corresp

METZGER & McDONALD PLLC
A PROFESSIONAL LIMITED LIABILITY COMPANY
ATTORNEYS, MEDIATORS & COUNSELORS



Steven C. Metzger	3626 N. Hall Street, Suite 800
Direct Dial 214-740-5030	Dallas, Texas 75219-5133	Facsimile 214-224-7555
smetzger@pmklaw.com	214-969-7600	214-523-3838
	www.pmklaw.com	214-969-7635

	May 21, 2010

Via EDGAR

The Securities and Exchange Commission
100 F Street, Mail Stop 4628
Washington, D.C. 20549
Attn: Karl Hiller, Branch Chief
Joanna Lam, Staff Accountant

Re:

New Concept Energy, Inc. (Commission File No. 000-08187; CIK No. 0000105744) — Form 10-K for the fiscal year ended December 31, 2009 filed March 31, 2010; Response Letter dated March 16, 2010

Ladies and Gentlemen:

On behalf of New Concept Energy, Inc., a Nevada corporation (“GBR”) this letter is being filed as correspondence uploaded on the EDGAR system on behalf of GBR in response to a letter of comment from the Staff of the Securities and Exchange Commission dated April 19, 2010. Schedule 1 annexed to this letter contains the responses to the comments of the Staff. In each instance on such Schedule, for convenience, each comment of the Staff is repeated, followed in each instance by the applicable response to such comment or explanation. Also included in such response, where appropriate, is a letter/page reference to the text to the applicable document or instrument referred to in the comment.

This letter is being filed under the EDGAR system in direct response to the comments of the Staff. If you would like to discuss any item concerning the referenced matter included in this letter or Schedule 1, please do not hesitate to contact the undersigned at any time at 214-740-5030 direct or Gene S. Bertcher, President of GBR at 469-522-4238 direct.


	Very truly yours,
	/s/ Steven C. Metzger
	Steven C. Metzger

cc:

Gene S. Bertcher, President
New Concept Energy, Inc.
1755 Wittington Place, Suite 340
Dallas, Texas 75234

SCHEDULE 1

Response to Comments of the Staff of
the Securities and Exchange Commission
by letter dated April 19, 2010 with respect to
Form 10-K for the fiscal year ended December 31, 2009 and
Response Letter dated March 16, 2010
Commission File No. 000-08187

The following information is to provide a response to comments of the Staff of the Securities and Exchange Commission rendered by letter dated April 19, 2010 with respect to Form 10-K Annual Report to the Securities and Exchange Commission for the fiscal year ended December 31, 2009 of New Concept Energy, Inc. (the “Company” or “GBR”) as well as a prior response letter dated March 16, 2010 of the Company. For convenience, each comment of the Staff is restated below, with our response noted immediately following the comment. Also included in such response is a letter/page reference to the text of each instrument where applicable. Certain attachments are referenced below which are attached and which contain certain revisions or proposed disclosure when the Company files a Form 10-K/A to respond to the comments below after the Staff approves and clears such proposed revised disclosure.

Form 10-K for the Fiscal Year Ended December 31, 2009

General

Comment/Observation No. 1. We note that you continue to describe a policy of assessing your oil and gas properties for impairment following the guidance in SFAS 144 in our discussion of critical accounting policies on page 13 and in your summary of accounting policies under Note B to your financial statements on page 42. Please see comment 7 in our letter dated December 15, 2009, in which we advised you that this method of assessing impairment is not appropriate in your circumstances, given that you chose to follow the full cost method.

We believe that you need to revise your accounting policy to comply with the requirements of Rule 4-10(c)(4) of Regulation S-X, and to amend your filing to make corresponding changes to the disclosures mentioned above and to correct your financial statements to the extent necessary to adhere to this guidance.

The disclosure that you have on page 43, referencing a ceiling test, does not appear to be consistent with the requirements in the approach and frequency. For example, while you indicate that you conduct a test on an annual basis, it should be applied at each balance sheet date (quarterly) to comply with Rule 4-10(c)(4). You also indicate that your test is based on the present value of net reserves, however, this is not one of the four main components that you must compute in determining the ceiling to which capitalize costs are compared — none of which you have mentioned in describing your version of the ceiling test.

When reformulating your accounting policy and disclosures please ensure that you provide an accurate description of the ceiling test that is required to comply with GAAP, and which differentiates between impairments and ceiling test write-downs, as these have distinct qualities under the full cost rules -impairments result from the assessments required under Rule 4-10(c)(3)(ii)(A), the amounts impaired are added to the costs subject to amortization - conversely, ceiling test write-downs may arise when you

conduct the ceiling test required under Rule 4-10(c)(4), the write-downs are recognized as a charge against earnings.

Response to Comment/Observation No. 1.

The description of the policy of assessing oil and gas properties has been modified to be in comply with Rule 4-10(c)(4) of Regulation S-X. The Company’s December 31, 2009 Form 10-K and all future filings will include the following or similar language:

The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas reserves (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion exceed the discounted future net revenues of proved oil and natural gas reserves net of deferred taxes, such excess capitalized costs are charged to expense. Beginning December 31, 2009, full cost companies use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date to calculate the future net revenues of proved reserves. Prior to December 31, 2009, companies used the price in effect at the calculation date and had the option, under certain circumstances, to elect to use subsequent commodity prices if they increased after the calculation date.

The Company assesses its oil and gas properties on a quarterly basis for possible impairment or reduction in value. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

There is no required change to the Company’s December 31, 2009 financial statements as a result of the change in the policy language. See also attached revised Note B — Summary of Significant Accounting Policies — Full Cost Testing.

Properties, page 8

Comment/Observation No. 2. You have disclosure under Oil and Gas Reserves in Note B to your financial statements on page 42, indicating that while certain technology may identify possible or probable reserves by methods other than drilling, these reserves may not be disclosed under current SEC rules. However, under Item 1202(a)(2)(iv) through (vi) of Regulation S-K, issuers may disclose both possible and probable reserves as defined in Rule 4-10(a)(17) and (18) of Regulation S-X. Please modify your disclosure accordingly.

Response to Comment/Observation No. 2.

The disclosure has been removed regarding possible and probable reserves in Note B to the

financial statements and on page 16 as the Company does currently have any such reserves.

Comment/Observation No. 3. Currently, part of the disclosure of your oil and gas operations are under “Business” and part are provided under “Properties.” Given the related nature of these disclosures, please combine under one heading.

Response to Comment/Observation No. 3.

The oil and gas disclosures have been revised to put all business information in “Item 1. Business” and only property information in “Item 2. Properties”. See the proposed revisions attached under each caption.

Comment/Observation No. 4. Please expand your disclosure to provide the following information, which should generally be reported for each geographic area of each year. We have included reference to the specific sections of Subpart 1200 requiring these disclosures.

	•		Proved undeveloped reserves by product type — Item 1202(a)(2)(ii)

	•		A description of the technologies used to establish the appropriate level of certainty for the reserve estimates you disclose — Item 1202(a)(6)

	•		A description of the internal controls used in your reserve estimation effort including those required to ensure that information taken from third party reports is properly disclosed in your filing — Item 1202(a)(7)

	•		A description of the qualifications of the technical person with the third party engineering firm overseeing the work performed — Item 1202(a)(7)

	•		A discussion of material changes in proved undeveloped reserves that occurred during each period covered by the report, including quantities converted to proved developed reserves — Item 1203(b)

	•		A discussion of investments (e.g. capital expenditures) and progress made during each year to convert proved undeveloped reserves to proved developed reserves — Item 1203(c)

	•		A discussion covering the extent of drilling and exploratory efforts, including the number of productive and dry exploratory and development wells, and other exploratory and development activities — Item 1205

	•		A description of present activities underway as of year-end or in close proximity to the date of filing your report — Item 1206

	•		The number of gross and net productive wells, separately for oil and gas, and total gross and net productive acreage — Item 1208(a)

	•		The number of gross and net unproductive acreage — Item 1208(b)

Response to Comment/Observation No. 4.

The oil and gas properties disclosure has been expanded to include the required disclosures for a) proved undeveloped reserves, b) technologies used to establish certainty for reserve estimates, c) internal controls used to insure information from third party reserve reports is properly disclosed, d) description of the qualifications of the reserve engineering firm, e) productive well information, and f) unproductive acreage information. See proposed Items 1 “Business” and 2 “Properties” attached.

Comment/Observation No. 5. You indicate on page 8 that your third party engineers estimated total proved reserves at $11,372,000 as of December 31, 2009. We expect that you will need to modify your disclosure to clarify that this amount does not represent the current market value of your reserves, consistent with your disclosure on page 14, and to explain the basis of the calculation underlying this figure. Based on the report of your engineers, it appears you are referring to either an estimate of the present value of future net revenues associated with both developed and undeveloped reserves or the standardized measure reported on page 59.

Response to Comment/Observation No. 5.

The disclosure in Item 1: Business has been modified to correctly refer to the estimate of the present value of future net revenues associated with our proved developed and undeveloped reserves. See proposed Item 1 “Business” attached.

Comment/Observation No. 6. We note that you have identified a third party engineering firm as having prepared the reserve estimates that you disclosed and see that you attached a report from that firm as an exhibit to your filing. However, that report does not comply with Item 1202(a)(8) of Regulation S-K in certain respects, and we have several other concerns about the representations that have been made. We expect that you will need to discuss the following points with your third party engineering firm, and obtain and file a report that complies with the aforementioned guidance. Please contact us by telephone if you or your third party engineering firm requires further clarification or guidance about the representations that are required.

	•		The report indicates that it includes various summaries that are contained on four schedules. It appears you would need to attach these schedules in order for the report to be complete. If such information is not intended to be part of the summary of conclusions, the report will need to clarify.

