EX-99.1 11 exhibit991.htm

Exhibit 99.1

 

 

 

 

 

 

 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

12/31/2018

 
 

Exhibit 99.1

 

 

 

 

 

 

 

 

 

INDEX

 

 

 

 

 

 

 

 

 

 

 

 
 

Exhibit 99.1

 

 

 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

 

 

 
 

Exhibit 99.1

 

 

LETTER

 

 
 

Exhibit 99.1

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 15, 2019

 

 

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, 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, 2018, and the results are summarized as follows:

  ESTIMATED REMAINING      
   NET RESERVES  FUTURE NET REVENUE
       
RESERVE  Oil  Gas  TOTAL  Disc. @ 10%
CLASSIFICATION  (BBLS)  (MCF)  ($)  ($)
             
Proved Developed            
Producing
   27,541    179,687    1,449,808     812,508 
Probable   —      1,566,088     2,530,288    1,646,987 
Possible   —      522,029    843,429    511,980 
Total All Reserves   27,541    2,267,804    4,823,525

 

    2,971,475 

 

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.

 
 

Exhibit 99.1

 

 

 

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 eleven (111) were selling gas with ten (10) 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 ten 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.

 

oShut-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.
oBehind-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.

 

 
 

Exhibit 99.1

 

 

 

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, 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 2018 through December 2018, as provided by the staff of Mountaineer.

 

These prices were $61.46 per barrel of oil, and $2.91 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.

 

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.

 
 

Exhibit 99.1

 

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.

 

 

 
 

Exhibit 99.1

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.

 
 

Exhibit 99.1

 

(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.

 
 

Exhibit 99.1

 

(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.

 
 

Exhibit 99.1

(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:

 
 

Exhibit 99.1

(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.

 
 

Exhibit 99.1

(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.

 
 

Exhibit 99.1

 

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.

 
 

Exhibit 99.1

 

 

 

 

 

 

 

 

 

SCHEDULE 1

 

 

 

 

 

 

Exhibit 99.1

 

MOUNTAINEER STATE ENERGY, INC. DATE : 03/14/2019  
OHIO AND WEST VIRGINIA PROPERTIES TIME : 16:29:50    
PROVED DEVELOPED PRODUCING RESERVES DBS : MountaineerSt
All Reserves SETTINGS: LKA0119  
  SCENARIO : LKA0119 

 

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

 

 

AS OF DATE: 01/2019

 

