110 |
| 12-2022 | 2.635 | 54.753 | 2.052 | 46.686 | 52.890 | 2.790 | 108.537 | 130.255 | 238.792 |
| 12-2023 | 2.323 | 26.595 | 1.794 | 22.142 | 52.890 | 2.790 | 94.903 | 61.776 | 156.679 |
| 12-2024 | 2.113 | 19.174 | 1.624 | 15.729 | 52.890 | 2.790 | 85.867 | 43.885 | 129.752 |
| 12-2025 | 1.980 | 17.447 | 1.518 | 14.289 | 52.890 | 2.790 | 80.311 | 39.868 | 120.178 |
| 12-2026 | 1.859 | 15.895 | 1.424 | 12.994 | 52.890 | 2.790 | 75.308 | 36.255 | 111.563 |
| 12-2027 | 1.749 | 14.496 | 1.338 | 11.827 | 52.890 | 2.790 | 70.754 | 32.997 | 103.751 |
| 12-2028 | 1.648 | 13.231 | 1.259 | 10.771 | 52.890 | 2.790 | 66.567 | 30.052 | 96.619 |
| 12-2029 | 1.554 | 12.085 | 1.185 | 9.816 | 52.890 | 2.790 | 62.698 | 27.387 | 90.085 |
| 12-2030 | 1.466 | 11.046 | 1.118 | 8.951 | 52.890 | 2.790 | 59.115 | 24.973 | 84.088 |
| 12-2031 | 1.385 | 10.103 | 1.054 | 8.166 | 52.890 | 2.790 | 55.772 | 22.784 | 78.556 |
| 12-2032 | 1.308 | 9.247 | 0.995 | 7.455 | 52.890 | 2.790 | 52.633 | 20.798 | 73.432 |
| 12-2033 | 1.236 | 8.460 | 0.939 | 6.809 | 52.890 | 2.790 | 49.683 | 18.996 | 68.679 |
| 12-2034 | 1.157 | 7.739 | 0.877 | 6.222 | 52.890 | 2.790 | 46.406 | 17.359 | 63.765 |
| S TOT | 28.567 | 386.046 | 22.006 | 324.105 | 52.890 | 2.790 | 1163.919 | 904.253 | 2068.172 |
| AFTER | 10.011 | 41.998 | 7.099 | 29.646 | 52.890 | 2.790 | 375.446 | 82.712 | 458.159 |
| TOTAL | 38.578 | 428.044 | 29.105 | 353.751 | 52.890 | 2.790 | 1539.365 | 986.965 | 2526.330 |
| --END-- | AD VALOREM | PRODUCTION | DIRECT OPER | INTEREST | CAPITAL | EQUITY | FUTURE NET | CUMULATIVE | CUM. DISC. |
| MO-YEAR | TAX | TAX | EXPENSE | PAID | REPAYMENT | INVESTMENT | CASHFLOW | CASHFLOW | CASHFLOW |
| ------ | ---M$--- | ---M$--- | ---M$--- | ---M$--- | ---M$--- | ---M$--- | ---M$--- | ---M$--- | ---M$--- |
|
12-2020 |
17.245 |
4.919 |
117.344 |
0.000 |
0.000 |
0.000 |
202.614 |
202.614 |
193.185 |
| 12-2021 | 15.620 | 4.475 | 117.344 | 0.000 | 0.000 | 0.000 | 172.671 | 375.285 | 342.854 |
| 12-2022 | 11.754 | 3.701 | 80.589 | 0.000 | 0.000 | 0.000 | 142.748 | 518.033 | 455.472 |
| 12-2023 | 7.297 | 2.810 | 27.371 | 0.000 | 0.000 | 0.000 | 119.201 | 637.234 | 540.906 |
| 12-2024 | 6.292 | 1.958 | 15.140 | 0.000 | 0.000 | 0.000 | 106.363 | 743.597 | 610.172 |
| 12-2025 | 5.851 | 1.777 | 15.140 | 0.000 | 0.000 | 0.000 | 97.410 | 841.007 | 667.842 |
| 12-2026 | 5.456 | 1.614 | 15.140 | 0.000 | 0.000 | 0.000 | 89.353 | 930.360 | 715.932 |
| 12-2027 | 5.097 | 1.467 | 15.140 | 0.000 | 0.000 | 0.000 | 82.048 | 1012.408 | 756.076 |
| 12-2028 | 4.768 | 1.333 | 15.140 | 0.000 | 0.000 | 0.000 | 75.378 | 1087.786 | 789.604 |
| 12-2029 | 4.466 | 1.212 | 15.140 | 0.000 | 0.000 | 0.000 | 69.267 | 1157.053 | 817.613 |
| 12-2030 | 4.188 | 1.103 | 15.140 | 0.000 | 0.000 | 0.000 | 63.657 | 1220.710 | 841.013 |
| 12-2031 | 3.931 | 1.004 | 15.140 | 0.000 | 0.000 | 0.000 | 58.482 | 1279.192 | 860.557 |
| 12-2032 | 3.691 | 0.913 | 15.140 | 0.000 | 0.000 | 0.000 | 53.688 | 1332.880 | 876.868 |
| 12-2033 | 3.467 | 0.832 | 15.140 | 0.000 | 0.000 | 0.000 | 49.240 | 1382.120 | 890.467 |
| 12-2034 | 3.230 | 0.757 | 14.664 | 0.000 | 0.000 | 0.000 | 45.115 | 1427.236 | 901.794 |
| S TOT | 102.352 | 29.877 | 508.707 | 0.000 | 0.000 | 0.000 | 1427.236 | 1427.236 | 901.794 |
| AFTER | 24.288 | 3.760 | 102.749 | 0.000 | 0.000 | 0.000 | 327.361 | 1754.597 | 950.079 |
| TOTAL | 126.640 | 33.637 | 611.456 | 0.000 | 0.000 | 0.000 | 1754.597 | 1754.597 | 950.079 |
| P.W. % | P.W., |
| GROSS WELLS | 10.0 | 149.0 | LIFE, YRS. | 50.00 | 5.00 | 1229.128 | |||
| GROSS ULT., | MB & MMF | 113.696 | 11740.507 | DISCOUNT % | 10.00 | 10.00 | 950.079 | ||
| GROSS CUM., | MB & MMF | 75.118 | 11312.463 | UNDISCOUNTED PAYOUT, YRS. | 0.00 | 12.00 | 873.210 | ||
| GROSS RES., | MB & MMF | 38.578 | 428.044 | DISCOUNTED PAYOUT, YRS. | 0.00 | 15.00 | 780.864 | ||
| NET RES., | MB & MMF | 29.105 | 353.751 | UNDISCOUNTED NET/INVEST. | 0.00 | 20.00 | 668.042 | ||
| NET REVENUE, M$ | 1539.365 | 986.965 | DISCOUNTED NET/INVEST. | 0.00 | 25.00 | 587.496 | |||
| INITIAL PRICE, $ | 52.890 | 2.790 | RATE-OF-RETURN, PCT. | 100.00 | 40.00 | 441.917 | |||
| INITIAL N.I., PCT. | 78.567 | 85.807 | INITIAL W.I., PCT. | 95.761 | 60.00 | 342.979 | |||
| 80.00 | 286.295 | ||||||||
| 100.00 | 249.045 | ||||||||
THIS SCHEDULE IS PART OF A REPORT AND SUBJECT TO QUALIFICATIONS OF THE REPORT. LEE KEELING AND ASSOCIATES, INC.