	•		The report states that the reserves estimated “may or may not be actually recovered...,” and includes definitions of proved developed and proved undeveloped reserves that are purported to comply with the SEC guidance but which do not coincide, particularly in stating that such reserves are those which “can be expected to be recovered...,” or “are expected to be recovered” The definition of proved reserves in Rule 4-10(a)(22) of Regulation S-X requires “reasonable certainty” of being able to produce those quantities economically, under current operating conditions, prior to the expiration of contracts under which the right to extract is held, and commencing within a reasonable period of time. The guidance in Rule 4-10(a)(24) explains what is meant by reasonable certainty. If you do not have this level of confidence, you would not have appropriately identified those quantities as proved reserves. The estimation of reserves and the definitions contained in the report need to conform to Rule 4-10(a).

The remaining points list specific details that your third party engineer would need to add to the report to conform with Item 1202(a)(8) of Regulation S-K, although if these representations would not be consistent with the procedures conducted by your third party engineer in estimating your reserves, you should instead contact us by telephone to discuss an appropriate course of action.

	•		The portion of your total reserves that are covered by the report.

	•		A statement that the assumptions, data, methods, and procedures used, are appropriate for the purpose served by the report.

	•		A discussion of the possible effects of regulation on your ability to recover the estimated reserves.

	•		A statement that the engineer has used all methods and procedures as it considered necessary under the circumstances to prepare the report.

	•		The signature of the engineer.

Response to Comment/Observation No. 6.

A revised reserve report letter has been obtained from the reserve engineering firm which is in compliance with Item 1202{a)(8) of Regulation S-X including, a) appropriate certainty language, b) a statement that the reserve report covers all of the Company’s reserves, b) a statement as to the assumptions, data, methods and procedures used, c) discussion of the effects of possible regulations, and d) a statement as to the methods and procedures used by the engineer. In addition, the reserve report letter was modified to remove reference to “Schedule 4” which was primarily detailed lease by lease graphs and charts which was considered to voluminous to include as and exhibit to the Form 10-K. This information is included as and attachment to this letter for your review. The signed revised reserve letter and the referenced schedules will be attached as an exhibit to our amended Forml0-K/A. The revised report and the supplemental information previously referred to as “Schedule 4” is attached to this correspondence for you review. See the attachment letter dated March 23, 2010 from Lee Keeling and Associates, Inc.

Financial Statements

General

Comment/Observation No. 7. We note that you have presented a combined total of costs related to developed and undeveloped properties on your balance sheet. The amounts pertaining to unproved properties and major development projects that are properly excluded from the amounts being amortized must be presented separately to comply with Rule 4-10(c)(7)(ii) of Regulation S-X. Please revise accordingly.

Response to Comment/Observation No. 7.

As of December 31, 2009 and 2008, all of the Company’s oil and gas properties were proved developed or proved undeveloped. As of those dates, the Company did not have any unproved properties or major development projects that would be required to be separately disclosed under Rule 4-10(c)(7)(ii) of Regulation S-X.

Note A — Business Description and Presentation, page 39

Comment/Observation No. 8. Please modify your disclosure concerning your September 2008 acquisitions to specify the total cost and to include your purchase price allocation to comply with paragraph 51(d), (e) and (h) and SFAS 141. Please specify the amounts ascribed to both proved properties and to unproved properties.

Response to Comment/Observation No. 8.

The information regarding the purchase cost and purchase price allocation will be added to Note A to the financial statements under the section titled “Acquisition of Carl E. Smith Companies” in the amended Form 10-K/A. See proposed disclosure attached under Note A — Business Description and Presentation.

Note P — Supplemental Financial Information on Oil and Natural Gas Exploration. Development and Production Activities, page 58

Comment/Observation No. 9. We note that you have not followed the guidance in FASB ASC Section 932-235-50, as amended by FASB ASU 2010-03 in preparing your disclosures. Please revise as necessary to address the following points. We have included reference to the specific sections of the guidance requiring these disclosures.

	•		Quantity proved undeveloped reserves as of the beginning and end of each year presented - - FASB ASC paragraph 932-235-50-4.

	•		Identify and discuss important economic factors and uncertainties affecting reserves - FASB ASC paragraph 932-235-50-10.

	•		Identify amounts capitalized for oil and gas producing activities in total and separately for unproved properties, and the related accumulated DD&A — FASB ASC paragraphs 932- 235-50-13 and 14.

	•		Disclose acquisition, exploration and development costs incurred each year - FASB ASC paragraph 932-235-50-18.

	•		Identify the sources of change in the standardized measure of discounted future cash flows for each year — FASB ASC paragraph 932-235-50-35.

Response to Comment/Observation No. 9.

Note P to the financial statements has been modified to include information regarding a) proved undeveloped reserves, b) amounts capitalized for oil and gas activities, c) acquisition, exploration and development costs, and d) changes in the standardized measure of discounted future cash flows. See attached proposed disclosure. Other requirements of FASB ASC Section 932-235-50, as amended by FASB ASU 2010-03 are not applicable.

PART I

Item 1. Business

New Concept Energy, Inc. (“New Concept”, “NCE” or the “Company” or “we” or “us”) was incorporated in Nevada on May 31, 1991, under the name Medical Resource Companies of America, Inc. The Company is the successor-by-merger to Wespac Investors Trust, a California business trust that began operating in 1982. On March 26, 1996, the name was changed to Greenbriar Corporation. On February 8, 2005, the name of the Company was changed to CabelTel International Corporation. On May 21, 2008, the name of the company was changed to New Concept Energy, Inc.

Oil and Gas Operations

In September 2008, the Company completed the acquisition of certain entities, mineral interests and related assets through its wholly owned subsidiaries Mountaineer State Energy, Inc. and Mountaineer State Operations, LLC. The Company now operates oil and gas wells and mineral leases in Athens and Meigs Counties in Ohio and in Calhoun, Jackson and Roane Counties in West Virginia. The assets acquired included 114 producing gas wells, 101 non-producing wells and related equipment and mineral leases.

At December 31, 2009, 122 wells are producing. The company engaged the firm of independent oil and gas engineers Lee Keeling & Associates, Inc. to estimate the net oil and gas reserves. On the basis of their study, the estimate of the present value of future net revenues were estimated to be $11.4 million at December 31, 2009.

The wells in West Virginia and Ohio were drilled prior to acquisition. The majority of wells are located on leased property under mineral rights contracts. While some wells were drilled in the 1960’s, the majority were drilled in the 1970’s and 1980’s. The acquisition was contemplated with the intention of re-working existing wells in different geological formations using modern technologies, and then drilling new wells in strategic locations.

In addition to the wells and mineral leases, the acquisition included a complex covering approximately 41 acres of land with 8,000 square feet of office and storage buildings, an adjacent 12 acre site with a 24 stall horse barn, machinery and equipment in excess of the needs of the gas operation and approximately $1.5 million in cash. During 2009, the Company sold various equipment and vehicles not necessary for operations. As of December 31, 2009, the horse barn, the undeveloped land, and one piece of heavy equipment remain unsold.

Estimates of total, proved net oil or gas reserves

Reserve Rule Changes: During 2009, the SEC issued its final rule on the modernization of oil and gas reporting (the “Reserve Ruling”) and the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update No. 2010-03 (“ASU 2010-03”) “Extractive Industries — Oil and Gas,” which aligns the estimation and disclosure requirements of FASB

Accounting Standards Codification Topic 932 with the Reserve Ruling. The Reserve Ruling and ASU 2010-03 are effective for Annual Reports on Form 10-K for fiscal years ending on or after December 31, 2009. The key provisions of the Reserve Ruling and ASU 2010-03 are as follows:

	•		Expanding the definition of oil and gas-producing activities to include the extraction of saleable hydrocarbons, in the solid, liquid or gaseous state, from oil sands, coalbeds or other nonrenewable natural resources that are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction;

	•		Amending the definition of proved oil and gas reserves to require the use of an average of the first-day-of-the-month commodity prices during the 12-month period ending on the balance sheet date rather than the period-end commodity prices;

	•		Adding to and amending other definitions used in estimating proved oil and gas reserves, such as “reliable technology” and “reasonable certainty”;

	•		Broadening the types of technology that an issuer may use to establish reserves estimates and categories; and,

	•		Changing disclosure requirements and providing formats for tabular reserve disclosures.

According to our independent reserve engineering firm, Lee Keeling & Associates, Inc., as of December 31, 2009, our Proved Reserves were approximately 7.6 million Mcf of natural gas. Of the total Proved Reserves, approximately 38% were Proved Developed Reserves. As of December 31, 2009, the related PV-10 of our Proved Reserves was approximately $11.4 million. During the year ended December 31, 2009, we produced approximately 236,000 Mcf of natural gas.

Additional Oil and Gas Information

	•		Average sales price per unit — $5.26 per Mcf

	•		Average production cost per unit — $3.05 per Mcf

	•		Productive wells — 122 productive wells

	•		Developed acreage — approximately 20,000 acres

	•		Drilling activity — Since the date of acquisition, the Company has reworked numerous wells and is continuing the reworking of additional wells in 2010. In 2010, we have tentatively scheduled a “behind-the-pipe” drilling schedule, in addition to new site drilling, subject to favorable market conditions.

	•		Delivery Commitments — For fiscal 2010, the Company has contracted with Dominion Field Services, Inc. to purchase the Company’s gas production. The contract is separated into production from the Ohio wells and the West Virginia wells. Ohio gas is under contract for $6.01 per dekatherm and West Virginia gas at $6.08 per dekatherm at a volume of 20,000 dekatherms per month. Our gas converts from dekatherms to Mcf at a ratio of approximately 1.2, which equates to 16,667 Mcf per month. There is no penalty to the Company for not reaching the contract volume. Volume exceeding the contract volume will be settled at the spot price.

Retirement Community

The Company leases and operates Pacific Pointe Retirement Inn (“Pacific Pointe”) in King City, Oregon. Pacific Pointe began operations in 1993, has a capacity of 114 residents and provides community living with basic services such as meals, housekeeping, laundry, 24/7 staffing, transportation and social and recreational activities. These residents do not yet need assistance or support with activities of daily living but prefer the physical and psychological comfort of a residential community of like-minded people and access to senior-oriented services.