--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$----
12-2019 3.159 2.495 136.316 61.460 2.910 153.317 396.679 549.997
12-2020 2.848 433.668 2.243 379.056 61.460 2.910 137.867 1103.052 1240.920
12-2021 2.592 513.694 2.036 449.160 61.460 2.910 125.139 1307.056 1432.194
12-2022 2.375 388.652 1.862 339.806 61.460 2.910 114.430 988.834 1103.264
12-2023 2.189 294.736 1.713 257.672 61.460 2.910 105.278 749.825 855.103
12-2024 2.028 224.158 1.584 195.949 61.460 2.910        97.358 570.213 667.571
12-2025 1.887 171.088 1.471 149.538 61.460 2.910        90.428 435.156 525.584
12-2026 1.762 131.154 1.372 114.616 61.460 2.910        84.308 333.533 417.842
12-2027 1.651 95.570 1.283 83.497 61.460 2.910        78.861 242.977 321.837
12-2028 1.550 70.538 1.203 61.608 61.460 2.910        73.947 179.279 253.226
12-2029 1.458 53.846 1.130 47.014 61.460 2.910        69.474 136.812 206.286
12-2030 1.335 30.318 1.030 26.437 61.460 2.910        63.276 76.931 140.207
12-2031 1.183 8.502 0.904 7.356 61.460 2.910         55.545 21.406 76.951
12-2032 1.082 2.954 0.821 2.509 61.460 2.910        50.484 7.301 57.784
12-2033 1.027 2.796 0.780 2.376 61.460 2.910        47.921 6.915 54.837
S TOT 28.126 2578.060 21.927 2252.910 61.460 2.910 1347.633 6555.968 7903.603
AFTER 7.966 17.824 5.614 14.894 61.460 2.910 345.063 43.343 388.406
TOTAL 36.092 2595.884 27.541 2267.804 61.460 2.910 1692.696 6599.311 8292.009
--END-- AD VALOREM PRODUCTION DIRECT OPER INTEREST CAPITAL EQUITY FUTURE NET CUMULATIVE CUM. DISC.
MO-YEAR TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW
------- -----M$---- -----M$---- -----M$---- -----M$---- -----M$---- -----M$---- -----M$---- -----M$---- -----M$----
12-2019 19.433 18.993 57.819 0.000 0.000 700.000 -246.248 -246.248 -240.105
12-2020 36.011 54.412 97.563 0.000 0.000 700.000 352.934 106.686 60.979
12-2021 40.279 64.691 122.403 0.000 0.000 0.000 1204.822 1311.507 1010.361
12-2022 31.699 48.842 122.403 0.000 0.000 0.000 900.320 2211.828 1655.306
12-2023 25.187 36.943 122.403 0.000 0.000 0.000 670.570 2882.398 2092.000
12-2024 20.229 28.005 122.403 0.000 0.000 0.000 496.934 3379.331 2386.197
12-2025 16.441 21.289 122.403 0.000 0.000 0.000 365.451 3744.782 2582.885
12-2026 13.535 16.239 122.403 0.000 0.000 0.000 265.665 4010.447 2712.868
12-2027 10.946 11.739 109.155 0.000 0.000 0.000 189.998 4200.444 2797.380
12-2028 9.058 8.578 102.531 0.000 0.000 0.000 133.059 4333.503 2851.184
12-2029 7.725 6.477 102.531 0.000 0.000 0.000        89.553 4423.056 2884.104
12-2030 5.844 3.525 73.363 0.000 0.000 0.000        57.475 4480.532 2903.333
12-2031 3.965 0.812 31.333 0.000 0.000 0.000        40.841 4521.372 2915.745
12-2032 3.291 0.145 16.947 0.000 0.000 0.000        37.402 4558.774 2926.075
12-2033 3.123 0.137 16.947 0.000 0.000 0.000        34.630 4593.404 2934.770
S TOT 246.765 320.828 1342.605 0.000 0.000 1400.000 4593.404 4593.404 2934.770
AFTER 22.121 0.934 135.230 0.000 0.000 0.000 230.122 4823.526 2971.475
TOTAL 268.886 321.762 1477.835 0.000 0.000 1400.000 4823.526 4823.526 2971.475
    OIL GAS       P.W. % P.W., M$

 

GROSS WELLS

---------

14.0

---------

111.0

 

LIFE, YRS.

 

32.92

------

5.00

--------

3719.450

GROSS ULT., MB & MMF 81.103 13786.671 DISCOUNT % 10.00 10.00 2971.475
GROSS CUM., MB & MMF 45.011 11190.786 UNDISCOUNTED PAYOUT, YRS. 1.70 12.00 2735.643
GROSS RES., MB & MMF 36.092 2595.885 DISCOUNTED PAYOUT, YRS. 1.80 15.00 2431.188
NET RES., MB & MMF 27.541 2267.804 UNDISCOUNTED NET/INVEST. 4.45 20.00 2023.918
NET REVENUE, M$ 1692.696 6599.312 DISCOUNTED NET/INVEST. 3.34 25.00 1707.444
INITIAL PRICE, $ 61.460 2.910 RATE-OF-RETURN, PCT. 100.00 40.00 1084.502
INITIAL N.I., PCT. 78.970 87.165 INITIAL W.I., PCT. 99.167 60.00 642.513
          80.00 399.445
          100.00 252.222
                       

 

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

LEE KEELING AND ASSOCIATES, INC.

 

 

Exhibit 99.1

 

MOUNTAINEER STATE ENERGY, INC. DATE : 03/14/2019  
OHIO AND WEST VIRGINIA PROPERTIES TIME : 16:29:50    
PROVED DEVELOPED PRODUCING RESERVES DBS : MountaineerSt
SETTINGS: LKA0119  
  SCENARIO : LKA0119 

 

 

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

 

 

AS OF DATE: 01/2019

 