| 1 |
| ESTIMATED RESERVES AND FUTURE NET REVENUE | DATE : 03/09/2020 |
| MOUNTAINEER STATE ENERGY | TIME : 14:51:24 |
| OHIO AND WEST VIRGINIA PROPERTIES | DBS : MountaineerSt |
| ALL RESERVES | SETTINGS : LKA0120 |
| Scenario : LKA0120 |
R E S E R V E S A N D E C O N O M I C S
AS OF DATE: 01/2020
--END-- MO-YEAR |
GROSS OIL PRODUCTION | GROSS GAS PRODUCTION | NET OIL PRODUCTION | NET GAS PRODUCTION | NET OIL PRICE | NET GAS PRICE | NET OIL SALES | NET GAS SALES | TOTAL NET SALES | |
| ------ | ---MBBLS--- | ---MMCF--- | ---MBBLS--- | ---MMCF--- | ---$/BBL--- | ---$/MCF--- | ---M$--- | ---M$--- | ---M$--- | |
| 12-2020 | 0.000 | 1.187 | 0.000 | 0.049 | 0.000 | 2.790 | 0.000 | 0.138 | 0.138 | |
| 12-2021 | 0.000 | 1.128 | 0.000 | 0.047 | 0.000 | 2.790 | 0.000 | 0.131 | 0.131 | |
| 12-2022 | 0.000 | 1.071 | 0.000 | 0.045 | 0.000 | 2.790 | 0.000 | 0.124 | 0.124 | |
| 12-2023 | 0.000 | 1.018 | 0.000 | 0.042 | 0.000 | 2.790 | 0.000 | 0.118 | 0.118 | |
| 12-2024 | 0.000 | 0.967 | 0.000 | 0.040 | 0.000 | 2.790 | 0.000 | 0.112 | 0.112 | |
| 12-2025 | 0.000 | 0.919 | 0.000 | 0.038 | 0.000 | 2.790 | 0.000 | 0.107 | 0.107 | |
| 12-2026 | 0.000 | 0.873 | 0.000 | 0.036 | 0.000 | 2.790 | 0.000 | 0.101 | 0.101 | |
| 12-2027 | 0.000 | 0.829 | 0.000 | 0.034 | 0.000 | 2.790 | 0.000 | 0.096 | 0.096 | |
| 12-2028 | 0.000 | 0.788 | 0.000 | 0.033 | 0.000 | 2.790 | 0.000 | 0.091 | 0.091 | |
| 12-2029 | 0.000 | 0.748 | 0.000 | 0.031 | 0.000 | 2.790 | 0.000 | 0.087 | 0.087 | |
| 12-2030 | 0.000 | 0.711 | 0.000 | 0.030 | 0.000 | 2.790 | 0.000 | 0.082 | 0.082 | |
| 12-2031 | 0.000 | 0.675 | 0.000 | 0.028 | 0.000 | 2.790 | 0.000 | 0.078 | 0.078 | |
| 12-2032 | 0.000 | 0.642 | 0.000 | 0.027 | 0.000 | 2.790 | 0.000 | 0.074 | 0.074 | |
| 12-2033 | 0.000 | 0.600 | 0.000 | 0.025 | 0.000 | 2.790 | 0.000 | 0.070 | 0.070 | |
| 12-2034 | 0.000 | 0.556 | 0.000 | 0.024 | 0.000 | 2.790 | 0.000 | 0.066 | 0.066 | |
| S TOT | 0.000 | 12.711 | 0.000 | 0.529 | 0.000 | 2.790 | 0.000 | 1.477 | 1.477 | |
| AFTER | 0.000 | 7.361 | 0.000 | 0.318 | 0.000 | 2.790 | 0.000 | 0.887 | 0.887 | |
| TOTAL | 0.000 | 20.072 | 0.000 | 0.847 | 0.000 | 2.790 | 0.000 | 2.364 | 2.364 | |
| --END-- | AD VALOREM | PRODUCTION | DIRECT OPER | INTEREST | CAPITAL | EQUITY | FUTURE NET | CUMULATIVE | CUM. DISC. | |
| MO-YEAR | TAX | TAX | EXPENSE | PAID | REPAYMENT | INVESTMENT | CASHFLOW | CASHFLOW | CASHFLOW | |
| ------ | ---M$--- | ---M$--- | ---M$--- | ---M$--- | ---M$--- | ---M$--- | ---M$--- | ---M$--- | ---M$--- | |
| 12-2020 | 0.007 | 0.002 | 0.000 | 0.000 | 0.000 | 0.000 | 0.129 | 0.129 | 0.123 | |
| 12-2021 | 0.007 | 0.002 | 0.000 | 0.000 | 0.000 | 0.000 | 0.122 | 0.251 | 0.229 | |
| 12-2022 | 0.007 | 0.002 | 0.000 | 0.000 | 0.000 | 0.000 | 0.116 | 0.367 | 0.320 | |
| 12-2023 | 0.006 | 0.001 | 0.000 | 0.000 | 0.000 | 0.000 | 0.110 | 0.477 | 0.399 | |
| 12-2024 | 0.006 | 0.001 | 0.000 | 0.000 | 0.000 | 0.000 | 0.105 | 0.582 | 0.467 | |
| 12-2025 | 0.006 | 0.001 | 0.000 | 0.000 | 0.000 | 0.000 | 0.100 | 0.681 | 0.526 | |
| 12-2026 | 0.005 | 0.001 | 0.000 | 0.000 | 0.000 | 0.000 | 0.095 | 0.776 | 0.577 | |
| 12-2027 | 0.005 | 0.001 | 0.000 | 0.000 | 0.000 | 0.000 | 0.090 | 0.866 | 0.621 | |
| 12-2028 | 0.005 | 0.001 | 0.000 | 0.000 | 0.000 | 0.000 | 0.085 | 0.951 | 0.659 | |
| 12-2029 | 0.005 | 0.001 | 0.000 | 0.000 | 0.000 | 0.000 | 0.081 | 1.032 | 0.692 | |
| 12-2030 | 0.004 | 0.001 | 0.000 | 0.000 | 0.000 | 0.000 | 0.077 | 1.109 | 0.720 | |
| 12-2031 | 0.004 | 0.001 | 0.000 | 0.000 | 0.000 | 0.000 | 0.073 | 1.182 | 0.745 | |
| 12-2032 | 0.004 | 0.001 | 0.000 | 0.000 | 0.000 | 0.000 | 0.070 | 1.252 | 0.766 | |
| 12-2033 | 0.004 | 0.001 | 0.000 | 0.000 | 0.000 | 0.000 | 0.066 | 1.318 | 0.784 | |
| 12-2034 | 0.004 | 0.001 | 0.000 | 0.000 | 0.000 | 0.000 | 0.062 | 1.379 | 0.799 | |
| S TOT | 0.080 | 0.018 | 0.000 | 0.000 | 0.000 | 0.000 | 1.379 | 1.379 | 0.799 | |
| AFTER | 0.048 | 0.011 | 0.000 | 0.000 | 0.000 | 0.000 | 0.828 | 2.208 | 0.891 | |
| TOTAL | 0.127 | 0.029 | 0.000 | 0.000 | 0.000 | 0.000 | 2.208 | 2.208 | 0.891 | |
| OIL | GAS | P.W. % | P.W., | M$ | ||||||
| GROSS WELLS | 0.0 | 23.0 | LIFE, YRS. | 50.00 | 5.00 | 1.278 | ||||
| GROSS ULT., MB & MMF | 0.000 | 21.361 | DISCOUNT % | 10.00 | 10.00 | 0.891 | ||||
| GROSS CUM., MB & MMF | 0.000 | 1.289 | UNDISCOUNTED PAYOUT, YRS. | 0.00 | 12.00 | 0.796 | ||||
| GROSS RES., MB & MMF | 0.000 | 20.072 | DISCOUNTED PAYOUT, YRS. | 0.00 | 15.00 | 0.687 | ||||
| NET RES., MB & MMF | 0.000 | 0.847 | UNDISCOUNTED NET/INVEST. | 0.00 | 20.00 | 0.563 | ||||
| NET REVENUE, M$ | 0.000 | 2.364 | DISCOUNTED NET/INVEST. | 0.00 | 25.00 | 0.479 | ||||
| INITIAL PRICE, $ | 0.000 | 2.790 | RATE-OF-RETURN, PCT. | 100.00 | 40.00 | 0.338 | ||||
| INITIAL N.I., PCT | 0.000 | 4.159 | INITIAL W.I., PCT. | 0.000 | 60.00 | 0.250 | ||||
| 80.00 | 0.203 | |||||||||
| 100.00 | 0.173 | |||||||||
THIS SCHEDULE IS PART OF A REPORT AND SUBJECT TO QUALIFICATIONS OF THE REPORT. LEE KEELING AND ASSOCIATES, INC.
| ESTIMATED RESERVES AND FUTURE NET REVENUE | DATE : 03/09/2020 |
| MOUNTAINEER STATE ENERGY | TIME : 14:51:25 |
| OHIO AND WEST VIRGINIA PROPERTIES | DBS : MountaineerSt |
| ALL RESERVES | SETTINGS : LKA0120 |
| Scenario : LKA0120 |
R E S E R V E S A N D E C O N O M I C S
AS OF DATE: 01/2020
--END-- MO-YEAR |
GROSS OIL PRODUCTION | GROSS GAS PRODUCTION | NET OIL PRODUCTION | NET GAS PRODUCTION | NET OIL PRICE | NET GAS PRICE | NET OIL SALES | NET GAS SALES | TOTAL NET SALES |
| ------ | ---MBBLS--- | ---MMCF--- | ---MBBLS--- | ---MMCF--- | ---$/BBL--- | ---$/MCF--- | ---M$--- | ---M$--- | ---M$--- |
| 12-2020 | 3.227 | 85.716 | 2.535 | 74.520 | 52.890 | 2.790 | 134.075 | 207.909 | 341.984 |
| 12-2021 | 2.929 | 77.743 | 2.293 | 67.631 | 52.890 | 2.790 | 121.289 | 188.691 | 309.979 |
| 12-2022 | 2.635 | 53.682 | 2.052 | 46.642 | 52.890 | 2.790 | 108.537 | 130.131 | 238.667 |
| 12-2023 | 2.323 | 25.577 | 1.794 | 22.100 | 52.890 | 2.790 | 94.903 | 61.658 | 156.561 |
| 12-2024 | 2.113 | 18.207 | 1.624 | 15.689 | 52.890 | 2.790 | 85.867 | 43.772 | 129.640 |
| 12-2025 | 1.980 | 16.529 | 1.518 | 14.251 | 52.890 | 2.790 | 80.311 | 39.761 | 120.072 |
| 12-2026 | 1.859 | 15.022 | 1.424 | 12.958 | 52.890 | 2.790 | 75.308 | 36.153 | 111.461 |
| 12-2027 | 1.749 | 13.667 | 1.338 | 11.792 | 52.890 | 2.790 | 70.754 | 32.901 | 103.655 |
| 12-2028 | 1.648 | 12.443 | 1.259 | 10.739 | 52.890 | 2.790 | 66.567 | 29.961 | 96.528 |
| 12-2029 | 1.554 | 11.336 | 1.185 | 9.785 | 52.890 | 2.790 | 62.698 | 27.300 | 89.999 |
| 12-2030 | 1.466 | 10.335 | 1.118 | 8.921 | 52.890 | 2.790 | 59.115 | 24.890 | 84.005 |
| 12-2031 | 1.385 | 9.428 | 1.054 | 8.138 | 52.890 | 2.790 | 55.772 | 22.705 | 78.478 |
| 12-2032 | 1.308 | 8.606 | 0.995 | 7.428 | 52.890 | 2.790 | 52.633 | 20.724 | 73.357 |