At Pacific Pointe, the Company’s marketing and sales efforts are undertaken at the local level. These efforts are intended to create awareness of our community and its services among prospective residents, their families, other key decision-makers and professional referral sources.

Business Strategy

The Company is a Nevada corporation which had historically been a real estate company, owning or leasing retirement specific real estate, an outlet shopping mall (sold 2008) and certain oil and natural gas leases through subsidiaries.

The Company intends to continue to pursue acquisition of undervalued or distressed oil and gas related businesses, as well as additional acquisitions of oil and gas leases. The Company may choose to develop or resell the acquired acreage as management deems most beneficial to the Company.

The Company intends to maintain its interest in the retirement center, however, for the foreseeable future, management intends to focus its efforts on oil and gas and energy related investments.

Insurance

The Company currently maintains property and liability insurance intended to cover claims in its oil and gas operations, retirement community and corporate operations. The provision of personal services entails an inherent risk of liability compared to more institutional long-term care communities. The Company also carries property insurance on each of its owned and leased properties, as appropriate.

Employees

At December 31, 2009, the Company employed, in all segments, 51 people (26 full-time and 25 part-time). The Company believes it maintains good relationships with its employees. None of the Company’s employees are represented by a collective bargaining group.

The Company’s operations are subject to the Fair Labor Standards Act. Many of the Company’s employees are paid at rates related to the minimum wage and any increase in the minimum wage will result in an increase in labor costs.

Management is not aware of any non-compliance by the Company as regards applicable regulatory requirements that would have a material adverse effect on the Company’s financial condition or results of operations.

Quality Assurance

Energy Philosophy — The Company is committed to the preservation and enhancement of the environment in which we operate. We are philosophically and operationally focused to continually prioritize the sensitivity of our ecological system in which we develop resources for our generation as well as our children’s. Management’s legacy is to prove that the energy industry can develop the earth’s natural resources with clean and efficient technologies while preserving its fragile beauty. Our technologies directly and significantly reduce the impact of our operations on nature and wildlife by minimizing surface disturbance.

Retirement Center Philosophy — The Company’s philosophy of management is to demonstrate by its actions and require from its employees high standards of personal integrity, to develop a climate of openness and trust, to demonstrate respect for human dignity in every circumstance, to be supportive in all relationships, to promote teamwork by involving employees in the management of their own work and to promote the free expression of ideas and opinions. In operating a retirement community, our commitment to quality assurance is designed to achieve a high degree of resident and family member satisfaction with the care and services the Company provides.

Regular Property Inspections — Property inspections are conducted by corporate personnel. These inspections cover the appearance of the exterior and grounds, the appearance and cleanliness of the interior, the professionalism and friendliness of staff and notes on maintenance.

Marketing

One purchaser comprises approximately 90% of the Company’s natural gas production. While there is an available market for crude oil and natural gas production, we cannot be assured that the loss of this purchaser would not have a material impact on the Company.

At Pacific Pointe, the Company’s marketing and sales efforts are undertaken at the local level. These are intended to create awareness of our property and its services among prospective residents, their families and other key referral sources. The property engages in traditional types of marketing activities such as special events, radio spots, direct mailings, print advertising, signs and yellow page advertising. These marketing activities and media advertisements are directed to potential customers.

Government Regulation

Competition

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and personnel substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.

We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. We are unable to predict when, or if, such shortages may again occur or how they would affect our development and exploitation program.

Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete satisfactorily. Many large oil companies have been actively marketing some of their existing producing properties for sale to independent producers. We regularly evaluate acquisition opportunities and submit bids as part of our growth strategy.

Our retirement community is in a highly competitive environment which and will continue to become increasingly competitive in the future. The Company competes with other retirement companies and numerous other companies providing similar long-term care alternatives, such as home healthcare agencies, community-based service programs and convalescent centers (nursing homes).

Item 2. Properties

The Company’s principal offices are located at 1755 Wittington Place, Dallas, Texas 75234 in approximately 5,000 square feet of leased office space. The Company believes this space is presently suitable, fully utilized and will be adequate for the foreseeable future.

Retirement Community

The Company’s retirement community is suitable and adequate for the purpose to which it is devoted.

Oil and Gas

Reserve Estimation

The Company’s producing properties have been in production for over 20 years. Because individual well production volumes were not available, composite production decline curves were constructed for each of the five counties in which these wells are located. All five composite decline curves exhibit well-established production decline trends. After reviewing all available information, it was determined that the most reliable method of estimating the Proved Developed Producing Reserves was by extrapolation of the existing production decline trends to the economic limit of production.

Proved Undeveloped Reserves were estimated by analogy to currently producing wells in the various areas producing from the same formations.

The Company’s reserve reports are prepared by independent petroleum engineers. The process used to control the information provided to the independent petroleum engineers includes an initial compilation of production data by experienced senior management personal in the Company’s field office. This data is independently reviewed by appropriate personal in the company’s corporate office prior to being submitted to the independent petroleum engineer. The submitted data is ultimately compared to the final reserve report and then agreed to the financial statement disclosures prepared by the Company.

The Company uses the petroleum engineering firm of Lee Keeling and Associates, Inc. to prepare its reserve estimates and future net revenues from its oil and gas properties. The work is performed by a registered professional engineer who is a member of the Society of Petroleum Engineers with over 40 years of experience in the oil and gas industry.

Development plan

The oil and gas properties owned and operated by the Company consist of 215 wells located on 20,000 acres in Ohio and West Virginia. These wells were drilled over 20 years ago when the science and technology of the oil and gas industry was not as sophisticated as it is today. In addition the company’s wells are located in an area where a number of wells, other than ours, have been drilling and the results of those efforts are available.

The company’s plan is to use the current knowledge of the area and the new technologies available to rework its existing wells. This represents the most economic way to increase production. Once this is accomplished the company will begin the process of identifying locations throughout its acreage to drill new wells.

Proved Reserves

The following table presents our estimated proved reserves as of December 31, 2009. These estimates correspond with the method used in presenting the “Supplemental Information on Oil and Gas Operations” in Note P to our consolidated financial statements included in this report.


	Gas		Oil
	(MBBLS)		(MMCF)
Proved Reserves
U.S. Onshore
Developed Producing		2,467		19
Developed Non-Producing		400		—
Undeveloped		4,694		—


Total Proved Reserves		7,561		19

The following table presents the changes in our total proved undeveloped reserves.


	Gas		Oil
	(MBBLS)		(MMCF)
Proved undeveloped reserves as of December 31, 2007		—		—
Purchases of reserves in place		4,694		—
Conversion to proved developed reserves		—		—


Proved undeveloped reserves as of December 31, 2008		4,694		—
Conversion to proved developed reserves		—		—


Proved undeveloped reserves as of December 31, 2009		4,694		—

Well Statistics

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation

Overview

Effective September 1, 2008, the Company completed the acquisition of certain entities, mineral interests and related assets through entities named Carl E. Smith, Inc., a West Virginia corporation, two of its affiliates, Carl E. Smith Petroleum, Inc. and Carl E. Smith Real Estate, Inc. and other privately owned related assets (collectively “CESI”). Immediately after the acquisition, all of the acquired entities and assets were merged into Carl E. Smith, Inc., the name of which was changed to Mountaineer State Energy, Inc. (“Mountaineer”) which became a wholly-owned subsidiary of NCE. The assets acquired include 94 producing gas wells, 121 non-producing wells and related equipment, mineral leases covering 20,000 acres located in Athens and Meigs Counties in Ohio as well as Calhoun, Jackson and Roane Counties in West Virginia. In addition to the wells and mineral leases, the acquisition included a complex covering approximately 41 acres of land with 8,000 square feet of office and storage buildings, an adjacent 12 acre site with a 24 stall horse barn, machinery and equipment in excess of the needs of the gas operation and approximately $1.5 million in cash. NCE has evaluated the excess equipment and since the acquisition has sold currently plans on selling certain excess land and equipment not needed for current or planned future operations.

The cash portion of the asset acquisition totaling approximately $13.9 million was paid from existing working capital held by NCE.

As part of the acquisition the Company entered into certain non interest bearing long term obligations which will paid out over the next 16 years. The Company has evaluated the above notes and after factoring in certain offsets provided for in the agreement has valued the above obligations at $1,198,000 at December 31, 2009.

As of December 31, 2009, the Company leased one independent living community in Oregon, with a capacity of 114 residents.

A number of years ago the Company has owned, leased and operated assisted living and retirement communities throughout the United States. During that period of time the Company has both acquired and sold over seventy communities. The property in Oregon is a holdover from that time period. While not an integral part of our business plan the one remaining facility is profitable and it is anticipated that it will remain a part of the Company’s operations.

In 2007, the Company acquired interests in a significant block of oil and natural gas leases in Cleburne County, Arkansas covering approximately 1,712 net acres. The company originally intended to drill on the acreage however an opportunity arose to sell the acreage and in 2008 we sold those mineral rights for a gain of approximately $16.4 million.

Critical Accounting Policies and Estimates

The Company’s discussion and analysis of its financial condition and results of operations are based upon the Company’s consolidated financial statements, which have been prepared in

accordance with accounting principles generally accepted in the United States. Certain of the Company’s accounting policies require the application of judgment in selecting the appropriate assumptions for calculating financial estimates. By their nature, these judgments are subject to an inherent degree of uncertainty. These judgments and estimates are based upon the Company’s historical experience, current trends and information available from other sources that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

The Company believes the following critical accounting policies are more significant to the judgments and estimates used in the preparation of its consolidated financial statements. Revisions in such estimates are recorded in the period in which the facts that give rise to the revisions become known.

Oil and Gas Property Accounting

The Company assesses all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

At December 31, 2009, the Company’s net book value of oil and natural gas properties exceeded the ceiling amount based on the unweighted arithmetic average of the first day of each month for the 12-month period ended December 31, 2009. As a result, the Company recorded a full cost ceiling adjustment before income taxes of approximately $1.7 million.