--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$----
12-2019 3.159 28.495 2.495 24.410 61.460 2.910 153.317 71.034     224.351
12-2020 2.848 24.904 2.243 21.387 61.460 2.910 137.867 62.236   200.103
12-2021 2.592 22.168 2.036 19.074 61.460 2.910 125.139 55.506   180.645
12-2022 2.375 20.007 1.862 17.241 61.460 2.910 114.430 50.172 164.602
12-2023 2.189 18.252 1.713 15.749 61.460 2.910 105.278 45.828 151.106
12-2024 2.028 16.796 1.584 14.507 61.460 2.910        97.358 42.215 139.573
12-2025 1.887 15.566 1.471 13.456 61.460 2.910        90.428 39.158 129.586
12-2026 1.762 14.512 1.372 12.555 61.460 2.910        84.308 36.535 120.843
12-2027 1.651 8.089 1.283 6.951 61.460 2.910        78.861 20.228 99.089
12-2028 1.550 4.927 1.203 4.198 61.460 2.910        73.947 12.217 86.164
12-2029 1.458 4.638 1.130 3.957 61.460 2.910        69.474 11.516 80.990
12-2030 1.335 4.133 1.030 3.525 61.460 2.910        63.276 10.257 73.532
12-2031 1.183 3.406 0.904 2.897 61.460 2.910        55.545 8.430 63.974
12-2032 1.082 2.954 0.821 2.509 61.460 2.910        50.484 7.301 57.784
12-2033 1.027 2.796 0.780 2.376 61.460 2.910        47.921 6.915 54.837
S TOT 28.126 191.641 21.927 164.793 61.460 2.910 1347.633 479.547 1827.180
AFTER 7.966 17.824 5.614 14.894 61.460 2.910 345.063 43.343 388.406
TOTAL 36.092 209.464 27.541 179.687 61.460 2.910 1692.696 522.890 2215.586
--END-- AD VALOREM PRODUCTION DIRECT OPER INTEREST CAPITAL EQUITY FUTURE NET CUMULATIVE CUM. DISC.
MO-YEAR TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW
------- -----M$---- -----M$---- -----M$---- -----M$---- -----M$---- -----M$---- -----M$---- -----M$---- -----M$----
12-2019 11.340 2.711 42.915 0.000 0.000   0.000 167.385 167.385 159.596
12-2020 10.144 2.372 42.915 0.000 0.000   0.000 144.672 312.058 284.995
12-2021 9.176 2.113 42.915 0.000 0.000 0.000 126.441 438.499 384.629
12-2022 8.372 1.909 42.915 0.000 0.000 0.000 111.407 549.905 464.435
12-2023 7.691 1.743 42.915 0.000 0.000 0.000 98.757 648.662 528.749
12-2024 7.107 1.605 42.915 0.000 0.000 0.000 87.946 736.608 580.815
12-2025 6.599 1.489 42.915 0.000 0.000 0.000 78.583 815.191 623.108
12-2026 6.154 1.390 42.915 0.000 0.000 0.000 70.385 885.576 657.546
12-2027 5.410 0.602 29.667 0.000 0.000 0.000 63.410 948.986 685.752
12-2028 4.906 0.225 23.043 0.000 0.000 0.000 57.990 1006.976 709.200
12-2029 4.612 0.212 23.043 0.000 0.000 0.000        53.124 1060.099 728.729
12-2030 4.187 0.191 22.027 0.000 0.000 0.000        47.127 1107.227 744.496
12-2031 3.643 0.163 19.741 0.000 0.000 0.000        40.428 1147.654 756.778
12-2032 3.291 0.145 16.947 0.000 0.000 0.000        37.402 1185.056 767.108
12-2033 3.123 0.137 16.947 0.000 0.000 0.000        34.630 1219.686 775.802
S TOT 95.754 17.007 494.733 0.000 0.000     0.000 1219.686 1219.686 775.802
AFTER 22.121 0.934 135.230 0.000 0.000 0.000 230.122 1449.808 812.508
TOTAL 117.875 17.941 629.963 0.000 0.000     0.000 4823.526 1449.808 812.508
    OIL GAS       P.W. % P.W., M$

 

GROSS WELLS

---------

10.0

---------

111.0

 

LIFE, YRS.

 

32.92

------

5.00

--------

1040.454

GROSS ULT., MB & MMF 81.103 11400.250 DISCOUNT % 10.00 10.00 2971.475
GROSS CUM., MB & MMF 45.011 11190.786 UNDISCOUNTED PAYOUT, YRS. 0.00 12.00 2735.643
GROSS RES., MB & MMF 36.092 209.464 DISCOUNTED PAYOUT, YRS. 0.00 15.00 2431.188
NET RES., MB & MMF 27.541 179.687 UNDISCOUNTED NET/INVEST. 0.00 20.00 2023.918
NET REVENUE, M$ 1692.696 522.89 DISCOUNTED NET/INVEST. 0.00 25.00 1707.444
INITIAL PRICE, $ 61.460 2.910 RATE-OF-RETURN, PCT. 100.00 40.00 1084.502
INITIAL N.I., PCT. 78.970 85.664 INITIAL W.I., PCT. 95.899 60.00 642.513
          80.00 399.445
          100.00 252.222
                       

 

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

LEE KEELING AND ASSOCIATES, INC.