| 12-2033 | 1.236 | 7.860 | 0.939 | 6.783 | 52.890 | 2.790 | 49.683 | 18.926 | 68.608 |
| 12-2034 | 1.157 | 7.183 | 0.877 | 6.198 | 52.890 | 2.790 | 46.406 | 17.293 | 63.699 |
| S TOT | 28.567 | 373.335 | 22.006 | 323.576 | 52.890 | 2.790 | 1163.919 | 902.776 | 2066.694 |
| AFTER | 10.011 | 34.637 | 7.099 | 29.328 | 52.890 | 2.790 | 375.446 | 81.825 | 457.271 |
| TOTAL | 38.578 | 407.972 | 29.105 | 352.903 | 52.890 | 2.790 | 1539.365 | 984.601 | 2523.966 |
| --END-- | AD VALOREM | PRODUCTION | DIRECT OPER | INTEREST | CAPITAL | EQUITY | FUTURE NET | CUMULATIVE | CUM. DISC. |
| MO-YEAR | TAX | TAX | EXPENSE | PAID | REPAYMENT | INVESTMENT | CASHFLOW | CASHFLOW | CASHFLOW |
| ------ | ---M$--- | ---M$--- | ---M$--- | ---M$--- | ---M$--- | ---M$--- | ---M$--- | ---M$--- | ---M$--- |
|
12-2020 |
17.237 |
4.918 |
117.344 |
0.000 |
0.000 |
0.000 |
202.485 |
202.485 |
193.062 |
| 12-2021 | 15.613 | 4.474 | 117.344 | 0.000 | 0.000 | 0.000 | 172.549 | 375.034 | 342.625 |
| 12-2022 | 11.747 | 3.700 | 80.589 | 0.000 | 0.000 | 0.000 | 142.632 | 517.666 | 455.152 |
| 12-2023 | 7.291 | 2.809 | 27.371 | 0.000 | 0.000 | 0.000 | 119.091 | 636.757 | 540.507 |
| 12-2024 | 6.285 | 1.957 | 15.140 | 0.000 | 0.000 | 0.000 | 106.258 | 743.015 | 609.705 |
| 12-2025 | 5.846 | 1.776 | 15.140 | 0.000 | 0.000 | 0.000 | 97.310 | 840.325 | 667.315 |
| 12-2026 | 5.450 | 1.613 | 15.140 | 0.000 | 0.000 | 0.000 | 89.258 | 929.584 | 715.355 |
| 12-2027 | 5.091 | 1.466 | 15.140 | 0.000 | 0.000 | 0.000 | 81.958 | 1011.542 | 755.455 |
| 12-2028 | 4.763 | 1.332 | 15.140 | 0.000 | 0.000 | 0.000 | 75.293 | 1086.835 | 788.945 |
| 12-2029 | 4.462 | 1.211 | 15.140 | 0.000 | 0.000 | 0.000 | 69.186 | 1156.021 | 816.921 |
| 12-2030 | 4.184 | 1.102 | 15.140 | 0.000 | 0.000 | 0.000 | 63.580 | 1219.601 | 840.293 |
| 12-2031 | 3.926 | 1.003 | 15.140 | 0.000 | 0.000 | 0.000 | 58.409 | 1278.010 | 859.812 |
| 12-2032 | 3.687 | 0.913 | 15.140 | 0.000 | 0.000 | 0.000 | 53.618 | 1331.628 | 876.102 |
| 12-2033 | 3.463 | 0.831 | 15.140 | 0.000 | 0.000 | 0.000 | 49.175 | 1380.803 | 889.683 |
| 12-2034 | 3.226 | 0.756 | 14.664 | 0.000 | 0.000 | 0.000 | 45.054 | 1425.856 | 900.995 |
| S TOT | 102.272 | 29.859 | 508.707 | 0.000 | 0.000 | 0.000 | 1425.856 | 1425.856 | 900.995 |
| AFTER | 24.241 | 3.749 | 102.749 | 0.000 | 0.000 | 0.000 | 326.533 | 1752.389 | 949.188 |
| TOTAL | 126.513 | 33.608 | 611.456 | 0.000 | 0.000 | 0.000 | 1752.389 | 1752.389 | 949.188 |
| OIL | GAS | P.W. % | P.W.,M$ | ||||||
| GROSS WELLS | 0.0 | 23.0 | LIFE, YRS. | 50.00 | 5.00 | 1.278 | |||
| GROSS ULT., MB & MMF | 0.000 | 21.361 | DISCOUNT % | 10.00 | 10.00 | 0.891 | |||
| GROSS CUM., MB & MMF | 0.000 | 1.289 | UNDISCOUNTED PAYOUT, YRS. | 0.00 | 12.00 | 0.796 | |||
| GROSS RES., MB & MMF | 0.000 | 20.072 | DISCOUNTED PAYOUT, YRS. | 0.00 | 15.00 | 0.687 | |||
| NET RES., MB & MMF | 0.000 | 0.847 | UNDISCOUNTED NET/INVEST. | 0.00 | 20.00 | 0.563 | |||
| NET REVENUE, M$ | 0.000 | 2.364 | DISCOUNTED NET/INVEST. | 0.00 | 25.00 | 0.479 | |||
| INITIAL PRICE, $ | 0.000 | 2.790 | RATE-OF-RETURN, PCT. | 100.00 | 40.00 | 0.338 | |||
| INITIAL N.I., PCT | 0.000 | 4.159 | INITIAL W.I., PCT. | 0.000 | 60.00 | 0.250 | |||
| 80.00 | 0.203 | ||||||||
| 100.00 | 0.173 | ||||||||
THIS SCHEDULE IS PART OF A REPORT AND SUBJECT TO QUALIFICATIONS OF THE REPORT. LEE KEELING AND ASSOCIATES, INC.
| 3 |
SCHEDULE 2
ESTIMATED RESERVES AND FUTURE NET REVENUE
MOUNTAINEER STATE ENERGY, INC.
MAXIMUM TO MINIMUM LEASE SUMMARY
AS OF DECEMBER 31, 2019
|
ARIES I.D. |
LEASE |
RSV CAT |
STATE |
COUNTY |
LOCATION |
GROSS OIL MBO |
GROSS GAS MMCF |
NET OIL MBO |
NET GAS MMCF |
WORKING INTEREST |
REVENUE INTEREST |
CASHFLOW (M$) |
DISC. 10% (M$) |
NON-OPERATED |
|||||||||||||
|
254 |
BG/ROLLIN B COMBS #521 |
1PDP |
OH |
MORGAN |
0.000 |
4.751 |
0.000 |
0.260 |
0.000000 |
0.054688 |
0.677 |
0.256 | |
| 247 | LESLIE STEPHENSON #513 | 1PDP | OH | MORGAN | 0.000 | 2.807 | 0.000 | 0.154 | 0.000000 | 0.054688 | 0.400 | 0.151 | |
| 241 | CROSS #501 | 1PDP | WV | ROANE | 0.000 | 2.915 | 0.000 | 0.072 | 0.000000 | 0.024683 | 0.186 | 0.070 | |
| 250 | BG/SWANK-GARRIS #517 | 1PDP | OH | MORGAN | 0.000 | 1.171 | 0.000 | 0.064 | 0.000000 | 0.054688 | 0.167 | 0.070 | |
| 251 | BG/HAROLD SCOTT #518 | 1PDP | OH | MORGAN | 0.000 | 1.131 | 0.000 | 0.062 | 0.000000 | 0.054688 | 0.161 | 0.068 | |
| 258 | SWANT-WORTMAN #526 | 1PDP | OH | MORGAN | 0.000 | 0.703 | 0.000 | 0.045 | 0.000000 | 0.064401 | 0.118 | 0.054 | |
| 253 | OP/GARRIS-DRUMMO #520 | 1PDP | OH | MORGAN | 0.000 | 1.442 | 0.000 | 0.048 | 0.000000 | 0.033154 | 0.125 | 0.050 | |
| 249 | OP/SWANK-KEETON #516 | 1PDP | OH | MORGAN | 0.000 | 1.404 | 0.000 | 0.037 | 0.000000 | 0.026510 | 0.097 | 0.039 | |
| 246 | OD BAKER #511 | 1PDP | OH | MORGAN | 0.000 | 0.469 | 0.000 | 0.026 | 0.000000 | 0.054688 | 0.067 | 0.033 | |
| 252 | OP/COMBS-WILEY #519 | 1PDP | OH | MORGAN | 0.000 | 0.936 | 0.000 | 0.028 | 0.000000 | 0.029395 | 0.072 | 0.031 | |
| 242 | D ADAMS #505 | 1PDP | OH | MEIGS | 0.000 | 0.703 | 0.000 | 0.022 | 0.000000 | 0.031250 | 0.057 | 0.026 | |
| 243 | EDITH REED #506 | 1PDP | OH | MEIGS | 0.000 | 0.469 | 0.000 | 0.015 | 0.000000 | 0.031250 | 0.038 | 0.019 | |
| 244 | P STABLER #507 | 1PDP | OH | MEIGS | 0.000 | 0.235 | 0.000 | 0.007 | 0.000000 | 0.031250 | 0.019 | 0.012 | |
| 255 | OP/CLARENCE KEETO #522 | 1PDP | OH | MORGAN | 0.000 | 0.703 | 0.000 | 0.008 | 0.000000 | 0.011159 | 0.020 | 0.009 | |
| 248 | OP/GILLILAND-WORT #515 | 1PDP | OH | MORGAN | 0.000 | 0.235 | 0.000 | 0.001 | 0.000000 | 0.004553 | 0.003 | 0.002 | |
| 240 | JACKSON CO., WV #524 | 1PDP | WV | JACKSON | 0.000 | 0.000 | 0.000 | 0.000 | 0.000000 | 0.000000 | 0.000 | 0.000 | |
| 261 | MORGAN COUNTY #512 | 1PDP | OH | MORGAN | 0.000 | 0.000 | 0.000 | 0.000 | 0.000000 | 0.000000 | 0.000 | 0.000 | |
| 262 | MORGAN COUNTY #514 | 1PDP | OH | MORGAN | 0.000 | 0.000 | 0.000 | 0.000 | 0.000000 | 0.000000 | 0.000 | 0.000 | |
| 256 | OP/GILLARD-FISHER #523 | 1PDP | OH | MORGAN | 0.000 | 0.000 | 0.000 | 0.000 | 0.000000 | 0.000000 | 0.000 | 0.000 | |
| 259 | PLEASANTS COUNTY #509 | 1PDP | WV | PLEASANTS | 0.000 | 0.000 | 0.000 | 0.000 | 0.000000 | 0.000000 | 0.000 | 0.000 | |
| 260 | PLEASANTS COUNTY #510 | 1PDP | WV | PLEASANTS | 0.000 | 0.000 | 0.000 | 0.000 | 0.000000 | 0.000000 | 0.000 | 0.000 | |
| 257 | PLEASANTS COUNTY #525 | 1PDP | WV | PLEASANTS | 0.000 | 0.000 | 0.000 | 0.000 | 0.000000 | 0.000000 | 0.000 | 0.000 | |
| 245 | T WATKINS #508 | 1PDP | OH | MEIGS | 0.000 | 0.000 | 0.000 | 0.000 | 0.000000 | 0.000000 | 0.000 | 0.000 | |
| NON-OPERATED TOTAL | 0.000 | 20.072 | 0.000 | 0.847 | 2.208 | 0.891 |
THIS SCHEDULE IS PART OF A REPORT AND SUBJECT TO QUALIFICATIONS OF THE REPORT. LEE KEELING AND ASSOCIATES, INC.
| 1 |
ESTIMATED RESERVES AND FUTURE NET REVENUE
MOUNTAINEER STATE ENERGY, INC.
