EX-99 5 ex991.htm

ESTIMATED RESERVES

AND FUTURE NET REVENUE

OIL AND GAS PROPERTIES

Owned By

MOUNTAINEER STATE ENERGY, INC.

LOCATED IN

ATHENS AND MEIGS COUNTIES, OHIO

| AND |

CALHOUN, JACKSON AND ROANE

COUNTIES, WEST VIRGINIA

Effective Date

12/31/2017

| 12/31/2017 |

| INDEX |

ESTIMATED RESERVES AND FUTURE NET REVENUE

INTERESTS OWNED BY MOUNTAINEER STATE ENERGY, INC.

INDEX

| LETTER |

| SCHEDULES |

Summary Forecast of Production, Income and Estimated Future Net Revenue

Discounted at Ten Per Cent (10%) 1

Maximum to Minimum One-Line Summary of Discounted Future Net Revenue 2

Alphabetical One-Line Summary of the Forecast Entities 3

Individual Cash Flows Accompanied by Production Decline Curves 4

| LETTER |

L EE K EELING AND A SSOCIATES, I NC.

P ETROLEUM C ONSULTANTS

First Place Tower

15 East Fifth Street • Suite 3500 Tulsa, Oklahoma 74103-4350

(918) 587-5521 • Fax: (918) 587-2881 www.lkaengineers.com

March 29, 2018

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, Probable and Possible 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, nonproducing, probable and possible 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, 2017, and the results are summarized as follows:

|  | ESTIMATED REMAINING |  |  |  |
|  | NET RESERVES |  | FUTURE NET REVENUE
|  |  |  |  |  | Present Worth
RESERVE |  | Oil |  | Gas |  | TOTAL |  | Disc. @ 10%
CLASSIFICATION |  | (BBLS) |  | (MCF) |  | ($) |  | ($)
Proved Developed |  |  |  |  |  |  |  |
Producing Proved Developed Non-Producing |  |  | 51,370 |  |  |  | 805,257 |  |  |  | 2 ,513,174 |  |  |  | 1,314,703 |
Behind Pipe |  |  | 17,495 |  |  |  | 24,493 |  |  |  | 574,131 |  |  |  | 250,469 |
Proved Developed Total |  |  | 68,865 |  |  |  | 829,750 |  |  |  | 3 ,087,305 |  |  |  | 1,565,172 |
Probable |  |  | — |  |  |  | 1,025,446 |  |  |  | 1 ,452,432 |  |  |  | 881,958 |
Possible |  |  | — |  |  |  | 341,815 |  |  |  | 484,144 |  |  |  | 274,159 |
Total All Reserves |  |  | 68,865 |  |  |  | 2,197,011 |  |  |  | 5 ,023,881 |  |  |  | 2,721,289 |
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

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 reserve type of annual gross and net production, severance and ad valorem taxes, operating income and net revenue. Schedule No. 2 is a sequential listing of the forecast entities based on discounted future net revenue. A one-line alphabetical listing of the forecast entities is presented on Schedule No. 3. Supplemental data, presented as Schedule No. 4, includes the individual cash flows for the various entities. These are accompanied by production decline curves that show our projections of future producing rates.

| BACKGROUND |

This estimate is concerned with approximately one hundred twenty-five (125) gas and oil wells of which one hundred ten (110) were selling gas with nine (9) producing oil on the effective date. Several additional wells are shut-in. These wells are located in two Ohio counties, Athens and Meigs, and the three West Virginia counties of Calhoun, Jackson and Roane. Composite production decline curves have been prepared of gas production (sales) for each of the five counties. These composite decline curves are the “forecast entities” referred to in the preceding paragraphs. Individual production decline curves with cash flows for the nine Berea oil wells and one gas well in Jackson County, West Virginia are also included.

CLASSIFICATION OF RESERVES

Reserves assigned to the various leases and/or wells have been classified as either “proved developed,” ”probable” or “possible” 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.

Developed Producing (Petroleum Resources Management System (PRMS) Definitions

Although not required for disclosure under SEC regulations, Proved Oil and Gas Reserves may be further sub-classified as Producing or Non-Producing, according to PRMS definitions set out below:

| • | Developed Producing (PDP) Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

| • | Developed Non-Producing (PDNP) Reserves include shut-in and behind-pipe reserves.

| o | Shut-In Reserves are expected to be recovered from:

| 1. | Completion intervals which are open at the time of the estimate but which have not yet started producing.

| 2. | Wells which were shut-in for market conditions or pipeline connections; or 3. Wells not capable of production for mechanical reasons.

| o | Behind-Pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Probable Reserves

Probable Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves, but more certain to be recovered than Possible Reserves.

Possible Reserves

Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Probable Reserves.

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, behind pipe, probable and/or possible locations 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 2017 through December 2017, as provided by the staff of Mountaineer.

These prices were $46.96 per barrel of oil, and $3.81 per MCF for gas in Ohio and $3.24 per MCF for gas in West Virginia. The prices were held constant, but provisions were made for state severance and ad valorem taxes.

Operating Expenses

Anticipated monthly expenses were based on expenses supplied by Mountaineer. Expenses were not escalated but held constant for the various recovery periods.

Future Expenses

As provided by Mountaineer, provisions have been made for future expenses required for drilling and completion of wells to capture the probable and possible reserves. These costs have been held constant from current estimates.

| 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.

LKA7738

Appendix

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.

D EFINITIONS

(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.

(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.

(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.

(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.

N OTE 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.