 

Exhibit 99.1

 

MOUNTAINEER STATE ENERGY, INC. DATE : 03/14/2019  
OHIO AND WEST VIRGINIA PROPERTIES TIME : 16:29:50    
PROBABLE RESERVES DBS : MountaineerSt
SETTINGS: LKA0119  
  SCENARIO : LKA0119 

 

 

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

 

 

AS OF DATE: 01/2019

 

--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$----
12-2019 0.000 127.892 0.000 111.906 0.000 2.910 0.000 325.646 325.646
12-2020 0.000 351.552 0.000 307.608 0.000 2.910 0.000 895.138 895.138
12-2021 0.000 349.407 0.000 305.731 0.000 2.910 0.000 889.678 889.678
12-2022 0.000 262.055 0.000 229.298 0.000 2.910 0.000 667.258 667.258
12-2023 0.000 196.541 0.000 171.974 0.000 2.910 0.000 500.444 500.444
12-2024 0.000 147.406 0.000 128.980 0.000 2.910 0.000 375.333 375.333
12-2025 0.000 110.555 0.000 96.735 0.000 2.910 0.000 281.500 281.500
12-2026 0.000 82.916 0.000 72.551 0.000 2.910 0.000 211.125 211.125
12-2027 0.000 62.187 0.000 54.414 0.000 2.910 0.000 158.344 158.344
12-2028 0.000 46.640 0.000 40.810 0.000 2.910 0.000 118.758 118.758
12-2029 0.000 34.980 0.000 30.608 0.000 2.910 0.000 89.068 89.068
12-2030 0.000 15.514 0.000 13.575 0.000 2.910 0.000 39.504 39.504
12-2031 0.000 2.169 0.000 1.898 0.000 2.910 0.000 5.523 5.523
12-2032                  
12-2033                  
S TOT 0.000 1789.815 0.000 1566.088 0.000 2.910 0.000 4557.316 4557.316
AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
TOTAL 0.000 1789.815 0.000 1566.088 0.000 2.910 0.000 4557.316 4557.316
--END-- AD VALOREM PRODUCTION DIRECT OPER INTEREST CAPITAL EQUITY FUTURE NET CUMULATIVE CUM. DISC.
MO-YEAR TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW
------- -----M$---- -----M$---- -----M$---- -----M$---- -----M$---- -----M$---- -----M$---- -----M$---- -----M$----
12-2019 8.093 16.282 14.904 0.000 0.000 700.000 -413.633 -413.633 -399.701
12-2020 22.246 44.757 48.024 0.000 0.000 350.000 430.111 16.478 -30.647
12-2021 22.110 44.484 59.616 0.000 0.000 0.000 763.468 779.946 570.955
12-2022 16.583 33.363 59.616 0.000 0.000 0.000 557.697 1337.642 970.461
12-2023 12.437 25.022 59.616 0.000 0.000 0.000 403.369 1741.011 1233.146
12-2024 9.328 18.767 59.616 0.000 0.000 0.000 287.622 2028.633 1403.426
12-2025 6.996 14.075 59.616 0.000 0.000 0.000 200.813 2229.446 1511.504
12-2026 5.247 10.556 59.616 0.000 0.000 0.000 135.706     2365.152 1577.902
12-2027 3.935 7.917 59.616 0.000 0.000 0.000   86.875 2452.027 1616.544
12-2028 2.951 5.938 59.616 0.000 0.000 0.000   50.252 2502.280 1636.864
12-2029 2.214 4.453 59.616 0.000 0.000 0.000   22.785 2525.065 1645.240
12-2030 0.982 1.975 31.464 0.000 0.000 0.000  5.083 2530.147 1646.943
12-2031 0.137 0.276 4.968 0.000 0.000 0.000  0.141 2530.288 1646.987
12-2032                  
12-2033                  
S TOT 113.258 227.866 635.904 0.000 0.000 1050.000 2530.288 2530.288 1646.987
AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 2530.288 1646.987
TOTAL 113.258 227.866 635.904 0.000 0.000 1050.000 2530.288 2530.288 1646.987
    OIL GAS       P.W. % P.W., M$

 

GROSS WELLS

---------

3.0

---------

0.0

 

LIFE, YRS.