Oil and Gas Reserves

Our proved oil and gas reserves are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof, including evaluations and extrapolations of well flow rates and reservoir pressure. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because proved reserves are required to be estimated using prices at the date of the evaluation, estimated reserve quantities can be significantly impacted by changes in product prices.

Depreciation, depletion and amortization (“DD&A”) of producing properties is computed on the unit-of-production method based on estimated proved oil and gas reserves. While total DD&A expense for the life of a property is limited to the property’s total cost, proved reserve revisions result in a change in timing of when DD&A expense is recognized. Downward revisions of proved reserves result in an acceleration of DD&A expense, while upward revisions tend to lower the rate of DD&A expense recognition.

The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include using year-end oil and gas prices and year-end costs for estimated future development and production expenditures. Discounted future net cash flows are calculated using a 10% rate. Changes in any of these assumptions could have a significant impact on the standardized measure. Accordingly, the standardized measure does not represent management’s estimated current market value of proved reserves.

The Company’s allowance for doubtful accounts receivable and notes receivable is based on an analysis of the risk of loss on specific accounts. The analysis places particular emphasis on past due accounts. Management considers such information as the nature and age of the receivable, the payment history of the tenant, customer or other debtor and the financial condition of the tenant or other debtor. Management’s estimate of the required allowance, which is reviewed on a quarterly basis, is subject to revision as these factors change.

Deferred Tax Assets

Significant management judgment is required in determining the provision for income taxes, deferred tax assets and liabilities and any valuation allowance recorded against net deferred tax assets. The future recoverability of the Company’s net deferred tax assets is dependent upon the generation of future taxable income prior to the expiration of the loss carry forwards. At December 31, 2009, the Company had a deferred tax asset due to tax deductions available to it in future years. However, as management could not determine that it was more likely than not that the benefit of the deferred tax asset would be realized, a 100% valuation allowance was established.

Liquidity and Capital Resources

At December 31, 2009, the Company had current assets of $12.1 million and current liabilities of $2.9 million.

Cash and cash equivalents totaled $155,000 at December 31, 2009 and $190,000 at December 31, 2008. New Concept’s principal sources of cash are property operations, sales of oil and gas, and proceeds from sales of assets. At December 31, 2009 the Company had $11.2 million invested in short term notes receivable with interest at the prime rate plus two percent.

Net cash provided by (used in) continuing operating activities was $736,000 in 2009, $427,000 in 2008, and $749,000 in 2007.

Net cash provided by (used in) investing activities was $(823,000) in 2009, $2.6 million in 2008, $(679,000) in 2007.

Net cash provided by (used in) financing activities was $52,000 in 2009, $(3.0 million) in 2008, and $-0- in 2007. The $3.0 million used in 2008 was the result of the payment of related party debt of $6.9 million, partially offset by receipt of $2.9 million for the issuance of 950,000 shares of common stock.

There were no discontinued operations in 2009 or 2008. Net cash provided (used in) discontinued operations was ($222,000) in 2007.

Results of Operations

Fiscal 2009 as compared to 2008

Revenues and Operating Expenses: Total revenues for 2009 totaled $4.1 million compared to $3.6 million in 2008. The primary reason for the increase is the acquisition of the oil and gas operations in September 2008. Fiscal 2009 reflects a full twelve months of operating revenue for the oil and gas operations, while 2008 reflects only four months of such revenue. Oil and gas revenue did not increase as much as may have been anticipated due to the expiration of a fixed-price contract in the first quarter of 2009. For the remainder of the year, gas was sold at the spot price, which was substantially less than the original contract price.

Revenue for the retirement facility totaled approximately $2.9 million for 2008 and 2009.

Operating expenses totaled $6.8 million for 2009 compared to $3.7 million for 2008. In 2009, oil and gas operating costs totaled $1.5 million compared to $496,000 in 2008 due to the acquisition of the oil and gas operations described above. In 2009, the company recorded a non-cash charge to operations of $1.7 million for impairment of natural gas and oil properties, pursuant to the results of the full-cost ceiling test. Also in 2009, the Company recorded accretion of discount related to its asset retirement obligation of $116,000. Real estate operating expenses remained relatively constant. Corporate general and administrative expenses increased from $852,000 to $1.2 million, due primarily to the write-down of receivables of approximately $200,000 and the accrual of $200,000 in interest and penalties on unpaid taxes, offset by reductions in salaries and wages of approximately $50,000.

Interest Income: Interest income decreased approximately $200,000 from 2008 to 2009 due to the reduction interest rate on portions of the notes receivable from eight percent to the prime rate plus two percent during 2009.

Interest Expense: Interest expense for 2009 decreased approximately $150,000 due to the pay-off of $6.9 million of related party debt in the first quarter of 2008.

Gain on sale of assets: In 2008, the Company sold its investment in mineral rights in the Fayetteville Shale for a gain of approximately $16.4 million. No gain or loss was recorded on sales of assets in 2009.

Other Income: Other income decreased from $464,000 in 2008 to $68,000 in 2009. Other income in 2008 is primarily due to cash received from receivables that were previously fully reserved.

Fiscal 2008 as Compared to 2007

Revenues and Operating Expenses: Revenues for 2008 totaled $3.6 million compared to $3.0 million in 2007. The primary reason for the increase is the acquisition of the oil and gas operations in West Virginia and Ohio in September, 2008, which provided $672,000 of net revenue. Revenue for the retirement facility totaled approximately $2.9 million in 2008 as

compared to $3.0 million for 2007. Operating expenses totaled $3.7 million for 2008 compared to $3.0 million for 2007. In 2008, oil and gas operating costs totaled $496,000, and corporate general and administrative expenses increased approximately $60,000, primarily due to the administrative costs of the acquisition.

Interest Income: Interest income increased approximately $670,000 from 2007 to 2008 due to the increase in the interest-bearing loans to affiliates during 2008.

Interest Expense: Interest expense for 2008 increased approximately $197,000 due primarily to the amount of time debt was owed. Interest on the note payable to affiliate in 2007 reflects less than two months of accrued interest, while 2008 interest is for more than four months.

Gain on sale of assets: In 2008, the Company sold its investment in mineral rights in the Fayetteville Shale for a gain of approximately $16.4 million. In 2007, the Company sold a participation in the future cash flow of its retirement community in King City, Oregon and recorded a gain of $750,000.

Other Income: Other income increased from $143,000 in 2007 to $464,000 in 2008. The increase in 2008 is primarily due to cash received from receivables that were previously fully reserved.

NOTE A — BUSINESS DESCRIPTION AND PRESENTATION

Acquisition Of Carl E. Smith Companies

Effective September 1, 2008, the Company completed the acquisition of certain entities, mineral interests and related assets through entities named Carl E. Smith, Inc., a West Virginia corporation, two of its affiliates, Carl E. Smith Petroleum, Inc. and Carl E. Smith Real Estate, Inc. and other privately owned related assets (collectively “CESI”). Immediately after the acquisition, all of the acquired entities and assets were merged into Carl E. Smith, Inc., the name of which was changed to Mountaineer State Energy, Inc. (“Mountaineer”) which became a wholly-owned subsidiary of NCE. The assets acquired include 94 producing gas wells, 121 non-producing wells and related equipment, mineral leases covering 20,000 acres located in Athens and Meigs Counties in Ohio as well as Calhoun, Jackson and Roane Counties in West Virginia. In addition to the wells and mineral leases, the acquisition included a complex covering approximately 41 acres of land with 8,000 square feet of office and storage buildings, an adjacent 12 acres site with a 24 stall horse barn, machinery and equipment in excess of the needs of the gas operation and approximately $1.5 million in cash.

The entities involved were the subject of bankruptcy proceedings in the Southern District of West Virginia originally filed in 2003 styled In Re Carl E. Smith, Inc., Case No. 03-22274 (Chapter 11) pending in the United Stated Bankruptcy Court for the Southern District of West Virginia, which was substantively consolidated with Carl E. Smith Real Estate, Inc., Case No. 03-22298 and Carl E. Smith Petroleum, Inc., Case No. 08-20022 (the “Bankruptcy Proceedings”). Pursuant to the Bankruptcy Proceedings, a subsidiary of NCE acquired a claim of an independent third party, and engaged in a bidding contest which resulted in the Court awarding NCE the bid on August 6, 2008, which was confirmed August 16, 2008, but various documents and instruments confirming the matter were not completed until September 19, 2008. Pursuant to the confirmed Plan of Reorganization, NCE paid all existing debt to third parties of approximately $5 million, paid cash of $7.3 million dollars to certain shareholders and paid or will pay approximately $1.6 million dollars in fees and bankruptcy related costs.

In addition, the Company entered into several agreements in which the Company agreed to payout two former shareholders and a family member.

The agreements all provide that bankruptcy administrative costs incurred over $500,000 would be reimbursed to NCE prior to any payments being made on the notes. The administrative costs incurred over $500,000 were approximately $1.1 million. The agreements further provide that NCE can reduce the note payments for any amounts that might be recovered by the IRS should they choose to audit CESI for period prior to the acquisition.

In the first two similar agreements two shareholders are to receive a total of $1,760,000 less administrative costs noted above. The Company is to make payments to each former shareholder in the amount of $1,000 a week for the next 17 years. The allocation of the administrative costs to each specific agreement is dependent on future events however the Company does not anticipate making any cash payments for five years.

The second agreement was in the amount of $600,000 and requires the Company should make payments equal to 100% of the available cash flow from the acquired entities. The entire obligation is required to be paid within five years. Available cash flow is to be determined by NCE based upon Mountaineer State Energy’s actual as well as projected cash needs. NCE anticipates that almost all of this obligation will be used to repay a portion of the reimbursable administrative costs.

The third agreement was in the amount of $1,000,000 and state the Company should make payments in the amount of 75% of available funds from the operation of the business under terms similar to the note above. However, the payments do not begin until the second agreement is fully funded. The agreement further provides that it be paid within seven years.

The Company has evaluated the above notes and after factoring the administrative cost reimbursement, imputing a 10% interest rate, and accreting interest since acquisition, has valued the above obligations at $1,198,000 at December 31, 2009.