MAXIMUM TO MINIMUM LEASE SUMMARY
AS OF DECEMBER 31, 2019
|
ARIES I.D. |
LEASE |
RSV CAT |
STATE |
COUNTY |
LOCATION |
GROSS OIL MBO |
GROSS GAS MMCF |
NET OIL MBO |
NET GAS MMCF |
WORKING INTEREST |
REVENUE INTEREST |
CASHFLOW (M$) |
DISC. 10% (M$) | |
| OPERATED | ||||||||||||||
|
2 |
GUAL # 402 BEREA 402 |
1PDP |
OH |
MEIGS |
8.731 |
19.831 |
7.640 |
17.352 |
1.000000 |
0.875000 |
389.343 |
201.779 | ||
| 233 | JACKSON CO., WV #347 | 1PDP | WV | JACKSON | 0.000 | 193.354 | 0.000 | 169.185 | 1.000000 | 0.875000 | 313.077 | 196.837 | ||
| 221 | KARL RUSSELL #273 | 1PDP | OH | MEIGS | 9.731 | 6.618 | 8.515 | 5.790 | 1.000000 | 0.875000 | 394.079 | 182.530 | ||
| 1 | MYERS # 401 BEREA WELL 401 | 1PDP | OH | MEIGS | 12.080 | 10.577 | 5.919 | 5.183 | 0.560000 | 0.490000 | 279.821 | 122.045 | ||
| 11 | JIM ROUSH #178 | 1PDP | OH | MEIGS | 4.219 | 16.776 | 3.692 | 14.679 | 1.000000 | 0.875000 | 193.605 | 103.384 | ||
| 222 | ROGER GAUL #274 | 1PDP | OH | MEIGS | 0.483 | 9.392 | 0.423 | 8.218 | 1.000000 | 0.875000 | 38.788 | 34.701 | ||
| 230 | RUTH MYERS #181 | 1PDP | OH | MEIGS | 1.326 | 7.809 | 1.160 | 6.833 | 1.000000 | 0.875000 | 53.085 | 34.310 | ||
| 172 | MEIGS CO., OHIO - COMPOSITE | 1PDP | OH | MEIGS | 0.000 | 112.379 | 0.000 | 98.332 | 1.000000 | 0.875000 | 32.174 | 29.568 | ||
| 238 | F.BERL BOGGS #190 | 1PDP | OH | MEIGS | 0.468 | 1.876 | 0.409 | 1.641 | 1.000000 | 0.875000 | 19.660 | 16.831 | ||
| 6 | JAY BLACKWOOD #165 | 1PDP | OH | MEIGS | 0.821 | 4.379 | 0.719 | 3.832 | 1.000000 | 0.875000 | 21.241 | 13.836 | ||
| 8 | JIM BERNARD #167 | 1PDP | OH | MEIGS | 0.717 | 0.000 | 0.628 | 0.000 | 1.000000 | 0.875000 | 10.303 | 6.979 | ||
| 169 | ROANE CO., WV - COMPOSITE | 1PDP | WV | ROANE | 0.000 | 24.982 | 0.000 | 21.859 | 1.000000 | 0.875000 | 7.213 | 6.388 | ||
| 168 | ATHENS CO. OHIO - COMPOSIT | 1PDP | OH | ATHENS | 0.000 | 0.000 | 0.000 | 0.000 | 1.000000 | 0.875000 | 0.000 | 0.000 | ||
| 171 | CALHOUN CO., WV - COMPOSI | 1PDP | WV | CALHOUN | 0.000 | 0.000 | 0.000 | 0.000 | 1.000000 | 0.875000 | 0.000 | 0.000 | ||
| 170 | JACKSON CO., WV - COMPOSIT | 1PDP | WV | JACKSON | 0.000 | 0.000 | 0.000 | 0.000 | 1.000000 | 0.875000 | 0.000 | 0.000 | ||
| 7 | LLOYD BLACKWOOD #166 | 1PDP | OH | MEIGS | 0.000 | 0.000 | 0.000 | 0.000 | 0.000000 | 0.000000 | 0.000 | 0.000 | ||
| OPERATED TOTAL | 38.578 | 407.972 | 29.105 | 352.903 | 1,752.389 | 949.188 | ||||||||
| TOTAL PROVED RESERVES | 38.578 | 428.044 | 29.105 | 353.751 | 1,754.597 | 950.079 | ||||||||
THIS SCHEDULE IS PART OF A REPORT AND SUBJECT TO QUALIFICATIONS OF THE REPORT. LEE KEELING AND ASSOCIATES, INC.
| 2 |
Exhibit 99.1
SCHEDULE 3
|
ARIES I.D. |
LEASE |
RSV CAT |
STATE |
COUNTY |
LOCATION |
GROSS OIL MBO |
GROSS GAS MMCF |
NET OIL MBO |
NET GAS MMCF |
WORKING INTEREST |
REVENUE INTEREST |
CASHFLOW (M$) |
DISC. 10% (M$) |
| 168 | ATHENS CO. OHIO - COMPOSI | 1PDP | OH | ATHENS | 0.000 | 0.000 | 0.000 | 0.000 | 1.000000 | 0.875000 | 0.000 | 0.000 | |
| 251 | BG/HAROLD SCOTT #518 | 1PDP | OH | MORGAN | 0.000 | 1.131 | 0.000 | 0.062 | 0.000000 | 0.054688 | 0.161 | 0.068 | |
| 254 | BG/ROLLIN B COMBS #521 | 1PDP | OH | MORGAN | 0.000 | 4.751 | 0.000 | 0.260 | 0.000000 | 0.054688 | 0.677 | 0.256 | |
| 250 | BG/SWANK-GARRIS #517 | 1PDP | OH | MORGAN | 0.000 | 1.171 | 0.000 | 0.064 | 0.000000 | 0.054688 | 0.167 | 0.070 | |
| 171 | CALHOUN CO., WV - COMPOSI | 1PDP | WV | CALHOUN | 0.000 | 0.000 | 0.000 | 0.000 | 1.000000 | 0.875000 | 0.000 | 0.000 | |
| 241 | CROSS #501 | 1PDP | WV | ROANE | 0.000 | 2.915 | 0.000 | 0.072 | 0.000000 | 0.024683 | 0.186 | 0.070 | |
| 242 | D ADAMS #505 | 1PDP | OH | MEIGS | 0.000 | 0.703 | 0.000 | 0.022 | 0.000000 | 0.031250 | 0.057 | 0.026 | |
| 243 | EDITH REED #506 | 1PDP | OH | MEIGS | 0.000 | 0.469 | 0.000 | 0.015 | 0.000000 | 0.031250 | 0.038 | 0.019 | |
| 238 | F.BERL BOGGS #190 | 1PDP | OH | MEIGS | 0.468 | 1.876 | 0.409 | 1.641 | 1.000000 | 0.875000 | 19.660 | 16.831 | |
| 2 | GUAL # 402 BEREA 402 | 1PDP | OH | MEIGS | 8.731 | 19.831 | 7.640 | 17.352 | 1.000000 | 0.875000 | 389.343 | 201.779 | |
| 170 | JACKSON CO., WV - COMPOSI | 1PDP | WV | JACKSON | 0.000 | 0.000 | 0.000 | 0.000 | 1.000000 | 0.875000 | 0.000 | 0.000 | |
| 233 | JACKSON CO., WV #347 | 1PDP | WV | JACKSON | 0.000 | 193.354 | 0.000 | 169.185 | 1.000000 | 0.875000 | 313.077 | 196.837 | |
| 240 | JACKSON CO., WV #524 | 1PDP | WV | JACKSON | 0.000 | 0.000 | 0.000 | 0.000 | 0.000000 | 0.000000 | 0.000 | 0.000 | |
| 6 | JAY BLACKWOOD #165 | 1PDP | OH | MEIGS | 0.821 | 4.379 | 0.719 | 3.832 | 1.000000 | 0.875000 | 21.241 | 13.836 | |
| 8 | JIM BERNARD #167 | 1PDP | OH | MEIGS | 0.717 | 0.000 | 0.628 | 0.000 | 1.000000 | 0.875000 | 10.303 | 6.979 | |
| 11 | JIM ROUSH #178 | 1PDP | OH | MEIGS | 4.219 | 16.776 | 3.692 | 14.679 | 1.000000 | 0.875000 | 193.605 | 103.384 | |
| 221 | KARL RUSSELL #273 | 1PDP | OH | MEIGS | 9.731 | 6.618 | 8.515 | 5.790 | 1.000000 | 0.875000 | 394.079 | 182.530 | |
| 247 | LESLIE STEPHENSON #513 | 1PDP | OH | MORGAN | 0.000 | 2.807 | 0.000 | 0.154 | 0.000000 | 0.054688 | 0.400 | 0.151 | |
| 7 | LLOYD BLACKWOOD #166 | 1PDP | OH | MEIGS | 0.000 | 0.000 | 0.000 | 0.000 | 0.000000 | 0.000000 | 0.000 | 0.000 | |
| 172 | MEIGS CO., OHIO - COMPOSIT | 1PDP | OH | MEIGS | 0.000 | 112.379 | 0.000 | 98.332 | 1.000000 | 0.875000 | 32.174 | 29.568 | |
| 261 | MORGAN COUNTY #512 | 1PDP | OH | MORGAN | 0.000 | 0.000 | 0.000 | 0.000 | 0.000000 | 0.000000 | 0.000 | 0.000 | |
| 262 | MORGAN COUNTY #514 | 1PDP | OH | MORGAN | 0.000 | 0.000 | 0.000 | 0.000 | 0.000000 | 0.000000 | 0.000 | 0.000 | |
| 1 | MYERS # 401 BEREA WELL 40 | 1PDP | OH | MEIGS | 12.080 | 10.577 | 5.919 | 5.183 | 0.560000 | 0.490000 | 279.821 | 122.045 | |
| 246 | OD BAKER #511 | 1PDP | OH | MORGAN | 0.000 | 0.469 | 0.000 | 0.026 | 0.000000 | 0.054688 | 0.067 | 0.033 | |
| 255 | OP/CLARENCE KEETO #522 | 1PDP | OH | MORGAN | 0.000 | 0.703 | 0.000 | 0.008 | 0.000000 | 0.011159 | 0.020 | 0.009 | |
| 252 | OP/COMBS-WILEY #519 | 1PDP | OH | MORGAN | 0.000 | 0.936 | 0.000 | 0.028 | 0.000000 | 0.029395 | 0.072 | 0.031 | |
| 253 | OP/GARRIS-DRUMMO #520 | 1PDP | OH | MORGAN | 0.000 | 1.442 | 0.000 | 0.048 | 0.000000 | 0.033154 | 0.125 | 0.050 | |
| 256 | OP/GILLARD-FISHER #523 | 1PDP | OH | MORGAN | 0.000 | 0.000 | 0.000 | 0.000 | 0.000000 | 0.000000 | 0.000 | 0.000 |
THIS SCHEDULE IS PART OF A REPORT AND SUBJECT TO QUALIFICATIONS OF THE REPORT. LEE KEELING AND ASSOCIATES, INC.