S UCCESSFUL E FFORTS M ETHOD

(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.

F ULL C OST M ETHOD

(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:

(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-ofproduction 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) 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.

I NCOME T AXES

(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.

SCHEDULE 1

ESTIMATED RESERVES AND FUTURE NET REVENUE DATE : 03/29/2018

MOUNTAINEER STATE ENERGY TIME : 09:25:02

OHIO AND WEST VIRGINIA PROPERTIES DBS : MountaineerSt

ALL RESERVES SETTINGS : LKA0118 SCENARIO : LKA0118

| R | E S E R V E S A N D E C O N O M I C S

AS OF DATE: 12/31/2017

--END-- GROSS OIL GROSS GAS NET OIL NET GAS NET OIL NET GAS NET NET TOTAL

MO-YEAR PRODUCTION PRODUCTION PRODUCTION PRODUCTION PRICE PRICE OIL SALES GAS SALES NET SALES ------- ---MBBLS--- ----MMCF--- ---MBBLS--- ----MMCF--- ---$/BBL--- ---$/MCF--- -----M$---- -----M$---- -----M$----

| 12-2018 | 4.462 209.000 3.681 182.097 46.960 3.491 172.881 635.660 808.541

| 12-2019 | 5.592 387.773 4.692 338.721 46.960 3.369 220.347 1141.298 1361.645

| 12-2020 | 5.115 434.839 4.337 380.135 46.960 3.348 203.656 1272.818 1476.473

| 12-2021 | 4.363 345.243 3.818 302.088 46.960 3.368 179.272 1017.335 1196.607 12-2022 4.040 277.789 3.535 243.066 46.960 3.390 166.014 823.952 989.965

| 12-2023 | 3.765 226.295 3.295 198.008 46.960 3.414 154.721 675.980 830.702

| 12-2024 | 3.526 148.482 3.085 129.922 46.960 3.344 144.881 434.425 579.306

| 12-2025 | 3.313 101.288 2.899 88.627 46.960 3.278 136.136 290.550 426.686

| 12-2026 | 3.121 80.441 2.731 70.386 46.960 3.285 128.259 231.214 359.473 12-2027 2.947 64.620 2.579 56.543 46.960 3.292 121.096 186.159 307.255

| 12-2028 | 2.787 41.786 2.439 36.563 46.960 3.316 114.536 121.242 235.777

| 12-2029 | 2.640 22.006 2.310 19.255 46.960 3.376 108.490 65.002 173.492

| 12-2030 | 2.504 17.764 2.191 15.544 46.960 3.399 102.885 52.833 155.718

| 12-2031 | 2.377 16.859 2.080 14.752 46.960 3.399 97.664 50.134 147.798 12-2032 2.258 16.007 1.976 14.006 46.960 3.398 92.783 47.596 140.380

| S | TOT 52.812 2390.192 45.648 2089.710 46.960 3.372 2143.621 7046.197 9189.818

AFTER 26.535 122.629 23.218 107.300 46.960 3.475 1090.315 372.876 1463.191

TOTAL 79.347 2512.821 68.866 2197.010 46.960 3.377 3233.936 7419.074 10653.009

--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$----

| 12-2018 | 35.372 18.892 260.828 0.000 0.000 740.000 -246.551 -246.551 -238.344

| 12-2019 | 50.254 44.805 302.248 0.000 0.000 740.000 224.338 -22.213 -48.392

| 12-2020 | 52.005 52.118 324.685 0.000 0.000 0.000 1047.665 1025.452 777.157

| 12-2021 | 43.711 40.049 315.684 0.000 0.000 0.000 797.163 1822.615 1348.205 12-2022 37.691 30.977 315.684 0.000 0.000 0.000 605.613 2428.229 1742.597

| 12-2023 | 32.948 24.130 315.684 0.000 0.000 0.000 457.940 2886.168 2013.709

| 12-2024 | 21.920 18.117 193.820 0.000 0.000 0.000 345.449 3231.617 2199.639

| 12-2025 | 15.700 13.830 132.888 0.000 0.000 0.000 264.267 3495.885 2328.939

| 12-2026 | 13.727 10.915 132.888 0.000 0.000 0.000 201.943 3697.828 2418.763 12-2027 12.155 8.706 132.888 0.000 0.000 0.000 153.505 3851.333 2480.835

| 12-2028 | 10.130 5.499 101.424 0.000 0.000 0.000 118.724 3970.057 2524.482

| 12-2029 | 8.353 2.722 61.680 0.000 0.000 0.000 100.738 4070.795 2558.151

| 12-2030 | 7.700 2.143 53.400 0.000 0.000 0.000 92.475 4163.270 2586.245

| 12-2031 | 7.308 2.036 53.400 0.000 0.000 0.000 85.054 4248.324 2609.736 12-2032 6.941 1.934 53.400 0.000 0.000 0.000 78.105 4326.429 2629.346