 

12.25

------

5.00

--------

2026.920

GROSS ULT., MB & MMF 0.000 1789.815 DISCOUNT % 10.00 10.00 1646.987
GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 1.96 12.00 1520.846
GROSS RES., MB & MMF 0.000 1789.815 DISCOUNTED PAYOUT, YRS. 2.05 15.00 1353.688
NET RES., MB & MMF 0.000 1566.088 UNDISCOUNTED NET/INVEST. 3.41 20.00 1122.820
NET REVENUE, M$ 0.000 4557.316 DISCOUNTED NET/INVEST. 2.70 25.00 938.003
INITIAL PRICE, $ 0.000 2.910 RATE-OF-RETURN, PCT. 100.00 40.00 561.472
INITIAL N.I., PCT. 0.000 87.500 INITIAL W.I., PCT. 100.000 60.00 284.994
          80.00 130.152
          100.00 35.798
                       

 

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

LEE KEELING AND ASSOCIATES, INC.

Exhibit 99.1

 

MOUNTAINEER STATE ENERGY, INC. DATE : 03/14/2019  
OHIO AND WEST VIRGINIA PROPERTIES TIME : 16:29:50    
POSSIBLE RESERVES DBS : MountaineerSt
SETTINGS: LKA0119  
  SCENARIO : LKA0119 

 

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

 

 

AS OF DATE: 01/2019

 

--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$----
12-2019 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
12-2020 0.000 57.213 0.000 50.061 0.000 2.910 0.000 145.679 145.679
12-2021 0.000 142.119 0.000 124.355 0.000 2.910 0.000 361.872 361.872
12-2022 0.000 106.590 0.000 93.266 0.000 2.910 0.000 271.404 271.404
12-2023 0.000 79.942 0.000 69.949 0.000 2.910 0.000 203.553 203.553
12-2024 0.000 59.957 0.000 52.462 0.000 2.910 0.000 152.665 152.665
12-2025 0.000 44.967 0.000 39.347 0.000 2.910 0.000 114.498 114.498
12-2026 0.000 33.726 0.000 29.510 0.000 2.910 0.000 85.874 85.874
12-2027 0.000 25.294 0.000 22.132 0.000 2.910 0.000 64.405 64.405
12-2028 0.000 18.971 0.000 16.599 0.000 2.910 0.000 48.304 48.304
12-2029 0.000 14.228 0.000 12.449 0.000 2.910 0.000 36.228 36.228
12-2030 0.000 10.671 0.000 9.337 0.000 2.910 0.000 27.171 27.171
12-2031 0.000 2.927 0.000 2.561 0.000 2.910 0.000 7.454 7.454
12-2032                  
12-2033                  
S TOT 0.000 596.605 0.000 522.029 0.000 2.910 0.000 1519.106 1519.106
AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
TOTAL 0.000 596.605 0.000 522.029 0.000 2.910 0.000 1519.106 1519.106
--END-- AD VALOREM PRODUCTION DIRECT OPER INTEREST CAPITAL EQUITY FUTURE NET CUMULATIVE CUM. DISC.
MO-YEAR TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW
------- -----M$---- -----M$---- -----M$---- -----M$---- -----M$---- -----M$---- -----M$---- -----M$---- -----M$----
12-2019 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
12-2020 3.620 7.284 6.624 0.000 0.000 350.000 -221.850        -221.850 -193.369
12-2021 8.993 18.094 19.872 0.000 0.000 0.000 314.913        93.063 54.777
12-2022 6.745 13.570 19.872 0.000 0.000 0.000 231.217        324.280 220.410
12-2023 5.059 10.178 19.872 0.000 0.000 0.000 168.444        492.724 330.105
12-2024 3.794 7.633 19.872 0.000 0.000 0.000 121.365        614.090 401.957
12-2025 2.846 5.725 19.872 0.000 0.000 0.000 86.056 700.146 448.272
12-2026 2.134 4.294 19.872 0.000 0.000 0.000 59.574 759.720 477.421
12-2027 1.601 3.220 19.872 0.000 0.000 0.000 39.712 799.432 495.085
12-2028 1.200 2.415 19.872 0.000 0.000 0.000 24.816 824.248 505.119
12-2029 0.900 1.811 19.872 0.000 0.000 0.000 13.644 837.893 510.135
12-2030 0.675 1.359 19.872 0.000 0.000 0.000 5.265 843.158 511.894
12-2031 0.185 0.373 6.624 0.000 0.000 0.000 0.272 843.429 511.980
12-2032                  
12-2033                  
S TOT 37.753 75.955 211.968 0.000 0.000 350.000 843.429        843.429 511.980
AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 843.429 511.980
TOTAL 37.753 75.955 211.968 0.000 0.000 350.000 843.429        843.429 511.980
    OIL GAS       P.W. % P.W., M$

 

GROSS WELLS

---------

1.0

---------

0.0

 

LIFE, YRS.