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ARIES I.D. |
LEASE |
RSV CAT |
STATE |
COUNTY |
LOCATION |
GROSS OIL MBO |
GROSS GAS MMCF |
NET OIL MBO |
NET GAS MMCF |
WORKING INTEREST |
REVENUE INTEREST |
CASHFLOW (M$) |
DISC. 10% (M$) | |
| 248 | OP/GILLILAND-WORT #515 | 1PDP | OH | MORGAN | 0.000 | 0.235 | 0.000 | 0.001 | 0.000000 | 0.004553 | 0.003 | 0.002 | ||
| 249 | OP/SWANK-KEETON #516 | 1PDP | OH | MORGAN | 0.000 | 1.404 | 0.000 | 0.037 | 0.000000 | 0.026510 | 0.097 | 0.039 | ||
| 244 | P STABLER #507 | 1PDP | OH | MEIGS | 0.000 | 0.235 | 0.000 | 0.007 | 0.000000 | 0.031250 | 0.019 | 0.012 | ||
| 259 | PLEASANTS COUNTY #509 | 1PDP | WV | PLEASANTS | 0.000 | 0.000 | 0.000 | 0.000 | 0.000000 | 0.000000 | 0.000 | 0.000 | ||
| 260 | PLEASANTS COUNTY #510 | 1PDP | WV | PLEASANTS | 0.000 | 0.000 | 0.000 | 0.000 | 0.000000 | 0.000000 | 0.000 | 0.000 | ||
| 257 | PLEASANTS COUNTY #525 | 1PDP | WV | PLEASANTS | 0.000 | 0.000 | 0.000 | 0.000 | 0.000000 | 0.000000 | 0.000 | 0.000 | ||
| 169 | ROANE CO., WV - COMPOSITE | 1PDP | WV | ROANE | 0.000 | 24.982 | 0.000 | 21.859 | 1.000000 | 0.875000 | 7.213 | 6.388 | ||
| 222 | ROGER GAUL #274 | 1PDP | OH | MEIGS | 0.483 | 9.392 | 0.423 | 8.218 | 1.000000 | 0.875000 | 38.788 | 34.701 | ||
| 230 | RUTH MYERS #181 | 1PDP | OH | MEIGS | 1.326 | 7.809 | 1.160 | 6.833 | 1.000000 | 0.875000 | 53.085 | 34.310 | ||
| 258 | SWANT-WORTMAN #526 | 1PDP | OH | MORGAN | 0.000 | 0.703 | 0.000 | 0.045 | 0.000000 | 0.064401 | 0.118 | 0.054 | ||
| 245 | T WATKINS #508 | 1PDP | OH | MEIGS | 0.000 | 0.000 | 0.000 | 0.000 | 0.000000 | 0.000000 | 0.000 | 0.000 | ||
| TOTAL PROVED RESERVES | 38.578 | 428.044 | 29.105 | 353.751 | 1,754.597 | 950.079 | ||||||||
THIS SCHEDULE IS PART OF A REPORT AND SUBJECT TO QUALIFICATIONS OF THE REPORT. LEE KEELING AND ASSOCIATES, INC.
Page 2 of 2
D. NOTES RECEIVABLE |
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| Receivables [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| NOTES RECEIVABLE | NOTE D– NOTES RECEIVABLE
Notes Receivable are comprised of the following (in thousands):
The Company holds a note receivable from a non related party. The original note was $415,000 payable in 120 monthly payments at 6% interest. Balance due at December 31, 2019 is $255,000 with $41,000 due currently. |
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H. STOCKHOLDERS' EQUITY |
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Dec. 31, 2019 | |||||||||||||||||||||||||||||||||||||
| Equity [Abstract] | |||||||||||||||||||||||||||||||||||||
| STOCKHOLDERS' EQUITY | NOTE H – STOCKHOLDERS’ EQUITY
Outstanding Preferred Stock
Preferred stock consists of the following (amounts in thousands):
The Series B preferred stock has a liquidation value of $100 per share. The right to convert expired April 30, 2003. Dividends at a rate of 6% are payable in cash or preferred shares at the option of the Company.
Outstanding Common Stock
On December 4, 2018, the Company issued an additional 3,000,000 shares of Common Stock to Realty Advisors, Inc. (“RAI”) a related party, for cash of $4,500,000 to increase stockholders’ equity by $4,440,000 after issuance costs. The issuance of 3,000,000 shares of Common Stock resulted in a change in control of the Company, as RAI now owns approximately 59.6% of the outstanding Common Stock. The issuance of the 3,000,000 shares of Common Stock to RAI increased the total number of shares issued and outstanding to 5,131,935 shares. |
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L. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) |
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Dec. 31, 2019 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Extractive Industries [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) | NOTE L - SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
The following table reflects revenues and expenses directly associated with our oil and gas producing activities, including general and administrative expenses directly related to such producing activities. They do not include any allocation of interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net earnings of our oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil and gas sales after deducting costs, including depreciation, depletion and amortization and after giving effect to permanent differences.
In 2019 pursuant to the requirements of the “full cost ceiling test” for oil & gas companies we recorded a non-cash charge to operations of $2.3 million to write down its investment in West Virginia. In September 2019 the Company unsuccessfully drilled a well which resulted in dry hole. As the well did not prove up the estimated probable and possible reserves, the Company had to deem the applicable reserve estimates as impaired. In the third quarter the company booked an impairment expense of $2.3 which represents a reduction of both the estimated probable and possible reserves as well as the cost of drilling the failed well. This charge to earnings was caused by a revaluation of the Company’s non- producing oil and gas reserves.
The following table reflects the standardized measure of future net cash flows related to our proved reserves
(1) Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves are as likely as not to be recovered. (2) Possible reserves are those additional reserves that are less certain to be recovered than probable reserves
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F. NOTES PAYABLE (Details Narrative) |
12 Months Ended |
|---|---|
Dec. 31, 2019 | |
| Debt Disclosure [Abstract] | |
| Debt interest rate range | 5% to 5 1/2% |
D. NOTES RECEIVABLE (Details Narrative) - USD ($) $ in Thousands |
3 Months Ended | ||
|---|---|---|---|
Mar. 31, 2019 |
Apr. 01, 2020 |
Dec. 31, 2019 |
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| Receivables [Abstract] | |||
| Note Receivable Original Balance | $ 415 | ||
| Terms of Note Receivable | The original note was $415,000 payable in 120 monthly payments at 6% interest | ||
| Interest Rate on Note Receivable | 6.00% | ||
| Note Receivable | $ 41 | $ 255 |
Document and Entity Information - shares |
12 Months Ended | |
|---|---|---|
Dec. 31, 2019 |
Mar. 27, 2020 |
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| Document And Entity Information | ||
| Entity Registrant Name | New Concept Energy, Inc. | |
| Entity Central Index Key | 0000105744 | |
| Document Type | 10-K | |
| Document Period End Date | Dec. 31, 2019 | |
| Amendment Flag | false | |
| Current Fiscal Year End Date | --12-31 | |
| Is Entity a Well-known Seasoned Issuer? | No | |
| Is Entity a Voluntary Filer? | No | |
| Is Entity's Reporting Status Current? | Yes | |
| Is Entity Emerging Growth Company? | false | |
| Entity Filer Category | Smaller Reporting Company | |
| Entity Small Business | true | |
| Entity Common Stock, Shares Outstanding | 5,131,934 | |
| Document Fiscal Period Focus | FY | |
| Document Fiscal Year Focus | 2019 | |
| Entity Shell Company | false |
C. RELATED PARTIES |
12 Months Ended |
|---|---|
Dec. 31, 2019 | |
| Related Party Transactions [Abstract] | |
| RELATED PARTIES | NOTE C– RELATED PARTIES
Commencing in February 2008, three publicly traded entities needed a chief financial officer, American Realty Investors, Inc. (“ARL”), Transcontinental Realty Investors, Inc. (“TCI”) and Income Opportunity Realty Investors, Inc. (“IOR”), Mr. Bertcher, is a certified public accountant and has a long history in their industry. New Concept made arrangements with the three entities whereby, in addition to his responsibilities to New Concept Mr. Bertcher would be Chief Financial Officer for the three entities. Mr. Bertcher was paid directly for such services by the contractual advisor for the three companies. Mr. Bertcher resigned as an officer of American Realty Investors, Inc. (“ARI”) and Transcontinental Realty Investors, Inc. (“TCI”) on June 30, 2019, but continued on as an officer of Income Opportunity Realty Investors, Inc. (“IOR”).