S TOT 355.914 276.873 2750.601 0.000 0.000 1480.000 4326.429 4326.429 2629.346

AFTER 76.752 13.642 675.345 0.000 0.000 0.000 697.452 5023.881 2721.291

TOTAL 432.667 290.515 3425.946 0.000 0.000 1480.000 5023.881 5023.881 2721.291

OIL GAS P.W. % P.W., M$

--------- --------- ------ --------

GROSS WELLS 15.0 110.0 LIFE, YRS. 50.00 5.00 3564.104

GROSS ULT., MB & MMF 146.825 13587.245 DISCOUNT % 10.00 10.00 2721.291

GROSS CUM., MB & MMF 67.478 11074.424 UNDISCOUNTED PAYOUT, YRS. 2.02 12.00 2473.395

GROSS RES., MB & MMF 79.347 2512.821 DISCOUNTED PAYOUT, YRS. 2.06 15.00 2163.607

NET RES., MB & MMF 68.866 2197.011 UNDISCOUNTED NET/INVEST. 4.39 20.00 1764.653

NET REVENUE, M$ 3233.936 7419.073 DISCOUNTED NET/INVEST. 3.03 25.00 1464.948

INITIAL PRICE, $ 46.960 3.338 RATE-OF-RETURN, PCT. 100.00 40.00 896.484

INITIAL N.I., PCT. 82.503 87.128 INITIAL W.I., PCT. 99.342 60.00 508.018

80.00 299.738 100.00 175.936 PROVED DEVELOPED PRODUCING RESERVES DBS : MountaineerSt

SETTINGS : LKA0118 SCENARIO : LKA0118

| R | E S E R V E S A N D E C O N O M I C S

AS OF DATE: 12/31/2017

--END-- GROSS OIL GROSS GAS NET OIL NET GAS NET OIL NET GAS NET NET TOTAL

MO-YEAR PRODUCTION PRODUCTION PRODUCTION PRODUCTION PRICE PRICE OIL SALES GAS SALES NET SALES ------- ---MBBLS--- ----MMCF--- ---MBBLS--- ----MMCF--- ---$/BBL--- ---$/MCF--- -----M$---- -----M$---- -----M$----

| 12-2018 | 4.115 123.252 3.377 107.067 46.960 3.664 158.602 392.322 550.924

| 12-2019 | 3.848 112.822 3.166 98.139 46.960 3.674 148.680 360.592 509.273

| 12-2020 | 3.499 104.891 2.923 91.431 46.960 3.678 137.244 336.289 473.533

| 12-2021 | 2.968 97.527 2.597 85.336 46.960 3.681 121.954 314.085 436.039 12-2022 2.811 91.746 2.460 80.278 46.960 3.683 115.510 295.661 411.171

| 12-2023 | 2.665 86.513 2.332 75.699 46.960 3.685 109.525 278.931 388.456

| 12-2024 | 2.530 43.406 2.213 37.980 46.960 3.577 103.940 135.838 239.778

| 12-2025 | 2.402 22.251 2.102 19.469 46.960 3.382 98.687 65.844 164.531

| 12-2026 | 2.281 20.943 1.996 18.325 46.960 3.381 93.730 61.953 155.683 12-2027 2.167 19.788 1.896 17.314 46.960 3.379 89.046 58.514 147.560

| 12-2028 | 2.059 18.745 1.802 16.402 46.960 3.378 84.618 55.413 140.031

| 12-2029 | 1.957 17.774 1.713 15.552 46.960 3.378 80.427 52.529 132.956

| 12-2030 | 1.861 16.864 1.628 14.756 46.960 3.377 76.450 49.830 126.281

| 12-2031 | 1.769 16.007 1.548 14.006 46.960 3.377 72.671 47.295 119.966 12-2032 1.681 15.199 1.471 13.299 46.960 3.376 69.078 44.904 113.982

| S | TOT 38.612 807.729 33.223 705.056 46.960 3.617 1560.164 2550.000 4110.164

AFTER 20.740 114.515 18.147 100.201 46.960 3.451 852.192 345.828 1198.021

TOTAL 59.352 922.245 51.370 805.257 46.960 3.596 2412.356 2895.828 5308.185

--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$----

| 12-2018 | 28.460 6.765 244.728 0.000 0.000 0.000 270.972 270.972 258.362

| 12-2019 | 26.509 5.971 241.022 0.000 0.000 0.000 235.771 506.742 462.724

| 12-2020 | 24.706 5.478 238.021 0.000 0.000 0.000 205.327 712.069 624.523

| 12-2021 | 22.761 5.048 229.020 0.000 0.000 0.000 179.211 891.280 752.900 12-2022 21.502 4.704 229.020 0.000 0.000 0.000 155.945 1047.225 854.456

| 12-2023 | 20.342 4.405 229.020 0.000 0.000 0.000 134.690 1181.915 934.196

| 12-2024 | 12.019 3.302 107.156 0.000 0.000 0.000 117.301 1299.216 997.336

| 12-2025 | 7.847 2.700 46.224 0.000 0.000 0.000 107.760 1406.976 1050.061

| 12-2026 | 7.428 2.549 46.224 0.000 0.000 0.000 99.482 1506.458 1094.310 12-2027 7.041 2.414 46.224 0.000 0.000 0.000 91.881 1598.338 1131.463

| 12-2028 | 6.681 2.292 46.224 0.000 0.000 0.000 84.834 1683.172 1162.647

| 12-2029 | 6.343 2.177 46.224 0.000 0.000 0.000 78.213 1761.385 1188.785

| 12-2030 | 6.024 2.067 46.224 0.000 0.000 0.000 71.965 1833.350 1210.648

| 12-2031 | 5.723 1.964 46.224 0.000 0.000 0.000 66.055 1899.405 1228.891 12-2032 5.438 1.866 46.224 0.000 0.000 0.000 60.455 1959.860 1244.070