In 2002, the Internal Revenue Service (“IRS”) commenced an audit of the CESI and its related companies. This audit was halted in its early stages during which time the Justice Department began a review and subsequent prosecution of certain individual owners and related individuals of CESI. It is unknown as to whether, at this point, the IRS will choose to renew its audit of the Company for any years prior to our acquisition of CESI. The bankruptcy plan provides that the IRS has two years from the approval of the plan of reorganization to complete an audit should it choose to do so. The bankruptcy code provides certain limitations as to how far back the IRS can go in determining any claims against CESI. We believe that should the IRS complete an audit for the years legally available for a claim the IRS would find no material adjustments. Further, should the IRS be successful in any claims against CESI, any payments made by the Company would reduce future payments due the previous owners, per the terms of the acquisition.

Certain individuals have filed administrative claims in the bankruptcy court totaling approximately $400,000. Should any of these claims be successful, any obligation paid by the Company would reduce future payments due the previous owners, per the terms of the acquisition.

The purchase price of $13,850,000 was paid in cash as follows.

The computation of the purchase price is:


Cash paid to all sellers	$	7,300
Cash paid to creditors		5,000
Cash paid in fees and bankruptcy related costs		1,550

Total cash cost	$	13,850

The details of the purchase price allocation are as follows:

NOTE B — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows:

Principles of Consolidation

The consolidated financial statements include the accounts of New Concept Energy, Inc. and its majority-owned subsidiaries (collectively, the “Company”, New Concept or “NCE”) and are prepared on the basis of accounting principles generally accepted in the United States of America. All significant intercompany transactions and accounts have been eliminated.

Depreciation and Amortization

Depreciation is provided for in amounts sufficient to relate the cost of property and equipment to operations over their estimated service lives, ranging from 3 to 40 years. Depreciation is computed by the straight-line method. Depreciation and amortization expense, included in operations expenses, was $83,000, $60,000, and $48,000 for 2009, 2008, and 2007 respectively.

Depletion of Mineral Rights

The Company recorded depletion of mineral rights of $298,000 in 2009 and $112,000 in 2008. No such costs were incurred in 2007.

Segments

The company operates two primary business segments; oil and gas operations and retirement facilities. Segment data is provided in “Note N” to these consolidated financial statements.

Major Purchaser

The Company has one primary purchaser of its oil natural gas, which in 2009 comprised 89 percent of total sales. While there is an available market for crude oil and natural gas production, we cannot be assured that the loss of this purchaser would not have a material impact on the Company.

Oil and Gas Reserves

evaluation, estimated reserve quantities can be significantly impacted by changes in product prices.

The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include using recent oil and gas prices and year-end costs for estimated future development and production expenditures. Discounted future net cash flows are calculated using a 10% rate. Changes in any of these assumptions could have a significant impact on the standardized measure. Accordingly, the standardized measure does not represent management’s estimated current market value of proved reserves.

Full cost ceiling test

As of December 31, 2009, the ceiling test computation resulted in the carrying costs of our unamortized proved oil and natural gas properties, net of deferred taxes, exceeding the December

31, 2009 present value of future net revenues by approximately $1.7 million. Accordingly, a non-cash charge of $1.7 million was recognized for the year ended December 31, 2009.

Gas gathering assets

Gas gathering assets are capitalized as part of the depletable pool and ratably charged to earnings along with other capitalized exploration, drilling and development costs.

Office and field equipment

Office and field equipment are capitalized at cost and depreciated on a straight line basis over their estimated useful lives. Office and field equipment useful lives range from 5 to 30 years.

Revenue recognition and gas imbalances

We use the sales method of accounting for oil and natural gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. Gas imbalances at December 31, 2009 were not significant. New Concept also follows the sales method of accounting for natural gas production imbalances and would recognize a liability if the existing proved reserves were not adequate to cover an imbalance.

Accounting for Leases

Leases of property, plant and equipment where the Company assumes substantially all the benefits and risks of ownership are classified as finance leases. Finance leases are capitalized at the estimated present value of the underlying lease payments. Each lease payment is allocated between the liability and finance charges so as to achieve a constant rate on the finance balance outstanding. The corresponding rental obligations, net of finance charges, are included in other long-term payables. The interest element of the finance charge is charged to the income statement over the lease period. Property, plant and equipment acquired under finance leasing contracts are depreciated over the useful life of the asset.

Leases of assets under which all the risks and benefits of ownership are effectively retained by the lessor are classified as operating leases. Payments made under operating leases are charged to the income statement on a straight-line basis over the period of the lease. When an operating lease is terminated before the lease period has expired, any payment required to be made to the lessor by way of penalty is recognized as an expense in the period in which termination takes place.

Revenue Recognition

Rental income for residential property leases is recorded when due from residents and is recognized monthly as it is earned, which is not materially different than on a straight-line basis as lease terms are generally for periods of one year or less.

Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. Costs associated with revenues are recorded in cost of revenues. Production volumes of natural gas are sold immediately and transported via pipeline. Royalties on the production of natural gas either paid in cash or settled through the delivery of volumes. New Concept includes royalties in its revenues and cost of revenues when settlement of the royalties is paid in cash, while royalties settled by the delivery of volumes are excluded from revenues and cost of revenues.

New Concept follows the sales method of accounting for natural gas production imbalances and would recognize a liability if the existing proved reserves were not adequate to cover an imbalance.

Use of Estimates

In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash Equivalents

The Company considers all short-term deposits and money market investments with a maturity of less than three months to be cash equivalents.

Other Intangible Assets

The cost of acquired patents, trademarks and licenses is capitalized and amortized using the straight-line method over their useful lives. The carrying amount of each intangible asset is reviewed annually and adjusted for permanent impairment where it is considered necessary.

Impairment of Notes Receivable

Notes receivable are identified as impaired when it is probable that interest and principal will not be collected according to the contractual terms of the note agreements. The accrual of interest is discontinued on such notes, and no income is recognized until all past due amounts of principal and interest are recovered in full.

Impairment of Long-Lived Assets

The Company reviews its long-lived assets and certain identifiable intangibles for impairment when events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. In reviewing recoverability, the Company estimates the future cash flows expected to result from use of the assets and eventually disposing of them. If the sum of the expected future cash flows (undiscounted and without interest charges) is less than the carrying amount of the asset, an impairment loss is recognized based on the asset’s fair value.

The Company determines the fair value of assets to be disposed of and records the asset at the lower of fair value less disposal costs or carrying value. Assets are not depreciated while held for disposal.

Stock Options

The Company follows Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment” (“SFAS 123R”) for its stock options. The effect of SFAS 123R is immaterial to the Company’s financial statements.

Sales of Real Estate

Gains on sales of real estate are recognized to the extent permitted by Statement of Financial Accounting Standards No. 66, “Accounting for Sales of Real Estate” (“SFAS No. 66”). Until the requirements of SFAS No. 66 have been met for full profit recognition, sales are accounted for by the installment or cost recovery method, whichever is appropriate.

Real Estate Held for Sale

Statement of Financial Accounting Standards No. 144 (“SFAS No. 144”) requires that properties held for sale be reported at the lower of carrying amount or fair value less costs of sale. If a reduction in a held for sale property’s carrying amount to fair value less costs of sale is required, a provision for loss is recognized by a charge against earnings. Subsequent revisions, either upward or downward, to a held for sale property’s estimated fair value less costs of sale are recorded as an adjustment to the property’s carrying amount, but not in excess of the property’s carrying amount when originally classified as held for sale. A corresponding charge against or credit to earnings is recognized. Properties held for sale are not depreciated.

Asset Retirement Obligation

The Company records an asset retirement obligation liability on the consolidated balance sheets and capitalizes a portion of the cost in “Oil and natural gas properties” during the period in which the obligation is incurred. The asset retirement obligation is further described in Note Q.

Recent Accounting Pronouncements

FASB Accounting Standards Codification. The company presents its financial statements in accordance with generally accepted accounting principles in the United States (“GAAP”). In June 2009, the Financial Accounting Standards Board (“FASB”) completed its accounting guidance codification project. The FASB Accounting Standards Codification (“ASC”) became effective for the Company’s financial statements issued subsequent to June 30, 2009 and is the single source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with GAAP.

In August 2009, the FASB issued Accounting Standards Update (ASU) No. 2009-05, Fair Value Measurements and Disclosures (ASU 2009-05). ASU 2009-05 amends Subtopic 820-10, Fair Value Measurements and Disclosures, to provide guidance on the fair value measurement of liabilities. ASU 2009-05 provides clarification for circumstances in which a quoted price in an active market for the identical liability is not available. ASU 2009-05 is effective for interim and annual periods beginning after August 26, 2009. The Company adopted the provisions of ASU 2009-05 for the period ended December 31, 2009. There was no impact on the Company’s operating results, financial position or cash flows.

In June 2009, the FASB issued ASU No. 2009-01, Generally Accepted Accounting Principles (ASU 2009-01). ASU 2009-01 establishes “The FASB Accounting Standards Codification,” or Codification, which became the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. On the effective date, the Codification superseded all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification will become non-authoritative. ASU 2009-01 is effective for interim and annual periods ending after September 15, 2009. The Company adopted the provisions of ASU 2009-01 for the period ended September 30, 2009. There was no impact on the Company’s operating results, financial position or cash flows.

In May 2009, the FASB issued SFAS No. 165, Subsequent Events (ASC 855) to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. ASC 855 is effective for interim and annual reporting periods ending after June 15, 2009. The Company adopted the provisions of ASC 855 for the period ended June 30, 2009. There was no impact on the Company’s operating results, financial position or cash flows.

In April 2009, the FASB issued FASB Staff Position (FSP) No. FAS 107-1 and Accounting Principles Board (APB) 28-1, Interim Disclosures about Fair Value of Financial Instruments (ASC 825-10-65) to change the reporting requirements on certain fair value disclosures of financial instruments to include interim reporting periods. The Company adopted ASC 825-10-65 in the second quarter of 2009. There was no impact on the Company’s operating results, financial position or cash flows; however additional disclosures were added to the accompanying notes to the consolidated financial statements for the Company’s fair value of financial instruments.