Beginning in 2011 Pillar Income Asset Management (“Pillar”) became the contractual advisor to the three publically traded entities. Pillar is a wholly owned subsidiary of RAI. In addition to the relationship with Mr. Bertcher, New Concept conducts business with Pillar whereby Pillar provided the Company with services including processing payroll, acquiring insurance and other administrative matters. The Company believes that by purchasing these services through certain large entities it can get lower costs and better service. Pillar does not charge the Company a fee for providing these services. The Company reimburses Pillar for the direct cost for such services. In December 2019 the Company had accumulated a balance due to Pillar of approximately $450,000 which was repaid from the proceeds of a stock offering. Mr. Bertcher was an officer of Pillar until June 30, 2019.
Realty Advisors, Inc., (“RAI”) is a privately owned investment company and by virtue of its stock ownership, the controlling shareholder for the three public entities. Mr. Bertcher was an officer of RAI until June 30, 2019. |
D. Notes Receivable (Tables) |
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| Receivables [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Notes Receivable [Table Text Block] |
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H. STOCKHOLDERS' EQUITY (Table) |
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Dec. 31, 2019 | |||||||||||||||||||||||||||||||||||||
| Equity [Abstract] | |||||||||||||||||||||||||||||||||||||
| Schedule of Preferred Stock |
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M. ASSET RETIREMENT OBLIGATION (Details) - USD ($) $ in Thousands |
12 Months Ended | |
|---|---|---|
Dec. 31, 2019 |
Dec. 31, 2018 |
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| Asset Retirement Obligation Disclosure [Abstract] | ||
| Asset retirement obligation, January 1 | $ 2,770 | |
| Acquisition of oil and gas properties | ||
| Revisions in the estimated cash flows | ||
| Liability incurred upon acquiring and drilling wells | ||
| Liability settled upon plugging and abandoning wells | ||
| Accretion of discount expense | ||
| Asset retirement obligation, December 31 | $ 2,770 | $ 2,770 |
K. QUARTERLY DATA (UNAUDITED) (Details) - USD ($) $ / shares in Units, $ in Thousands |
3 Months Ended | 12 Months Ended | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2019 |
Sep. 30, 2019 |
Jun. 30, 2019 |
Mar. 31, 2019 |
Dec. 31, 2018 |
Sep. 30, 2018 |
Jun. 30, 2018 |
Mar. 31, 2018 |
Dec. 31, 2017 |
Sep. 30, 2017 |
Jun. 30, 2017 |
Mar. 31, 2017 |
Dec. 31, 2019 |
Dec. 31, 2018 |
Dec. 31, 2017 |
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| Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||
| Revenue | $ 119 | $ 127 | $ 164 | $ 180 | $ 138 | $ 167 | $ 173 | $ 204 | $ 159 | $ 194 | $ 243 | $ 195 | $ 590 | $ 682 | $ 791 |
| Operating (expense) | (100) | (176) | (231) | (179) | (144) | (186) | (239) | (275) | (261) | (254) | (256) | (256) | (3,383) | (1,197) | (4,061) |
| Corporate general and administrative expense | (98) | (92) | (134) | (88) | (71) | (99) | (108) | (75) | (91) | (95) | (122) | (100) | (412) | (353) | (408) |
| Impairment of natural gas and oil properties | 2,285 | 2,626 | (2,285) | (2,626) | |||||||||||
| Other income (expense) net | 62 | 106 | 60 | 213 | 22 | (3) | 12 | (30) | 65 | 11 | (11) | 441 | 31 | 29 | |
| Net income (loss) from continuing operations | (2,849) | (90) | (124) | (172) | (2,551) | (484) | (3,241) | ||||||||
| Net income (loss) from discontinued operations | (2) | (11) | (11) | 13 | (5) | ||||||||||
| Income (loss) allocable to common shareholders | $ (17) | $ (2,320) | $ (141) | $ 126 | $ (55) | $ (121) | $ (174) | $ (134) | $ (2,851) | $ (101) | $ (135) | $ (159) | $ (2,352) | $ (484) | $ (3,246) |
| Income (loss) per common share - basic | $ 0.00 | $ (0.45) | $ (0.03) | $ 0.02 | $ 0.00 | $ (0.06) | $ (0.08) | $ (0.07) | $ (1.39) | $ (0.05) | $ (0.07) | $ (0.08) | |||
E. FIXED ASSETS (Tables) |
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| Property, Plant and Equipment [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of fixed assets |
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J. OPERATING SEGMENTS (Tables) |
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| Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Segment Reporting |
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M. ASSET RETIREMENT OBLIGATION |
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| Asset Retirement Obligation Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||
| ASSET RETIREMENT OBLIGATION | NOTE M – ASSET RETIREMENT OBLIGATION
The Company records an asset retirement obligation (ARO) when the total depth of a drilled well is reached and the Company can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs. The Company records the ARO liability on the consolidated balance sheets and capitalizes a portion of the cost in “Oil and natural gas properties” during the period in which the obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date and adjusted for the Company’s credit risk. This amount is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for the Company. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds. The additional capitalized costs are depreciated on a unit-of-production basis or straight-line basis.
In 2012, the Company re-evaluated its method of plugging abandoned wells and determined by doing so in-house it could lower the cost. Based upon the Company’s current calculations, we have established a sufficient reserve, for accounting purposes, to plug the existing wells when necessary.
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E. FIXED ASSETS |
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| Property, Plant and Equipment [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| E. FIXED ASSETS | NOTE E – FIXED ASSETS AND OIL AND NATURAL GAS PROPERTIES
Land, building and furniture, fixtures and equitpment are recorded at cost incurred to acquire the assets.
At December 31, 2019, fixed assets are as follows:
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I. CONTINGENCIES |
12 Months Ended |
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Dec. 31, 2019 | |
| Commitments and Contingencies Disclosure [Abstract] | |
| CONTINGENCIES | NOTE I – CONTINGENCIES
The Company has been named as a defendant in lawsuits in the ordinary course of business. Management is of the opinion that these lawsuits will not have a material effect on the financial condition, results of operations or cash flows of the Company. |
B. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
12 Months Ended |
|---|---|
Dec. 31, 2019 | |
| Accounting Policies [Abstract] | |
| SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | NOTE B - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows:
Principles of Consolidation
The consolidated financial statements include the accounts of New Concept Energy, Inc. and its majority-owned subsidiaries (collectively, the “Company”, New Concept or “NCE”) and are prepared on the basis of accounting principles generally accepted in the United States of America “GAAP”. All significant intercompany transactions and accounts have been eliminated. Certain accounting balances have been reclassified to conform to the current year presentation.
Depreciation
Depreciation is provided for in amounts sufficient to relate the cost of property and equipment to operations over their estimated service lives, ranging from 3 to 40 years. Depreciation is computed by the straight-line method.
Depreciation expense, which is included in operations, was $20,000, $43,000 and $55,000 for 2019, 2018 and 2017, respectively.
Depreciation, Depletion and Amortization of Oil & Gas Properties
Depreciation, depletion and amortization (“DD&A”) of producing properties is computed on the unit-of-production method based on estimated oil and gas reserves. While total DD&A expense for the life of a property is limited to the property’s total cost, reserve revisions result in a change in timing of when DD&A expense is recognized.
The Company recorded depletion of mineral rights of $61,000, $204,000 and $259,000 in 2019, 2018 and 2017 respectively.
Segments
The Company operates one primary business segment: oil and gas operations. Segment data is provided in “Note H” to these consolidated financial statements.
Major Purchaser
The Company sells most of its natural gas production to one purchaser and all of its oil production to one purchaser. While there is an available market for crude oil and natural gas production, we cannot be assured that the loss of this purchaser would not have a material impact on the Company.
Oil and Gas Reserves
Our oil and gas reserves are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof, including evaluations and extrapolations of well flow rates and reservoir pressure. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because reserves are required to be estimated using recent prices of the evaluation, estimated reserve quantities can be significantly impacted by changes in product prices.
The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include using recent oil and gas prices and year-end costs for estimated future development and production expenditures. Discounted future net cash flows are calculated using a 10% rate. Changes in any of these assumptions could have a significant impact on the standardized measure. Accordingly, the standardized measure does not represent management’s estimated current market value of reserves.
Full cost accounting
The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas properties (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred.
The full cost method requires the Company to calculate quarterly, by cost center, a “ceiling,” or limitation on the amount of properties that can be capitalized on the balance sheet. To the extent capitalized costs of oil and natural gas properties, less accumulated depletion and related deferred taxes exceed the sum of the discounted future net revenues of proved oil and natural gas reserves, the lower of cost or estimated fair value of unproved properties subject to amortization, the cost of properties not being amortized, and the related tax amounts, such excess capitalized costs are charged to expense. Beginning December 31, 2009, full cost companies use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date to calculate the future net revenues of reserves. Prior to December 31, 2009, companies used the price in effect at the calculation date and had the option, under certain circumstances, to elect to use subsequent commodity prices if they increased after the calculation date.