S TOT 208.825 53.700 1887.779 0.000 0.000 0.000 1959.860 1959.860 1244.070

AFTER 61.653 12.957 570.097 0.000 0.000 0.000 553.313 2513.174 1314.703

TOTAL 270.478 66.657 2457.876 0.000 0.000 0.000 2513.174 2513.174 1314.703

OIL GAS P.W. % P.W., M$

--------- --------- ------ --------

GROSS WELLS 9.0 110.0 LIFE, YRS. 50.00 5.00 1711.959

GROSS ULT., MB & MMF 126.830 11996.669 DISCOUNT % 10.00 10.00 1314.703

GROSS CUM., MB & MMF 67.478 11074.424 UNDISCOUNTED PAYOUT, YRS. 0.00 12.00 1207.401

GROSS RES., MB & MMF 59.352 922.245 DISCOUNTED PAYOUT, YRS. 0.00 15.00 1079.181

NET RES., MB & MMF 51.370 805.257 UNDISCOUNTED NET/INVEST. 0.00 20.00 922.998

NET REVENUE, M$ 2412.356 2895.829 DISCOUNTED NET/INVEST. 0.00 25.00 811.448

INITIAL PRICE, $ 46.960 3.608 RATE-OF-RETURN, PCT. 100.00 40.00 609.021

INITIAL N.I., PCT. 82.081 86.869 INITIAL W.I., PCT. 98.076 60.00 470.718

80.00 391.400

100.00 339.382

PROVED DEVELOPED BEHIND PIPE RESERVES DBS : MountaineerSt

SETTINGS : LKA0118 SCENARIO : LKA0118

| R | E S E R V E S A N D E C O N O M I C S

AS OF DATE: 12/31/2017

--END-- GROSS OIL GROSS GAS NET OIL NET GAS NET OIL NET GAS NET NET TOTAL

MO-YEAR PRODUCTION PRODUCTION PRODUCTION PRODUCTION PRICE PRICE OIL SALES GAS SALES NET SALES ------- ---MBBLS--- ----MMCF--- ---MBBLS--- ----MMCF--- ---$/BBL--- ---$/MCF--- -----M$---- -----M$---- -----M$----

| 12-2018 | 0.347 0.486 0.304 0.426 46.960 3.810 14.278 1.622 15.900

| 12-2019 | 1.744 2.442 1.526 2.137 46.960 3.810 71.666 8.140 79.807

| 12-2020 | 1.616 2.263 1.414 1.980 46.960 3.810 66.412 7.543 73.956

| 12-2021 | 1.395 1.953 1.221 1.709 46.960 3.810 57.318 6.511 63.829 12-2022 1.229 1.721 1.075 1.506 46.960 3.810 50.503 5.736 56.240

| 12-2023 | 1.100 1.540 0.962 1.347 46.960 3.810 45.196 5.134 50.330

| 12-2024 | 0.996 1.395 0.872 1.221 46.960 3.810 40.941 4.650 45.591

| 12-2025 | 0.911 1.276 0.797 1.116 46.960 3.810 37.448 4.254 41.702

| 12-2026 | 0.840 1.176 0.735 1.029 46.960 3.810 34.529 3.922 38.451 12-2027 0.780 1.092 0.682 0.955 46.960 3.810 32.050 3.640 35.690

| 12-2028 | 0.728 1.019 0.637 0.892 46.960 3.810 29.918 3.398 33.316

| 12-2029 | 0.683 0.956 0.598 0.837 46.960 3.810 28.063 3.188 31.251

| 12-2030 | 0.643 0.901 0.563 0.788 46.960 3.810 26.435 3.003 29.438

| 12-2031 | 0.608 0.852 0.532 0.745 46.960 3.810 24.993 2.839 27.832 12-2032 0.577 0.808 0.505 0.707 46.960 3.810 23.705 2.693 26.397

| S | TOT 14.199 19.879 12.425 17.394 46.960 3.810 583.457 66.273 649.729

AFTER 5.795 8.113 5.071 7.099 46.960 3.810 238.123 27.047 265.171

TOTAL 19.995 27.992 17.495 24.493 46.960 3.810 821.580 93.320 914.900

--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$----

| 12-2018 | 0.905 0.041 1.196 0.000 0.000 40.000 -26.242 -26.242 -25.130

| 12-2019 | 4.544 0.206 6.578 0.000 0.000 40.000 28.478 2.236 -2.073

| 12-2020 | 4.211 0.191 7.176 0.000 0.000 0.000 62.377 64.613 47.079

| 12-2021 | 3.635 0.165 7.176 0.000 0.000 0.000 52.854 117.467 84.941 12-2022 3.202 0.145 7.176 0.000 0.000 0.000 45.716 163.183 114.713

| 12-2023 | 2.866 0.130 7.176 0.000 0.000 0.000 40.158 203.341 138.487

| 12-2024 | 2.596 0.118 7.176 0.000 0.000 0.000 35.701 239.042 157.702

| 12-2025 | 2.375 0.108 7.176 0.000 0.000 0.000 32.044 271.086 173.380

| 12-2026 | 2.189 0.099 7.176 0.000 0.000 0.000 28.986 300.072 186.273 12-2027 2.032 0.092 7.176 0.000 0.000 0.000 26.390 326.462 196.944

| 12-2028 | 1.897 0.086 7.176 0.000 0.000 0.000 24.157 350.619 205.824

| 12-2029 | 1.780 0.081 7.176 0.000 0.000 0.000 22.215 372.834 213.248

| 12-2030 | 1.676 0.076 7.176 0.000 0.000 0.000 20.509 393.343 219.479

| 12-2031 | 1.585 0.072 7.176 0.000 0.000 0.000 18.999 412.343 224.726 12-2032 1.503 0.068 7.176 0.000 0.000 0.000 17.650 429.993 229.158