 

12.33

------

5.00

--------

652.075

GROSS ULT., MB & MMF 0.000 596.605 DISCOUNT % 10.00 10.00 511.980
GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 2.70 12.00 466.472
GROSS RES., MB & MMF 0.000 596.605 DISCOUNTED PAYOUT, YRS. 2.78 15.00 407.066
NET RES., MB & MMF 0.000 522.029 UNDISCOUNTED NET/INVEST. 3.41 20.00 326.958
NET REVENUE, M$ 0.000 1519.106 DISCOUNTED NET/INVEST. 2.70 25.00 264.754
INITIAL PRICE, $ 0.000 2.910 RATE-OF-RETURN, PCT. 100.00 40.00 145.081
INITIAL N.I., PCT. 0.000 87.500 INITIAL W.I., PCT. 100.000 60.00 66.139
          80.00 27.372
          100.00 6.830
                       

 

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

LEE KEELING AND ASSOCIATES, INC.

 

 

Exhibit 99.1

 

 

 

 

 

 

 

SCHEDULE 2

 

 

 

 

 

 

 

 

 
 

Exhibit 99.1

ESTIMATED RESERVES AND FUTURE NET REVENUE

MOUNTAINEER STATE ENERGY, INC.

MAXIMUM TO MINIMUM LEASE SUMMARY

AS OF DECEMBER 31, 2018

 

(SORTED BY RESERVE CATEGORY, DFNR)

DFNR

ARIES

 

ID.

Lease

RSV

CAT 

  State Location

 

 Gross OIL MBO

GROSS GAS

MMCF

NET OIL

MBO

NET GAS

MMCF

WORKING

INTEREST

REVENUE

INTEREST

CASHFLOW

(M$)

 DISC 10% (M$)
PROVED DEVELOPED PRODUCING RESERVES                  
222 ROGER GAUL #274 1PDP OH MEIGS 5.872 45.096 5.138 39.459 1.000000 0.875000 332.734 174.302
221 KARL RUSSELL #273 1PDP OH MEIGS 6.998 6.888 6.123 6.027 1.000000 0.875000 292.157 154.368
1 MYERS # 401 BEREA WELL 1PDP OH MEIGS 10.491 9.335 5.141 4.574 0.560000 0.490000 253.674 118.624
11 JIM ROUSH #178 1PDP OH MEIGS 4.745 15.768 4.152 13.797 1.000000 0.875000 212.974 115.764
2 GUAL # 402 BEREA 1PDP OH MEIGS 2.957 12.349 2.587 10.805 1.000000 0.875000 143.506 98.737
233 JACKSON CO., WV #347 1PDP WV JACKSON 0.000 101.428 0.000 88.749 1.000000 0.875000 73.329 59.234
6 JAY BLACKWOOD #165 1PDP OH MEIGS 2.227 7.910 1.949 6.921 1.000000 0.875000 62.499 36.591
238 F.BERL BOGGS #190 1PDP OH MEIGS 1.656 3.770 1.449 3.299 1.000000 0.875000 43.808 28.585
230 RUTH MYERS #181 1PDP OH MEIGS 1.146 6.921 1.003 6.056 1.000000 0.875000 35.125 26.302
171 CALHOUN CO., WV - COMPOSITE 1PDP WV CALHOUN 0.000 0.000 0.000 0.000 1.000000 0.875000 0.000 0.000
170 JACKSON CO., WV - COMPOSITE 1PDP WV JACKSON 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
172 MEIGS CO., OHIO - COMPOSITE 1PDP OH MEIGS 0.000 0.000 0.000 0.000 1.000000 0.875000 0.000 0.000
169 ROANE CO., WV - COMPOSITE 1PDP WV ROANE 0.000 0.000 0.000 0.000 1.000000 0.875000 0.000 0.000
          36.092 209.464 27.541 179.687     1,449.808 812.508