In April 2009, the FASB issued FSP No. FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments, (ASC 320-10-65), to expand other-than-temporary impairment guidance for debt securities to enhance the application of the guidance and improve the presentation and disclosure of other-than temporary impairments on debt and equity securities within the financial statements. The adoption of ASC 320-10-65 in the second quarter of 2009 did not have a significant impact on the Company’s operating results, financial position or cash flows.

In April 2009, the FASB issued FSP No. FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, (ASC 820-10-65) to provide additional guidance for

estimating fair value when the volume and level of activity for an asset or liability has significantly decreased. In addition, ASC 820-10-65 includes guidance on identifying circumstances that indicate a transaction is not orderly. The adoption of ASC 820-10-65 in the second quarter of 2009 did not have a significant impact on the Company’s operating results, financial position or cash flows.

In December 2008, the SEC issued Release No. 33-8995, Modernization of Oil and Gas Reporting (ASC 2010-3), which amends the oil and gas disclosures for oil and gas producers contained in Regulations S-K and S-X, as well as adding a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being eliminated. The goal of Release No. 33-8995 is to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. Energy companies affected by Release No. 33-8995 are now required to price proved oil and gas reserves using the unweighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. SEC Release No. 33-8995 is effective beginning for financial statements for fiscal years ending on or after December 31, 2009. The impact on the Company’s operating results, financial position and cash flows has been recorded in the financial statements; additional disclosures were added to the accompanying notes to the consolidated financial statements for the Company’s supplemental oil and gas disclosure. See Note P — Supplementary Financial Information on Oil and Natural Gas Exploration, Development and Production Activities for more details.

In January 2010, the FASB issued FASB Accounting Standards Update (ASU) No. 2010-03 Oil and Gas Estimations and Disclosures (ASU 2010-03). This update aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Industries Oil and Gas topic of the FASB Accounting Standards Codification (ASC Topic 932) with the changes required by the SEC final rule ASC 2010-3, as discussed above, ASU 2010-03 expands the disclosures required for equity method investments, revises the definition of oil- and natural gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas, amends the definition of proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic area with respect to disclosure of information about significant reserves. ASU 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. The Company adopted ASU 2010-03 effective December 31, 2009. See Note P — Supplementary Financial Information on Oil and Natural Gas Exploration, Development and Production Activities for more details.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133 (ASC 815-10-65). ASC 815-10-65 requires entities that utilize derivative contracts to provide qualitative disclosures about their objectives and strategies for using such instruments, as well as any details of credit-risk-related contingent features contained within derivatives. ASC 815-10-65 also requires entities to

disclose additional information about the amounts and location of derivatives located within the financial statements, how the provisions of ASC 815 have been applied, and the impact that hedges have on an entity’s operating results, financial position or cash flows. The Company adopted ASC 815-10-65 on January 1, 2009. There was no impact on the Company’s operating results, financial position or cash flows.

In December 2007, the FASB issued SFAS No. 141 (Revised 2007), Business Combinations (ASC 805), and SFAS No. 160, Accounting and Reporting of Noncontrolling Interest in Consolidated Financial Statements, an amendment of ARB No. 51 (ASC 810-10-65). ASC 805 and ASC 810-10-65 significantly change the accounting for and reporting of business combination transactions and noncontrolling (minority) interests within the financial statements. ASC 805 provides additional definitions, such as the definition of the acquirer in a purchase and improvements in the application of how the acquisition method is applied. ASC 810-65 changes the accounting and reporting for minority interests, which are re-characterized as non-controlling interests, and classified as a component of equity. The Company adopted ASC 805 and ASC 810-10-65 on January 1, 2009. There was no impact on the Company’s operating results, financial position or cash flows; however if the Company enters into future business combinations, certain transaction related expenses may be recorded within the Company’s operating results which could reduce its current period net income or increase its net loss. Additionally, valuation of certain assets may be different than under the old accounting standards.

Effective January 1, 2009, the Company adopted FSP No. FAS 157-2, Effective Date of FASB Statement No. 157 (ASC 820-10-55). ASC 820-10-55 delayed the effective date of ASC 820 for all non-financial assets and non-financial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until the beginning of the first quarter of fiscal 2009. These include goodwill and other non-amortizable intangible assets. The adoption of ASC 820-10-55 did not have a significant impact on the Company’s operating results, financial position or cash flows. See Note Q “Asset Retirement Obligation” for more details.

In June 2008, the FASB issued Emerging Issues Task Force (EITF) 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (ASC 260). ASC 260 clarifies that share-based payment awards that entitle their holders to receive non-forfeitable dividends or dividend equivalents before vesting should be considered participating securities. The adoption of ASC 260 on January 1, 2009 did not have a significant impact on the Company’s operating results, financial position or cash flows.

NOTE P — SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

The Company’s net ownership interests in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves, all of which are located in the continental United States, are summarized below:


	2009
	Gas			Oil
	(MMCF)			(MBBLS)
Proved developed and undeveloped reserves —
January 1, 2009		5,997			37
Purchase of oil and natural gas properties in place		—			—
Discoveries and extensions		—			—
Revisions		1,800			(14	)
Sales of oil and gas properties in place					—
Production		(236	)		(4	)

End of year		7,561			19

Proved developed reserves at beginning of year		2,703			37

Proved developed reserves at end of year		2,867			19


	2008
	Gas			Oil
	(MMCF)			(MBBLS)
Proved developed and undeveloped reserves —
September 15, 2008 (pre-acquisition)		—			—
Purchase of oil and natural gas properties in place		6,080			44
Discoveries and extensions		—			—
Revisions		—			—
Sales of oil and gas properties in place		—			—
Production		(83	)		(7	)

End of year		5,997			37

Proved developed reserves at acquisition		2,786			44

Proved developed reserves at end of year		2,703			37

-1-

The following table presents the changes in our total proved undeveloped reserves.


	Gas		Oil
	(MMCF)		(MBBLS)
Proved undeveloped reserves as of December 31, 2007		—		—
Purchase of reserves		4,694		—
Conversion to proved developed reserves		—		—


Proved undeveloped reserves as of December 31, 2008		4,694		—
Conversion to proved developed reserves		—		—


Proved undeveloped reserves as of December 31, 2009		4,694		—

The following table reflects the capitalized costs relating to oil and gas producing activities.


	2009			2008

Property acquisition costs:
Proved properties (2009 reflects an adjustment to the 2008 acquisition costs)	$	(343	)	$	13,134
Unproved properties		—			—
Accumulated depreciation, depletion and amortization and valuation allowance		(1,993	)		(112	)


Net capitalized costs	$	(2,336	)	$	13,022

The following table reflects the costs incurred in oil and gas property acquisition, exploration and development activities.


	2009		2008
Property acquisition costs:
Proved properties	$	—	$	13,134
Unproved properties		—		—
Exploration costs		—		—
Development costs		—		—


Total cost incurred	$	—	$	13,134

The following table reflects revenues and expenses directly associated with our oil and gas producing activities, including general and administrative expenses directly related to such producing activities. They do not include any allocation of interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net earnings of our oil and gas operations. Income tax expense has been calculated by applying statutory income

tax rates to oil and gas sales after deducting costs, including depreciation, depletion and amortization and after giving effect to permanent differences.


	2009			2008
Oil and gas sales	$	1,241		$	672
Production expenses		(1,190	)		(370	)
Exploration expenses		—			—
Taxes other than income taxes		(10	)		(10	)
Depreciation, depletion and amortization		(442	)		(116	)
Impairment of oil and gas properties		(1,695	)		—
General and administrative expenses		(140	)		(40	)
Income tax benefit (expense)		—			—


Results of operations	$	(2,236	)	$	136

The following table reflects the standardized measure of future net cash flows related to our proved reserves.


	2009			2008
Future oil and gas cash inflows	$	49,250		$	66,539
Future oil and gas operating expenses		(9,318	)		(14,599	)
Future development costs		(13,589	)		(15,368	)
Future income tax expense		(184	)		(419	)

Future net cash flows		26,159			36,153
10% discount to reflect timing of cash flows		(14,372	)		(18,705	)


Standardized measure of discounted future net cash flows	$	11,372		$	17,808

The following table reflects the principal changes in the standardized measure of discounted future net cash flows attributable to our proved reserves.


	2009			2008
Beginning balance	$	17,808		$	—
Oil and gas sales, net of production costs		(51	)		—
Purchase of reserves, net of future development costs		—			17,808
Net changes in prices and production costs		(6,385	)		—
Extensions and discoveries, net of future development costs		—			—
Revisions of quantity estimates		—			—
Other changes		—			—


Ending balance	$	11,372		$	17,808

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

March 23, 2010

New Concept Energy, Inc.
1755 Wittington Place, Suite 340
Dallas, Texas 75234

Attn:

Mr. Gene Bertcher
Chief Executive Officer

Re:

Estimated Reserves and Future Net Revenue Proved Producing and Undeveloped 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, non-producing, and undeveloped 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, 2009, and the results are summarized as follows:


	ESTIMATED REMAINING
	NET RESERVES				FUTURE NET REVENUE
							Present Worth
	Oil		Gas		TOTAL		Disc.@ 10%
RESERVE CLASSIFICATION	(BBLS)		(MCF)		($)		($)

Proved Developed
Producing		19,291		2,466,819		9,068,912		4,473,309
Non-Producing		—		400,194		1,568,819		247,666

Sub-Total		19,291		2,867,013		10,637,731		4,720,975

Proved Undeveloped
Primary		—		4,694,375		15,521,462		6,650,898


Total All Reserves		19,291		7,561,388		26,159,193		11,371,873

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.

WWW.LKAENGINEERS.COM

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 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 215 gas wells of which 122 were selling gas on the effective date. 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.