S TOT 36.997 1.677 101.062 0.000 0.000 80.000 429.993 429.993 229.158

AFTER 15.100 0.685 105.248 0.000 0.000 0.000 144.138 574.131 250.469

TOTAL 52.097 2.362 206.310 0.000 0.000 80.000 574.131 574.131 250.469

OIL GAS P.W. % P.W., M$

--------- --------- ------ --------

GROSS WELLS 2.0 0.0 LIFE, YRS. 29.92 5.00 361.194

GROSS ULT., MB & MMF 19.995 27.992 DISCOUNT % 10.00 10.00 250.469

GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 1.92 12.00 220.513

GROSS RES., MB & MMF 19.995 27.992 DISCOUNTED PAYOUT, YRS. 2.04 15.00 184.962

NET RES., MB & MMF 17.495 24.493 UNDISCOUNTED NET/INVEST. 8.18 20.00 142.348

NET REVENUE, M$ 821.580 93.320 DISCOUNTED NET/INVEST. 4.39 25.00 112.659

INITIAL PRICE, $ 46.960 3.810 RATE-OF-RETURN, PCT. 100.00 40.00 61.470

INITIAL N.I., PCT. 87.500 87.500 INITIAL W.I., PCT. 100.000 60.00 29.949

80.00 14.097

100.00 5.036

PROBABLE RESERVES DBS : MountaineerSt

SETTINGS : LKA0118 SCENARIO : LKA0118

| R | E S E R V E S A N D E C O N O M I C S

AS OF DATE: 12/31/2017

--END-- GROSS OIL GROSS GAS NET OIL NET GAS NET OIL NET GAS NET NET TOTAL

MO-YEAR PRODUCTION PRODUCTION PRODUCTION PRODUCTION PRICE PRICE OIL SALES GAS SALES NET SALES ------- ---MBBLS--- ----MMCF--- ---MBBLS--- ----MMCF--- ---$/BBL--- ---$/MCF--- -----M$---- -----M$---- -----M$----

| 12-2018 | 0.000 85.262 0.000 74.604 0.000 3.240 0.000 241.716 241.716

| 12-2019 | 0.000 234.368 0.000 205.072 0.000 3.240 0.000 664.433 664.433

| 12-2020 | 0.000 232.938 0.000 203.821 0.000 3.240 0.000 660.380 660.380

| 12-2021 | 0.000 174.704 0.000 152.866 0.000 3.240 0.000 495.285 495.285 12-2022 0.000 131.028 0.000 114.649 0.000 3.240 0.000 371.463 371.463

| 12-2023 | 0.000 98.271 0.000 85.987 0.000 3.240 0.000 278.598 278.598

| 12-2024 | 0.000 73.703 0.000 64.490 0.000 3.240 0.000 208.948 208.948

| 12-2025 | 0.000 55.277 0.000 48.368 0.000 3.240 0.000 156.711 156.711

| 12-2026 | 0.000 41.458 0.000 36.276 0.000 3.240 0.000 117.533 117.533 12-2027 0.000 31.093 0.000 27.207 0.000 3.240 0.000 88.150 88.150

12-2028 0.000 12.536 0.000 10.969 0.000 3.240 0.000 35.539 35.539 12-2029 0.000 1.301 0.000 1.138 0.000 3.240 0.000 3.687 3.687

| 12-2030 |

| 12-2031 |

| 12-2032 |

| S | TOT 0.000 1171.938 0.000 1025.446 0.000 3.240 0.000 3322.444 3322.444

AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

TOTAL 0.000 1171.938 0.000 1025.446 0.000 3.240 0.000 3322.444 3322.444

--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$----

| 12-2018 | 6.007 12.086 14.904 0.000 0.000 700.000 -491.280 -491.280 -471.577

| 12-2019 | 16.512 33.222 48.024 0.000 0.000 350.000 216.674 -274.606 -286.507

| 12-2020 | 16.412 33.019 59.616 0.000 0.000 0.000 551.333 276.727 147.935

| 12-2021 | 12.309 24.764 59.616 0.000 0.000 0.000 398.596 675.322 433.469 12-2022 9.232 18.573 59.616 0.000 0.000 0.000 284.043 959.365 618.446

| 12-2023 | 6.924 13.930 59.616 0.000 0.000 0.000 198.128 1157.493 735.743

| 12-2024 | 5.193 10.447 59.616 0.000 0.000 0.000 133.692 1291.185 807.696

| 12-2025 | 3.895 7.836 59.616 0.000 0.000 0.000 85.365 1376.550 849.463

| 12-2026 | 2.921 5.877 59.616 0.000 0.000 0.000 49.120 1425.670 871.312 12-2027 2.191 4.407 59.616 0.000 0.000 0.000 21.936 1447.605 880.182