The Company assesses any unproved oil and gas properties on an annual basis for possible impairment or reduction in value. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of reserves; and the economic viability of development if reserves are assigned. During any period in which these factors indicate an impairment of unproved properties not subject to amortization, the associated costs incurred to date for such properties are then included in unproved properties subject to amortization.
Gas gathering assets
Gas gathering assets are capitalized as part of the depletable pool and ratably charged to earnings along with other capitalized exploration, drilling and development costs.
Office and field equipment
Office and field equipment are capitalized at cost and depreciated on a straight line basis over their estimated useful lives. Office and field equipment useful lives range from 5 to 30 years.
Revenue recognition and gas imbalances
We use the sales method of accounting for oil and natural gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. Gas imbalances at December 31, 2019 were not significant. New Concept also follows the sales method of accounting for natural gas production imbalances and would recognize a liability if the existing reserves were not adequate to cover an imbalance.
Accounting for Leases
Leases of property, plant and equipment where the Company assumes substantially all the benefits and risks of ownership are classified as finance leases. Finance leases are capitalized at the estimated present value of the underlying lease payments. Each lease payment is allocated between the liability and finance charges so as to achieve a constant rate on the finance balance outstanding. The corresponding rental obligations, net of finance charges, are included in other long-term payables. The interest element of the finance charge is charged to the income statement over the lease period. Property, plant and equipment acquired under finance leasing contracts are depreciated over the useful life of the asset. Leases of assets under which all the risks and benefits of ownership are effectively retained by the lessor are classified as operating leases. Payments made under operating leases are charged to the income statement on a straight-line basis over the period of the lease. When an operating lease is terminated before the lease period has expired, any payment required to be made to the lessor by way of penalty is recognized as an expense in the period in which termination takes place.
Revenue Recognition
Rental income for residential property leases is recorded when due from residents and is recognized monthly as it is earned, which is not materially different than on a straight-line basis as lease terms are generally for periods of one year or less.
Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. Costs associated with revenues are recorded in cost of revenues. Production volumes of natural gas are sold immediately and transported via pipeline. Royalties on the production of natural gas either paid in cash or settled through the delivery of volumes. The Company includes royalties in its revenues and cost of revenues when settlement of the royalties is paid in cash, while royalties settled by the delivery of volumes are excluded from revenues and cost of revenues.
The Company follows the sales method of accounting for natural gas production imbalances and would recognize a liability if the existing reserves were not adequate to cover an imbalance.
Use of Estimates
In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash Equivalents
The Company considers all short-term deposits and money market investments with a maturity of less than three months to be cash equivalents.
Other Intangible Assets
The cost of acquired patents, trademarks and licenses is capitalized and amortized using the straight-line method over their useful lives. The carrying amount of each intangible asset is reviewed annually and adjusted for permanent impairment where it is considered necessary.
Impairment of Notes Receivable
Notes receivable are identified as impaired when it is probable that interest and principal will not be collected according to the contractual terms of the note agreements. The accrual of interest is discontinued on such notes, and no income is recognized until all past due amounts of principal and interest are recovered in full.
Impairment of Long-Lived Assets
The Company reviews its long-lived assets and certain identifiable intangibles for impairment when events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. In reviewing recoverability, the Company estimates the future cash flows expected to result from use of the assets and eventually disposing of them. If the sum of the expected future cash flows (undiscounted and without interest charges) is less than the carrying amount of the asset, an impairment loss is recognized based on the asset’s fair value.
The Company determines the fair value of assets to be disposed of and records the asset at the lower of fair value less disposal costs or carrying value. Assets are not depreciated while held for disposal.
Sales of Real Estate
Gains on sales of real estate are recognized to the extent permitted by Accounting Standards Codification Topic 360-20, “Real Estate Sales – Real Estate Sales”, (“ASC 360-20”). Until the requirements of ASC 360-20 have been met for full profit recognition, sales are accounted for by the installment or cost recovery method, whichever is appropriate.
Real Estate Held for Sale
Accounting Standards Codification Topic 360, “Property, Plant, & Equipment” (“ASC 360”)requires that properties held for sale be reported at the lower of carrying amount or fair value less costs of sale. If a reduction in a held for sale property’s carrying amount to fair value less costs of sale is required, a provision for loss is recognized by a charge against earnings. Subsequent revisions, either upward or downward, to a held for sale property’s estimated fair value less costs of sale are recorded as an adjustment to the property’s carrying amount, but not in excess of the property’s carrying amount when originally classified as held for sale. A corresponding charge against or credit to earnings is recognized. Properties held for sale are not depreciated.
Asset Retirement Obligation
The Company records an asset retirement obligation liability on the consolidated balance sheets and capitalizes a portion of the cost in “Oil and natural gas properties” during the period in which the obligation is incurred. The asset retirement obligation is further described in Note K. Income Taxes The Company accounts for income taxes in accordance with Accounting Standards Codification, (“ASC”) No. 740, “Accounting for Income Taxes”. ASC 740 requires an asset and liability approach to financial accounting for income taxes. In the event differences between the financial reporting basis and the tax basis of the Company’s assets and liabilities result in deferred tax assets, ASC 740 requires an evaluation of the probability of being able to realize the future benefits indicated by such assets. A valuation allowance is provided for a portion or all of the deferred tax assets when there is an uncertainty regarding the Company’s ability to recognize the benefits of the assets in future years. Recognition of the benefits of deferred tax assets will require the Company to generate future taxable income. There is no assurance that the Company will generate earnings in future years. Since management could not determine the likelihood that the benefit of the deferred tax asset would be realized, no deferred tax asset was recognized by the Company.
Recent Accounting Pronouncements
In December 2019, the FASB issued ASU 2019-12. Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. The amendments in this Update simplify the accounting for income taxes by removing certain exceptions from ASC 740. Also, the amendments in this Update simplify the accounting for income tax by requiring that an entity recognize a franchise tax (or similar tax) that is partially based on income as an income-based tax, requiring that an entity evaluate when a step up in the tax basis of goodwill should be considered part of the business combination, and other targeted changes. The effective date of the amendments is for fiscal years, and interim periods within those years, beginning after December 15, 2020. The Company is currently evaluating the impact that the adoption of ASU 2019-12 may have on its consolidated financial statements. |
F. NOTES PAYABLE (Details - Debt maturities) - USD ($) $ in Thousands |
Dec. 31, 2019 |
Dec. 31, 2018 |
|---|---|---|
| Debt Disclosure [Abstract] | ||
| Principal maturity 2019 | $ 44 | |
| Principal maturity 2020 | 36 | |
| Principal maturity 2021 | 32 | |
| Principal maturity 2022 | 29 | |
| Principal maturity 2023 | 26 | |
| Principal maturity Thereafter | 78 | |
| Total long term debt | 245 | |
| Deferred borrowing costs | (24) | $ (29) |
| Total long term debt | $ 221 |
D. NOTES RECEIVABLE (Details) - USD ($) $ in Thousands |
12 Months Ended | |
|---|---|---|
Dec. 31, 2019 |
Dec. 31, 2018 |
|
| Receivable, Gross | $ 4,260 | $ 4,314 |
| less: current portion of notes receivable | 4,046 | 4,063 |
| Notes Receivable | 214 | 251 |
| American Realty Investors | ||
| Receivable, Gross | $ 4,005 | $ 4,017 |
| Receivable, Interest Rate | 6.00% | 6.00% |
| Third Party | ||
| Receivable, Gross | $ 255 | $ 297 |
| Receivable, Interest Rate | 6.00% | 6.00% |
L. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT (Details - Oil and gas operations) - USD ($) $ in Thousands |
3 Months Ended | 12 Months Ended | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2019 |
Sep. 30, 2019 |
Jun. 30, 2019 |
Mar. 31, 2019 |
Dec. 31, 2018 |
Sep. 30, 2018 |
Jun. 30, 2018 |
Mar. 31, 2018 |
Dec. 31, 2017 |
Sep. 30, 2017 |
Jun. 30, 2017 |
Mar. 31, 2017 |
Dec. 31, 2019 |
Dec. 31, 2018 |
Dec. 31, 2017 |
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| Extractive Industries [Abstract] | |||||||||||||||
| Oil and gas sales | $ 590 | $ 682 | |||||||||||||
| Operating expenses | (599) | (597) | |||||||||||||
| Depreciation, depletion and amortization | (87) | (247) | |||||||||||||
| Impairment of oil and gas properties | $ 2,285 | $ 2,626 | (2,285) | $ (2,626) | |||||||||||
| Results of operations | $ (2,381) | $ (162) | |||||||||||||
H. STOCKHOLDERS' EQUITY (Details Narrative) - USD ($) $ / shares in Units, $ in Thousands |
12 Months Ended | |
|---|---|---|
Dec. 31, 2019 |
Dec. 31, 2018 |
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| Series B convertible preferred stock, par value | $ 10 | $ 10 |
| Series B convertible preferred stock, liquidation value | $ 100 | $ 100 |
| Series B convertible preferred stock, shares authorized | 100 | 100 |
| Series B convertible preferred stock, shares issued | 1 | 1 |
| Series B convertible preferred stock, shares outstanding | 1 | 1 |
| Dividend rate | 6.00% | |
| Common stock issued | 5,131,934 | 5,131,934 |
| Cash received | $ 4,500,000 | |
| Shareholders equity increase | $ 4,400,000 | |
| Realty Advisors, Inc. [Member] | ||
| Common stock issued | 3,000,000 |
B. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (POLICIES) |
12 Months Ended |
|---|---|
Dec. 31, 2019 | |
| Accounting Policies [Abstract] | |
| Principles of Consolidation | Principles of Consolidation
The consolidated financial statements include the accounts of New Concept Energy, Inc. and its majority-owned subsidiaries (collectively, the “Company”, New Concept or “NCE”) and are prepared on the basis of accounting principles generally accepted in the United States of America “GAAP”. All significant intercompany transactions and accounts have been eliminated. Certain accounting balances have been reclassified to conform to the current year presentation.