CLASSIFICATION OF RESERVES

Reserves assigned to the various wells have been classified as “proved developed” and “proved undeveloped” in accordance with the definitions of the proved reserves as promulgated by the Securities and Exchange Commission (SEC). These are as follows:

Proved Developed Oil and Gas Reserves are reserves that can be recovered with reasonable certainty through existing wells with existing equipment and operating methods. Additional oil and gas to be recovered through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved Undeveloped Oil and Gas Reserves are reserves to be recovered with reasonable certainty from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved 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 tests in the area and in the same reservoir.

Proved Developed Oil and Gas Reserves attributed to the subject leases have been further classified as “proved developed producing,” and “proved developed non-producing.”

Proved Developed Producing Reserves are those reserves to be recovered with reasonable certainty from currently producing zones under continuation of present operating methods.

Proved Developed Non-Producing Reserves are those reserves to be recovered with reasonable certainty from zones that have been completed and tested but are not yet producing due to situations including, but not limited to, lack of market, minor completion problems that are expected to be corrected, or reserves to be recovered from future stimulation treatments with reasonable certainty based on analogy to nearby wells.

ESTIMATION OF RESERVES

All of Mountaineer’s active 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 anticipated from workovers and/or undeveloped 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 gas reserves was based on the average of prices received on the first day of each month in 2009 as provided by the staff of Mountaineer. Gas was being sold in both Ohio and West Virginia under two contracts, and the weighted average prices in each state were used, $6.319 per MCF in Ohio and $6.547 per MCF for gas sold in West Virginia. These prices were held constant, but provisions were made for state severance and ad valorem taxes.

Income from oil sales was also based on the average of prices received the first day of each month in 2009. This price supplied by Mountaineer was $55.97 per barrel and held constant with provisions for state severance and ad valorem taxes.

Projected produced gas volumes from West Virginia wells were reduced to sales volumes based on actual shrinkage data as provided by Mountaineer.

Operating Expenses

Anticipated monthly expenses were based on actual expenses incurred in 2009 as 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 workovers, drilling, and completion of wells drilled to capture the proved undeveloped 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.

You should be aware that state regulatory authorities could, in the future, change the allocation of reserves allowed to be produced from a particular well in any reservoir, thereby altering the material premise upon which our reserve estimate may be based.

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.


ESTIMATED RESERVES AND FUTURE NE	DATE	:	03/23/2010
MOUNTAINEER STATE ENERGY INC.	TIME	:	15:47:29
OIL AND GAS PROPERTIES	DBS	:	Mountain Energy
IN OHIO AND WEST VIRGINIA	SETTINGS	:	SETDATA
ALL RESERVES	SCENARIO	:	CESMITH09-SEC

RESERVES AND ECONOMICS

AS OF DATE : 12/31/2009

GROSS OIL

GROSS GAS

NET OIL

NET GAS

NET OIL

NET GAS

NET

TOTAL

END

PRODUCTION

PRICE

OIL SALES

GAS SALES

NET SALES

MO-YEAR

MBBLS

MMCF

MBBLS

MMCF

$/BBL

$/MCF

12-2010

3.652

376.004

3.195

318.690

55.970

6.437

178.850

2051.454

2230.304

12-2011

3.322

631.303

2.907

543.759

55.970

6.437

162.691

3500.010

3662.700

12-2012

2.131

839.098

1.865

727.325

55.970

6.427

104.370

4674.592

4778.962

12-2013

0.766

964.523

0.670

838.655

55.970

6.422

37.505

5386.004

5423.510

12-2014

0.725

923.013

0.634

803.184

55.970

6.401

35.488

5141.124

5176.612

12-2015

0.669

684.671

0.585

596.425

55.970

6.376

32.765

3802.701

3835.466

12-2016

0.615

481.153

0.538

420.086

55.970

6.352

30.133

2668.205

2698.338

12-2017

0.591

374.508

0.517

326.808

55.970

6.329

28.927

2068.266

2097.194

12-2018

0.567

328.674

0.496

286.914

55.970

6.324

27.770

1814.366

1842.136

12-2019

0.544

301.152

0.476

262.691

55.970

6.324

26.660

1661.248

1687.907

12-2020

0.523

279.017

0.457

243.356

55.970

6.324

25.593

1539.016

1564.610

12-2021

0.502

260.633

0.439

227.301

55.970

6.324

24.569

1437.519

1462.088

12-2022

0.482

244.933

0.421

213.594

55.970

6.324

23.587

1350.855

1374.442

12-2023

0.462

225.980

0.405

197.615

55.970

6.320

22.643

1248.917

1271.560

12-2024

0.444

213.037

0.388

186.408

55.970

6.319

21.737

1177.910

1199.647

S TOT

15.994

7127.898

13.995

6192.812

55.970

6.382

783.289

39522.184

40305.480

AFTER

6.053

1564.088

5.296

1368.577

55.970

6.319

296.427

8648.038

8944.463

TOTAL

22.047

8691.986

19.291

7561.389

55.970

6.371

1079.716

48170.223

49249.945

AD VALOREM

PRODUCTION

DIRECT OPER

INTEREST

CAPITAL

EQUITY

FUTURE NET

CUMULATIVE

CUM. DISC.

END

TAX

EXPENSE

PAID

REPAYMENT

INVESTMENT

CASHFLOW

MO-YEAR

12-2010

0.000

33.877

499.728

0.000

1898.000

-201.301

-203.773

12-2011

0.000

29.462

518.878

0.000

3054.000

60.360

-140.941

-175.951

12-2012

0.000

22.736

491.218

0.000

3093.000

1172.008

1031.067

714.453

12-2013

0.000

15.716

434.304

0.000

2943.000

2030.490

3061.557

2143.618

12-2014

0.000

13.584

455.154

0.000

2601.000

2106.875

5168.432

3504.915

12-2015

0.000

9.261

411.834

0.000

3414.372

8582.803

5533.990

12-2016

0.000

5.058

337.266

0.000

2356.013

10938.816

6805.718

12-2017

0.000

4.850

334.266

0.000

1758.077

12696.893

7668.050

12-2018

0.000

4.651

333.516

0.000

1503.970

14200.863

8337.875

12-2019

0.000

4.460

333.516

0.000

1349.932

15550.795

8884.375

12-2020

0.000

4.276

333.516

0.000

1226.817

16777.611

9335.847

12-2021

0.000

4.101

333.516

0.000

1124.472

17902.084

9712.015

12-2022

0.000

3.932

333.516

0.000

1036.994

18939.078

10027.370

12-2023

0.000

2.451

308.036

0.000

961.074

19900.152

10293.057

12-2024

0.000

2.090

302.940

0.000

894.617

20794.770

10517.883

S TOT

0.000

160.504

5761.204

0.000

13589.000

20794.770

10517.883

AFTER

0.000

23.252

3556.790

0.000

5364.421

26159.191

11371.874

TOTAL

0.000

183.756

9317.994

0.000

13589.000

26159.191

11371.874


	OIL		GAS
GROSS WELLS		0.0		184.0
GROSS ULT., MB & MMF		43.062		18274.988
GROSS CUM., MB & MMF		21.015		9583.000
GROSS RES., MB & MMF		22.047		8691.988
NET RES., MB & MMF		19.291		7561.390
NET REVENUE, M$		1079.716		48170.234
INITIAL PRICE, $		55.970		6.407
INITIAL N.I., PCT.		87.500		87.500

P.W. %

P.W., M$

LIFE, YRS.

50.00

5.00

16559.016

DISCOUNT %

10.00

9.00

12199.376

UNDISCOUNTED PAYOUT, YRS.

2.12

15.00

8236.707

DISCOUNTED PAYOUT, YRS.

2.20

20.00

6193.833

UNDISCOUNTED NET/INVEST.

2.93

25.00

4787.898

DISCOUNTED NET/INVEST.

2.06

30.00

3779.367

RATE-OF-RETURN, PCT.

100.00

40.00

2464.050

INITIAL W.I., PCT.

100.000

60.00

1167.698

80.00

587.711

100.00

288.722

THIS SCHEDULE IS PART OF A REPORT AND SUBJECT TO QUALIFICATIONS OF THE REPORT.
LEE KEELING AND ASSOCIATES, INC.

Page No. 1


ESTIMATED RESERVES AND FUTURE NE	DATE	:	03/23/2010
MOUNTAINEER STATE ENERGY INC.	TIME	:	15:47:27
OIL AND GAS PROPERTIES	DBS	:	Mountain Energy
IN OHIO AND WEST VIRGINIA	SETTINGS	:	SETDATA
PROVED DEVELOPED PRODUCING RESERVES	SCENARIO	:	CESMITH09-SEC

RESERVES AND ECONOMICS

AS OF DATE : 12/31/2009

END

GROSS OIL

GROSS GAS

NET OIL

NET GAS

NET OIL

NET GAS

NET

TOTAL

MO-YEAR

PRODUCTION

PRICE

OIL SALES

GAS SALES

NET SALES

MBBLS

MMCF

MBBLS

MMCF

$/BBL

$/MCF

12-2010

3.652

229.829

3.195

190.787

55.970

6.406

178.850

1222.108

1400.958

12-2011

3.322

208.984

2.907

174.230

55.970

6.398

162.691

1114.788

1277.479

12-2012

2.131

187.778

1.865

157.420

55.970

6.389

104.370

1005.770

1110.140

12-2013

0.766

168.275

0.670

141.938

55.970

6.379

37.505

905.398

942.903

12-2014

0.725

155.678

0.634

131.767

55.970

6.373

35.488

839.765

875.254

12-2015

0.669

134.664

0.585

115.168

55.970

6.356

32.765

732.009

764.774

12-2016

0.615

114.284

0.538

99.076

55.970

6.334

30.133

627.533

657.666

12-2017

0.591

109.713

0.517

95.113

55.970

6.334

28.927

602.432

631.359

12-2018

0.567

105.325

0.496

91.308

55.970

6.334

27.770

578.335

606.105

12-2019

0.544

101.112

0.476

87.656

55.970

6.334

26.660

555.201

581.861

12-2020

0.523

97.067

0.457

84.150

55.970

6.334

25.593

532.993

558.586

12-2021

0.502

93.184

0.439

80.784

55.970

6.334

24.569

511.674

536.243

12-2022

0.482

89.457

0.421

77.552

55.970

6.334

23.587

491.207

514.793

12-2023

0.462

80.612

0.405

70.418

55.970

6.322

22.643

445.160

467.803

12-2024

0.444

76.356

0.388

66.811

55.970

6.319

21.737

422.181

443.918

S TOT

15.994

1952.318

13.995

1664.179

55.970

6.361

783.289

10586.555

11369.841

AFTER

6.053

917.304

5.296

802.640

55.970

6.319

296.427

5071.887

5368.313

TOTAL

22.047

2869.622

19.291

2466.819

55.970

6.348

1079.716

15658.442

16738.154

END

AD VALOREM

PRODUCTION

DIRECT OPER

INTEREST

CAPITAL

EQUITY

FUTURE NET

CUMULATIVE

CUM. DISC.