12-2028 0.883 1.777 28.152 0.000 0.000 0.000 4.727 1452.333 881.924 12-2029 0.092 0.184 3.312 0.000 0.000 0.000 0.099 1452.432 881.958

| 12-2030 |

| 12-2031 |

| 12-2032 |

S TOT 82.569 166.122 571.320 0.000 0.000 1050.000 1452.432 1452.432 881.958

AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 1452.432 881.958

TOTAL 82.569 166.122 571.320 0.000 0.000 1050.000 1452.432 1452.432 881.958

OIL GAS P.W. % P.W., M$

--------- --------- ------ --------

GROSS WELLS 3.0 0.0 LIFE, YRS. 11.17 5.00 1128.051

GROSS ULT., MB & MMF 0.000 1171.938 DISCOUNT % 10.00 10.00 881.958

GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 2.50 12.00 800.086

GROSS RES., MB & MMF 0.000 1171.938 DISCOUNTED PAYOUT, YRS. 2.66 15.00 691.525

NET RES., MB & MMF 0.000 1025.446 UNDISCOUNTED NET/INVEST. 2.38 20.00 541.606

NET REVENUE, M$ 0.000 3322.444 DISCOUNTED NET/INVEST. 1.91 25.00 421.801

INITIAL PRICE, $ 0.000 3.240 RATE-OF-RETURN, PCT. 61.13 40.00 179.611

INITIAL N.I., PCT. 0.000 87.500 INITIAL W.I., PCT. 100.000 60.00 6.013

80.00 -87.285

100.00 -141.161

OHIO AND WEST VIRGINIA PROPERTIES TIME : 09:25:02

POSSIBLE RESERVES DBS : MountaineerSt

SETTINGS : LKA0118 SCENARIO : LKA0118

| R | E S E R V E S A N D E C O N O M I C S

AS OF DATE: 12/31/2017

--END-- GROSS OIL GROSS GAS NET OIL NET GAS NET OIL NET GAS NET NET TOTAL

MO-YEAR PRODUCTION PRODUCTION PRODUCTION PRODUCTION PRICE PRICE OIL SALES GAS SALES NET SALES ------- ---MBBLS--- ----MMCF--- ---MBBLS--- ----MMCF--- ---$/BBL--- ---$/MCF--- -----M$---- -----M$---- -----M$----

| 12-2018 | 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

| 12-2019 | 0.000 38.142 0.000 33.374 0.000 3.240 0.000 108.133 108.133

| 12-2020 | 0.000 94.746 0.000 82.903 0.000 3.240 0.000 268.606 268.606

| 12-2021 | 0.000 71.060 0.000 62.177 0.000 3.240 0.000 201.454 201.454 12-2022 0.000 53.295 0.000 46.633 0.000 3.240 0.000 151.091 151.091

| 12-2023 | 0.000 39.971 0.000 34.975 0.000 3.240 0.000 113.318 113.318

| 12-2024 | 0.000 29.978 0.000 26.231 0.000 3.240 0.000 84.989 84.989

| 12-2025 | 0.000 22.484 0.000 19.673 0.000 3.240 0.000 63.741 63.741

| 12-2026 | 0.000 16.863 0.000 14.755 0.000 3.240 0.000 47.806 47.806 12-2027 0.000 12.647 0.000 11.066 0.000 3.240 0.000 35.855 35.855

12-2028 0.000 9.485 0.000 8.300 0.000 3.240 0.000 26.891 26.891 12-2029 0.000 1.975 0.000 1.728 0.000 3.240 0.000 5.598 5.598

| 12-2030 |

| 12-2031 |

| 12-2032 |

| S | TOT 0.000 390.646 0.000 341.815 0.000 3.240 0.000 1107.481 1107.481

AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

TOTAL 0.000 390.646 0.000 341.815 0.000 3.240 0.000 1107.481 1107.481

--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$----

| 12-2018 | 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

| 12-2019 | 2.687 5.407 6.624 0.000 0.000 350.000 -256.585 -256.585 -222.536

| 12-2020 | 6.675 13.430 19.872 0.000 0.000 0.000 228.628 -27.957 -42.381

| 12-2021 | 5.007 10.073 19.872 0.000 0.000 0.000 166.503 138.546 76.894 12-2022 3.755 7.555 19.872 0.000 0.000 0.000 119.909 258.455 154.982

| 12-2023 | 2.816 5.666 19.872 0.000 0.000 0.000 84.964 343.419 205.283

| 12-2024 | 2.112 4.249 19.872 0.000 0.000 0.000 58.755 402.174 236.905

| 12-2025 | 1.584 3.187 19.872 0.000 0.000 0.000 39.098 441.272 256.035

| 12-2026 | 1.188 2.390 19.872 0.000 0.000 0.000 24.356 465.628 266.869 12-2027 0.891 1.793 19.872 0.000 0.000 0.000 13.299 478.927 272.246

12-2028 0.668 1.345 19.872 0.000 0.000 0.000 5.006 483.933 274.086 12-2029 0.139 0.280 4.968 0.000 0.000 0.000 0.211 484.144 274.159

| 12-2030 |

| 12-2031 |

| 12-2032 |

S TOT 27.523 55.374 190.440 0.000 0.000 350.000 484.144 484.144 274.159

AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 484.144 274.159

TOTAL 27.523 55.374 190.440 0.000 0.000 350.000 484.144 484.144 274.159

OIL GAS P.W. % P.W., M$

--------- --------- ------ --------

GROSS WELLS 1.0 0.0 LIFE, YRS. 11.25 5.00 362.900

GROSS ULT., MB & MMF 0.000 390.646 DISCOUNT % 10.00 10.00 274.159

GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 3.17 12.00 245.395

GROSS RES., MB & MMF 0.000 390.646 DISCOUNTED PAYOUT, YRS. 3.36 15.00 207.940

NET RES., MB & MMF 0.000 341.815 UNDISCOUNTED NET/INVEST. 2.38 20.00 157.701

NET REVENUE, M$ 0.000 1107.481 DISCOUNTED NET/INVEST. 1.91 25.00 119.040

INITIAL PRICE, $ 0.000 3.240 RATE-OF-RETURN, PCT. 61.13 40.00 46.382

INITIAL N.I., PCT. 0.000 87.500 INITIAL W.I., PCT. 100.000 60.00 1.339

80.00 -18.474

SCHEDULE 2

ESTIMATED RESERVES AND FUTURE NET REVENUE Exhibit 99.1

MOUNTAINEER STATE ENERGY, INC. MAXIMUM TO MINIMUM LEASE SUMMARY

AS OF DECEMBER 31, 2017

(SORTED BY RESERVE CATEGORY, DFNR)