 

TOTAL PROVED DEVELOPED PRODUCING RESERVES

PROBABLE UNDEVELOPED RESERVES

234   ORISKANY PROB 1 6PROB WV JACKSON 0.000 596.605 0.000 522.029 1.000000 0.875000 843.430 567.710
235   ORISKANY PROB 2 6PROB WV JACKSON 0.000 596.605 0.000 522.029 1.000000 0.875000 843.429 563.178
236   ORISKANY PROB 3 6PROB WV JACKSON 0.000 596.605 0.000 522.029 1.000000 0.875000 843.430 516.100
TOTAL PROBABLE UNDEVELOPED RESERVES

POSSIBLE UNDEVELOPED RESERVES

 0.000 1,789.815 0.000 1,566.088     2,530.288 1,646.987
237   ORISKANY POSS 1 7POSS WV JACKSON 0.000 596.605 0.000 522.029 1.000000 0.875000 843.429 511.980
  TOTAL POSSIBLE UNDEVELOPED RESERVES 0.000 596.605 0.000 522.029     843.429 511.980
  TOTAL PROVED RESERVES 36.092 2,595.884 27.541 2,267.805     4,823.526 2,971.475
                   

 

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

LEE KEELING AND ASSOCIATES, INC.

 

 
 

Exhibit 99.1

 

 

 

 

 

 

 

 

 

SCHEDULE 3

 

 

 

 

 

 

 

 

 

 

 

 
 

Exhibit 99.1

 

 

 

ESTIMATED RESERVES AND FUTURE NET REVENUE

MOUNTAINEER STATE ENERGY, INC.

MAXIMUM TO MINIMUM LEASE SUMMARY

AS OF DECEMBER 31, 2018

 

(SORTED BY RESERVE CATEGORY, DFNR)

DFNR

ARIES

 

ID.

Lease

RSV

CAT 

  State 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
171 CALHOUN CO., WV - COMPOSI 1PDP WV CALHOUN 0.000 0.000 0.000 0.000 1.000000 0.875000 0.000 0.000
238 F.BERL BOGGS #190 1PDP OH MEIGS 1.656 3.770 1.449 3.299 1.000000 0.875000 43.808 28.585
2 GUAL # 402 BEREA 402 1PDP OH MEIGS 2.957 12.349 2.587 10.805 1.000000 0.875000 143.506 98.737
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 0.000 101.428 0.000 88.749 1.000000 0.875000 73.329 59.234
6 JAY BLACKWOOD #165 1PDP OH MEIGS 2.227 7.910 1.949 6.921 1.000000 0.875000 62.499 36.591
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 4.745 15.768 4.152 13.797 1.000000 0.875000 212.974 115.764
221 KARL RUSSELL #273 1PDP OH MEIGS 6.998 6.888 6.123 6.027 1.000000 0.875000 292.157 154.368
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 0.000 0.000 0.000 1.000000 0.875000 0.000 0.000
1 MYERS # 401 BEREA WELL 40 1PDP OH MEIGS 10.491 9.335 5.141 4.574 0.560000 0.490000 253.674 118.624
237 ORISKANY POSS 1 7POSS WV JACKSON 0.000 596.605 0.000 522.029 1.000000 0.875000 843.429 511.980
234 ORISKANY PROB 1 6PROB WV JACKSON 0.000 596.605 0.000 522.029 1.000000 0.875000 843.430 567.710
235 ORISKANY PROB 2 6PROB WV JACKSON 0.000 596.605 0.000 522.029 1.000000 0.875000 843.429 563.178
236 ORISKANY PROB 3 6PROB WV JACKSON 0.000 596.605 0.000 522.029 1.000000 0.875000 843.430 516.100
169 ROANE CO., WV - COMPOSITE 1PDP WV ROANE 0.000 0.000 0.000 0.000 1.000000 0.875000 0.000 0.000
222 ROGER GAUL #274 1PDP OH MEIGS 5.872 45.096 5.138 39.459 1.000000 0.875000 332.734 174.302
230 RUTH MYERS #181 1PDP OH MEIGS 1.146 6.921 1.003 6.056 1.000000 0.875000 35.125 26.302
     TOTAL PROVED RESERVES 36.092 2,595.884 27.541 2,267.805     4,823.526 2,971.475

 

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

LEE KEELING AND ASSOCIATES, INC.