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| Depreciation | Depreciation
Depreciation is provided for in amounts sufficient to relate the cost of property and equipment to operations over their estimated service lives, ranging from 3 to 40 years. Depreciation is computed by the straight-line method.
Depreciation expense, which is included in operations, was $20,000, $43,000 and $55,000 for 2019, 2018 and 2017, respectively.
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| Depreciation, Depletion and Amortization of Producing Oil & Gas Properties | Depreciation, Depletion and Amortization of Oil & Gas Properties
Depreciation, depletion and amortization (“DD&A”) of producing properties is computed on the unit-of-production method based on estimated oil and gas reserves. While total DD&A expense for the life of a property is limited to the property’s total cost, reserve revisions result in a change in timing of when DD&A expense is recognized.
The Company recorded depletion of mineral rights of $61,000, $204,000 and $259,000 in 2019, 2018 and 2017 respectively.
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| Segments | Segments
The Company operates one primary business segment: oil and gas operations. Segment data is provided in “Note H” to these consolidated financial statements.
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| Major Purchaser | Major Purchaser
The Company sells most of its natural gas production to one purchaser and all of its oil production to one purchaser. While there is an available market for crude oil and natural gas production, we cannot be assured that the loss of this purchaser would not have a material impact on the Company.
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| Oil and Gas Reserves | Oil and Gas Reserves
Our oil and gas reserves are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof, including evaluations and extrapolations of well flow rates and reservoir pressure. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because reserves are required to be estimated using recent prices of the evaluation, estimated reserve quantities can be significantly impacted by changes in product prices.
The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include using recent oil and gas prices and year-end costs for estimated future development and production expenditures. Discounted future net cash flows are calculated using a 10% rate. Changes in any of these assumptions could have a significant impact on the standardized measure. Accordingly, the standardized measure does not represent management’s estimated current market value of reserves.
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| Full cost accounting | Full cost accounting
The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas properties (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred.
The full cost method requires the Company to calculate quarterly, by cost center, a “ceiling,” or limitation on the amount of properties that can be capitalized on the balance sheet. To the extent capitalized costs of oil and natural gas properties, less accumulated depletion and related deferred taxes exceed the sum of the discounted future net revenues of proved oil and natural gas reserves, the lower of cost or estimated fair value of unproved properties subject to amortization, the cost of properties not being amortized, and the related tax amounts, such excess capitalized costs are charged to expense. Beginning December 31, 2009, full cost companies use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date to calculate the future net revenues of reserves. Prior to December 31, 2009, companies used the price in effect at the calculation date and had the option, under certain circumstances, to elect to use subsequent commodity prices if they increased after the calculation date.
The Company assesses any unproved oil and gas properties on an annual basis for possible impairment or reduction in value. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of reserves; and the economic viability of development if reserves are assigned. During any period in which these factors indicate an impairment of unproved properties not subject to amortization, the associated costs incurred to date for such properties are then included in unproved properties subject to amortization.
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| Gas gathering assets | Gas gathering assets
Gas gathering assets are capitalized as part of the depletable pool and ratably charged to earnings along with other capitalized exploration, drilling and development costs.
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| Office and field equipment | Office and field equipment
Office and field equipment are capitalized at cost and depreciated on a straight line basis over their estimated useful lives. Office and field equipment useful lives range from 5 to 30 years.
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| Revenue recognition and gas imbalances | Revenue recognition and gas imbalances
We use the sales method of accounting for oil and natural gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. Gas imbalances at December 31, 2019 were not significant. New Concept also follows the sales method of accounting for natural gas production imbalances and would recognize a liability if the existing reserves were not adequate to cover an imbalance.
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| Accounting for Leases | Accounting for Leases
Leases of property, plant and equipment where the Company assumes substantially all the benefits and risks of ownership are classified as finance leases. Finance leases are capitalized at the estimated present value of the underlying lease payments. Each lease payment is allocated between the liability and finance charges so as to achieve a constant rate on the finance balance outstanding. The corresponding rental obligations, net of finance charges, are included in other long-term payables. The interest element of the finance charge is charged to the income statement over the lease period. Property, plant and equipment acquired under finance leasing contracts are depreciated over the useful life of the asset. Leases of assets under which all the risks and benefits of ownership are effectively retained by the lessor are classified as operating leases. Payments made under operating leases are charged to the income statement on a straight-line basis over the period of the lease. When an operating lease is terminated before the lease period has expired, any payment required to be made to the lessor by way of penalty is recognized as an expense in the period in which termination takes place.
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| Revenue Recognition | Revenue Recognition
Rental income for residential property leases is recorded when due from residents and is recognized monthly as it is earned, which is not materially different than on a straight-line basis as lease terms are generally for periods of one year or less.
Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. Costs associated with revenues are recorded in cost of revenues. Production volumes of natural gas are sold immediately and transported via pipeline. Royalties on the production of natural gas either paid in cash or settled through the delivery of volumes. The Company includes royalties in its revenues and cost of revenues when settlement of the royalties is paid in cash, while royalties settled by the delivery of volumes are excluded from revenues and cost of revenues.
The Company follows the sales method of accounting for natural gas production imbalances and would recognize a liability if the existing reserves were not adequate to cover an imbalance.
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| Use of Estimates | Use of Estimates
In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and revenues and expenses during the reporting period. Actual results could differ from those estimates.
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| Cash Equivalents | Cash Equivalents
The Company considers all short-term deposits and money market investments with a maturity of less than three months to be cash equivalents.
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| Other Intangible Assets | Other Intangible Assets
The cost of acquired patents, trademarks and licenses is capitalized and amortized using the straight-line method over their useful lives. The carrying amount of each intangible asset is reviewed annually and adjusted for permanent impairment where it is considered necessary.
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| Impairment of Notes Receivable | Impairment of Notes Receivable
Notes receivable are identified as impaired when it is probable that interest and principal will not be collected according to the contractual terms of the note agreements. The accrual of interest is discontinued on such notes, and no income is recognized until all past due amounts of principal and interest are recovered in full.
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| Impairment of Long-Lived Assets | Impairment of Long-Lived Assets
The Company reviews its long-lived assets and certain identifiable intangibles for impairment when events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. In reviewing recoverability, the Company estimates the future cash flows expected to result from use of the assets and eventually disposing of them. If the sum of the expected future cash flows (undiscounted and without interest charges) is less than the carrying amount of the asset, an impairment loss is recognized based on the asset’s fair value.
The Company determines the fair value of assets to be disposed of and records the asset at the lower of fair value less disposal costs or carrying value. Assets are not depreciated while held for disposal.
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| Sales of Real Estate | Sales of Real Estate
Gains on sales of real estate are recognized to the extent permitted by Accounting Standards Codification Topic 360-20, “Real Estate Sales – Real Estate Sales”, (“ASC 360-20”). Until the requirements of ASC 360-20 have been met for full profit recognition, sales are accounted for by the installment or cost recovery method, whichever is appropriate.
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| Real Estate Held for Sale | Real Estate Held for Sale
Accounting Standards Codification Topic 360, “Property, Plant, & Equipment” (“ASC 360”)requires that properties held for sale be reported at the lower of carrying amount or fair value less costs of sale. If a reduction in a held for sale property’s carrying amount to fair value less costs of sale is required, a provision for loss is recognized by a charge against earnings. Subsequent revisions, either upward or downward, to a held for sale property’s estimated fair value less costs of sale are recorded as an adjustment to the property’s carrying amount, but not in excess of the property’s carrying amount when originally classified as held for sale. A corresponding charge against or credit to earnings is recognized. Properties held for sale are not depreciated.
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| Asset Retirement Obligation | Asset Retirement Obligation
The Company records an asset retirement obligation liability on the consolidated balance sheets and capitalizes a portion of the cost in “Oil and natural gas properties” during the period in which the obligation is incurred. The asset retirement obligation is further described in Note K.
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| Income Taxes | Income Taxes
The Company accounts for income taxes in accordance with Accounting Standards Codification, (“ASC”) No. 740, “Accounting for Income Taxes”. ASC 740 requires an asset and liability approach to financial accounting for income taxes. In the event differences between the financial reporting basis and the tax basis of the Company’s assets and liabilities result in deferred tax assets, ASC 740 requires an evaluation of the probability of being able to realize the future benefits indicated by such assets. A valuation allowance is provided for a portion or all of the deferred tax assets when there is an uncertainty regarding the Company’s ability to recognize the benefits of the assets in future years. Recognition of the benefits of deferred tax assets will require the Company to generate future taxable income. There is no assurance that the Company will generate earnings in future years. Since management could not determine the likelihood that the benefit of the deferred tax asset would be realized, no deferred tax asset was recognized by the Company.
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| Recent Accounting Pronouncements | Recent Accounting Pronouncements
In December 2019, the FASB issued ASU 2019-12. Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. The amendments in this Update simplify the accounting for income taxes by removing certain exceptions from ASC 740. Also, the amendments in this Update simplify the accounting for income tax by requiring that an entity recognize a franchise tax (or similar tax) that is partially based on income as an income-based tax, requiring that an entity evaluate when a step up in the tax basis of goodwill should be considered part of the business combination, and other targeted changes. The effective date of the amendments is for fiscal years, and interim periods within those years, beginning after December 15, 2020. The Company is currently evaluating the impact that the adoption of ASU 2019-12 may have on its consolidated financial statements.
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G. INCOME TAXES (Tables) |
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| INCOME TAXES | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Effective Income Tax Rate Reconciliation |
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L. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION (Tables) |
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| Extractive Industries [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities |
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| Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure |
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| Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows |
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