| DFNR |

ARIES RSV GROSS OIL GROSS GAS NET OIL NET GAS WORKING REVENUE CASHFLOW DISC

I.D. LEASE CAT STATE COUNTY LOCATION MBO MMCF MBO MMCF INTEREST INTEREST (M$) 10% (M$)

PROVED DEVELOPED PRODUCING RESERVES

222 ROGER GAUL #274 | 1PDP | OH | MEIGS | 19.481 | 53.875 | 17.046 | 47.141 | 1.000000 | 0.875000 | 742.004 | 315.496
233 JACKSON CO., WV #347 | 1PDP | WV | JACKSON | 0.000 | 343.843 | 0.000 | 300.863 | 1.000000 | 0.875000 | 449.741 | 272.524
221 KARL RUSSELL #273 | 1PDP | OH | MEIGS | 17.073 | 18.697 | 14.939 | 16.360 | 1.000000 | 0.875000 | 549.825 | 242.494
172 MEIGS CO., OHIO - COMPOSITE | 1PDP | OH | MEIGS | 0.000 | 437.614 | 0.000 | 382.912 | 1.000000 | 0.875000 | 208.872 | 173.023
11 JIM ROUSH #178 | 1PDP | OH | MEIGS | 8.267 | 22.823 | 7.234 | 19.970 | 1.000000 | 0.875000 | 261.133 | 130.104
2 GUAL # 402 BEREA | 1PDP | OH | MEIGS | 8.392 | 21.486 | 7.343 | 18.800 | 1.000000 | 0.875000 | 157.555 | 96.996
230 RUTH MYERS #181 | 1PDP | OH | MEIGS | 4.677 | 18.053 | 4.093 | 15.796 | 1.000000 | 0.875000 | 137.638 | 78.186
1 MYERS # 401 BEREA WELL | 1PDP | OH | MEIGS | 1.461 | 4.434 | 0.716 | 2.173 | 0.560000 | 0.490000 | 6.388 | 5.864
169 ROANE CO., WV - COMPOSITE | 1PDP | WV | ROANE | 0.000 | 1.420 | 0.000 | 1.242 | 1.000000 | 0.875000 | 0.018 | 0.018
170 JACKSON CO., WV - COMPOSITE | 1PDP | WV | JACKSON | 0.000 | 0.000 | 0.000 | 0.000 | 1.000000 | 0.875000 | 0.000 | 0.000
171 CALHOUN CO., WV - COMPOSITE | 1PDP | WV | CALHOUN | 0.000 | 0.000 | 0.000 | 0.000 | 1.000000 | 0.875000 | 0.000 | 0.000
8 JIM BERNARD #167 | 1PDP | OH | MEIGS | 0.000 | 0.000 | 0.000 | 0.000 | 0.000000 | 0.000000 | 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
168 ATHENS CO., OHIO - COMPOSITE | 1PDP | OH | ATHENS | 0.000 | 0.000 | 0.000 | 0.000 | 1.000000 | 0.875000 | 0.000 | 0.000
6 JAY BLACKWOOD #165 | 1PDP | OH | MEIGS | 0.000 | 0.000 | 0.000 | 0.000 | 1.000000 | 0.875000 | 0.000 | 0.000

59.352 | 922.244 | 51.370 | 805.257
9.997 | 13.996 | 8.748 | 12.247
9.997 | 13.996 | 8.748 | 12.247
19.995 | 27.992 | 17.495 | 24.493
0.000 | 390.646 | 0.000 | 341.815
0.000 | 390.646 | 0.000 | 341.815
0.000 | 390.646 | 0.000 | 341.815

TOTAL PROVED DEVELOPED PRODUCING RESERVES2,513.174 1,314.703

PROVED DEVELOPED BEHIND-PIPE RESERVES

232 BEREA # 284 3PBP OH MEIGS1.000000 0.875000 287.066 128.221

231 BEREA #144 3PBP OH MEIGS1.000000 0.875000 287.066 122.248

TOTAL PROVED DEVELOPED BEHIND-PIPE RESERVES574.131 250.469

PROBABLE UNDEVELOPED RESERVES

| 234 | ORISKANY PROB 1 6PROB WV JACKSON1.000000 0.875000 484.144 304.010

| 235 | ORISKANY PROB 2 6PROB WV JACKSON1.000000 0.875000 484.144 301.575

236 ORISKANY PROB 3 6PROB WV JACKSON1.000000 0.875000 484.144 276.373

TOTAL PROBABLE UNDEVELOPED RESERVES 0.000 1,171.938 0.000 THIS SCHEDULE IS PART OF A REPORT AND SUBJECT TO QUALIFICATIONS OF THE REPORT. LEE KEELING AND ASSOCIATES, INC. | 1,025.446 | 1,452.432 | 881.958

ESTIMATED RESERVES AND FUTURE NET REVENUE Exhibit 99.1

MOUNTAINEER STATE ENERGY, INC.MAXIMUM TO MINIMUM LEASE SUMMARY

AS OF DECEMBER 31, 2017

(SORTED BY RESERVE CATEGORY, DFNR)

| DFNR |

ARIES RSV GROSS OIL GROSS GAS NET OIL NET GAS WORKING REVENUE CASHFLOW DISC

I.D. LEASE CAT STATE COUNTY LOCATION MBO MMCF MBO MMCF INTEREST INTEREST (M$) 10% (M$)

POSSIBLE UNDEVELOPED RESERVES

237 ORISKANY POSS 1 7POSS WV JACKSON 0.000 390.646 0.000 341.815 1.000000 0.875000 484.144 274.159

0.000 390.646 0.000 341.815 79.347 2,512.821 68.866 2,197.011 |

TOTAL POSSIBLE UNDEVELOPED RESERVES

TOTAL PROVED RESERVES

SCHEDULE 3

Exhibit 99.1ESTIMATED RESERVES AND FUTURE NET REVENUE

MOUNTAINEER STATE ENERGY, INC.

ALPHABETICAL LEASE SUMMARY

AS OF DECEMBER 31, 2017

(SORTED BY LEASE, WELL ID, RESERVE CATEGORY)

| DFNR |

ARIES RES. GROSS OIL GROSS GAS NET OIL NET GAS WORKING REVENUE CASHFLOW DISC 10%

I.D. LEASE CAT. STATE COUNTY LOCATION MBO MMCF MBO MMCF INTEREST INTEREST (M$) (M$)

168 ATHENS CO., OHIO - COMPOSI | 1PDP | OH | ATHENS | 0.000 | 0.000 | 0.000 | 0.000 | 1.000000 | 0.875000 | 0.000 | 0.000
232 BEREA # 284 284 | 3PBP | OH | MEIGS | 9.997 | 13.996 | 8.748 | 12.247 | 1.000000 | 0.875000 | 287.066 | 128.221
231 BEREA #144 144 | 3PBP | OH | MEIGS | 9.997 | 13.996 | 8.748 | 12.247 | 1.000000 | 0.875000 | 287.066 | 122.248
171 CALHOUN CO., WV - COMPOSI | 1PDP | WV | CALHOUN | 0.000 | 0.000 | 0.000 | 0.000 | 1.000000 | 0.875000 | 0.000 | 0.000
2 GUAL # 402 BEREA 402 | 1PDP | OH | MEIGS | 8.392 | 21.486 | 7.343 | 18.800 | 1.000000 | 0.875000 | 157.555 | 96.996
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 | 343.843 | 0.000 | 300.863 | 1.000000 | 0.875000 | 449.741 | 272.524
6 JAY BLACKWOOD #165 | 1PDP | OH | MEIGS | 0.000 | 0.000 | 0.000 | 0.000 | 1.000000 | 0.875000 | 0.000 | 0.000
8 JIM BERNARD #167 | 1PDP | OH | MEIGS | 0.000 | 0.000 | 0.000 | 0.000 | 0.000000 | 0.000000 | 0.000 | 0.000
11 JIM ROUSH #178 | 1PDP | OH | MEIGS | 8.267 | 22.823 | 7.234 | 19.970 | 1.000000 | 0.875000 | 261.133 | 130.104
221 KARL RUSSELL #273 | 1PDP | OH | MEIGS | 17.073 | 18.697 | 14.939 | 16.360 | 1.000000 | 0.875000 | 549.825 | 242.494
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 | 437.614 | 0.000 | 382.912 | 1.000000 | 0.875000 | 208.872 | 173.023
1 MYERS # 401 BEREA WELL 40 | 1PDP | OH | MEIGS | 1.461 | 4.434 | 0.716 | 2.173 | 0.560000 | 0.490000 | 6.388 | 5.864
237 ORISKANY POSS 1 | 7POSS | WV | JACKSON | 0.000 | 390.646 | 0.000 | 341.815 | 1.000000 | 0.875000 | 484.144 | 274.159
234 ORISKANY PROB 1 | 6PROB | WV | JACKSON | 0.000 | 390.646 | 0.000 | 341.815 | 1.000000 | 0.875000 | 484.144 | 304.010
235 ORISKANY PROB 2 | 6PROB | WV | JACKSON | 0.000 | 390.646 | 0.000 | 341.815 | 1.000000 | 0.875000 | 484.144 | 301.575
236 ORISKANY PROB 3 | 6PROB | WV | JACKSON | 0.000 | 390.646 | 0.000 | 341.815 | 1.000000 | 0.875000 | 484.144 | 276.373
169 ROANE CO., WV - COMPOSITE | 1PDP | WV | ROANE | 0.000 | 1.420 | 0.000 | 1.242 | 1.000000 | 0.875000 | 0.018 | 0.018
222 ROGER GAUL #274 | 1PDP | OH | MEIGS | 19.481 | 53.875 | 17.046 | 47.141 | 1.000000 | 0.875000 | 742.004 | 315.496
230 RUTH MYERS #181 | 1PDP | OH | MEIGS | 4.677 | 18.053 | 4.093 | 15.796 | 1.000000 | 0.875000 | 137.638 | 78.186

79.347 2,512.821 68.866 2,197.011 | 5,023.881 2,721.291

TOTAL PROVED RESERVES

THIS SCHEDULE IS PART OF A REPORT AND SUBJECT TO QUALIFICATIONS OF THE REPORT.

LEE KEELING AND ASSOCIATES, INC.

SCHEDULE 4