MO-YEAR

TAX

EXPENSE

PAID

REPAYMENT

INVESTMENT

CASHFLOW

12-2010

0.000

33.767

494.628

0.000

872.563

833.230

12-2011

0.000

29.044

494.628

0.000

753.806

1626.369

1487.616

12-2012

0.000

22.071

435.868

0.000

652.201

2278.570

2002.298

12-2013

0.000

15.046

353.604

0.000

574.253

2852.823

2414.215

12-2014

0.000

12.948

353.604

0.000

508.702

3361.525

2745.935

12-2015

0.000

8.656

302.484

0.000

453.634

3815.159

3014.802

12-2016

0.000

4.484

230.916

0.000

422.266

4237.424

3242.266

12-2017

0.000

4.305

230.916

0.000

396.139

4633.563

3436.260

12-2018

0.000

4.133

230.916

0.000

371.056

5004.620

3601.453

12-2019

0.000

3.967

230.916

0.000

346.978

5351.597

3741.885

12-2020

0.000

3.809

230.916

0.000

323.862

5675.459

3861.048

12-2021

0.000

3.656

230.916

0.000

301.671

5977.130

3961.956

12-2022

0.000

3.510

230.916

0.000

280.367

6257.498

4047.214

12-2023

0.000

2.050

205.436

0.000

260.318

6517.815

4119.178

12-2024

0.000

1.709

200.340

0.000

241.869

6759.684

4179.964

S TOT

0.000

153.155

4457.004

0.000

6759.684

4179.964

AFTER

0.000

20.596

3038.490

0.000

2309.228

9068.912

4473.309

TOTAL

0.000

173.751

7495.494

0.000

9068.912

4473.309


	OIL		GAS
GROSS WELLS		0.0		122.0
GROSS ULT. , MB & MMF		43.062		12452.621
GROSS CUM., MB & MMF		21.015		9583.000
GROSS RES., MB & MMF		22.047		2869.621
NET RES., MB & MMF		19.291		2466.819
NET REVENUE, M$		1079.716		15658.442
INITIAL PRICE, $		55.970		6.409
INITIAL N.I., PCT.		87.500		87.500

P.N. %

P.W. M$

LIFE, YRS.

50.00

5.00

5955.408

DISCOUNT %

10.00

9.00

4702.751

UNDISCOUNTED PAYOUT, YRS.

0.00

15.00

3618.992

DISCOUNTED PAYOUT, YRS.

0.00

20.00

3065.550

UNDISCOUNTED NET/INVEST.

0.00

25.00

2677.933

DISCOUNTED NET/INVEST.

0.00

30.00

2390.951

RATE-OF-RETURN, PCT.

100.00

40.00

1993.168

INITIAL W.I., PCT.

100.000

60.00

1540.203

80.00

1286.065

100.00

1121.709

THIS SCHEDULE IS PART OF A REPORT AND SUBJECT TO QUALIFICATIONS OF THE REPORT.
LEE KEELING AND ASSOCIATES, INC.

Page No. 2


ESTIMATED RESERVES AND FUTURE NE	DATE	:	03/23/2010
MOUNTAINEER STATE ENERGY INC.	TIME	:	15:47:28
OIL AND GAS PROPERTIES	DBS	:	Mountain Energy
IN OHIO AND WEST VIRGINIA	SETTINGS	:	SETDATA
PROVED DEVELOPED NON-PRODUCING RESERVES	SCENARIO	:	CESMITH09-SEC

RESERVES AND ECONOMICS

AS OF DATE : 12/31/2009

GROSS OIL.

GROSS GAS

NET OIL

NET GAS

NET OIL

NET GAS

NET

TOTAL

END

PRODUCTION

PRICE

OIL SALES

GAS SALES

NET SALES

MO-YEAR

MBBLS

MMCF

MBBLS

MMCF

$/BBL

$/MCF

12-2010

0.000

5.031

0.000

4.402

0.000

6.319

0.000

27.816

12-2011

0.000

19.105

0.000

16.717

0.000

6.319

0.000

105.637

12-2012

0.000

30.404

0.000

26.604

0.000

6.319

0.000

168.109

12-2013

0.000

30.611

0.000

26.784

0.000

6.319

0.000

169.250

12-2014

0.000

29.080

0.000

25.445

0.000

6.319

0.000

160.788

12-2015

0.000

27.626

0.000

24.173

0.000

6.319

0.000

152.748

12-2016

0.000

26.245

0.000

22.964

0.000

6.319

0.000

145.111

12-2017

0.000

24.933

0.000

21.816

0.000

6.319

0.000

137.855

12-2018

0.000

23.686

0.000

20.725

0.000

6.319

0.000

130.963

12-2019

0.000

22.502

0.000

19.689

0.000

6.319

0.000

124.414

12-2020

0.000

21.377

0.000

18.704

0.000

6.319

0.000

118.194

12-2021

0.000

20.308

0.000

17.769

0.000

6.319

0.000

112.284

12-2022

0.000

19.292

0.000

16.881

0.000

6.319

0.000

106.670

12-2023

0.000

18.328

0.000

16.037

0.000

6.319

0.000

101.336

12-2024

0.000

17.411

0.000

15.235

0.000

6.319

0.000

96.269

S TOT

0.000

335.938

0.000

293.946

0.000

6.319

0.000

1857.444

AFTER

0.000

121.426

0.000

106.248

0.000

6.319

0.000

671.380

TOTAL

0.000

457.364

0.000

400.194

0.000

6.319

0.000

2528.824

AD VALOREM

PRODUCTION

DIRECT OPER

INTEREST

CAPITAL

EQUITY

FUTURE NET

CUMULATIVE

CUM. DISC.

END
MO-Y BAR

TAX
M$

EXPENSE
M$

PAID
M$

REPAYMENT
M$

INVESTMENT
M$

CASHFLOW
M$

12-2010

0.000

0.110

0.000

400.000

-372.294

-353.387

12-2011

0.000

0.418

0.000

400.000

-294.781

-667.076

-608.088

12-2012

0.000

0.665

0.000

150.000

17.444

-649.631

-597.330

12-2013

0.000

0.670

0.000

168.581

-481.051

-476.473

12-2014

0.000

0.636

0.000

160.152

-320.899

-372.097

12-2015

0.000

0.604

0.000

152.144

-168.755

-281.953

12-2016

0.000

0.574

0.000

144.537

-24.219

-204.102

12-2017

0.000

0.545

0.000

137.310

113.091

-136.867

12-2018

0.000

0.518

0.000

130.444

243.536

-78.801

12-2019

0.000

0.492

0.000

123.922

367.458

-28.652

12-2020

0.000

0.468

0.000

117.726

485.184

14.658

12-2021

0.000

0.444

0.000

111.840

597.024

52.062

12-2022

0.000

0.422

0.000

106.248

703.271

84.365

12-2023

0.000

0.401

0.000

100.935

804.207

112.264

12-2024

0.000

0.381

0.000

95.889

900.095

136.358

S TOT

0.000

7.349

0.000

950.000

900.095

136.358

AFTER

0.000

2.656

0.000

668.724

1568.819

247.666

TOTAL

0.000

10.005

0.000

950.000

1568.819

247.666


	OIL		GAS
GROSS WELLS		0.0		19.0
GROSS ULT. , MB & MMF		0.000		457.364
GROSS CUM. , MB & MMF		0.000		0.000
GROSS RES., MB & MMF		0.000		457.364
NET RES. , MB & MMF		0.000		400.194
NET REVENUE, M$		0.000		2528.823
INITIAL PRICE, $		0.000		6.319
INITIAL N.I., PCT.		0.000		87.500

P.W. %

P.W., M$

LIFE, YRS.

23.92

5.00

686.431

DISCOUNT %

10.00

9.00

314.503

UNDISCOUNTED PAYOUT, YRS,

7.18

15.00

9.667

DISCOUNTED PAYOUT, YRS.

10.66

20.00

-128.528

UNDISCOUNTED NET/INVEST.

2.65

25.00

-212.901

DISCOUNTED NET/INVEST.

1.29

30.00

-266.205

RATE-OF-RSTURN, PCT.

15.35

40.00

-322.786

INITIAL W.I., PCT.

100.000

60.00

-353.244

80.00

-348.383

100.00

-334.353

THIS SCHEDULE IS PART OF A REPORT AND SUBJECT TO QUALIFICATIONS OF THE REPORT.
LEE KEELING AND ASSOCIATES, INC.

Page No. 3

ESTIMATED RESERVES AND FUTURE NE

DATE

03/23/2010

MOUNTAINEER STATE ENERGY INC.

TIME

15:47:29

OIL AND GAS PROPERTIES

DBS

Mountain Energy

IN OHIO AND WEST VIRGINIA

SETTINGS

SETDATA

PROVED UNDEVELOPED RESERVES

SCENARIO

CESMITH09-SEC

RESERVES AND ECONOMICS

AS OF DATE : 12/31/2009

END

GROSS OIL

GROSS GAS

NET OIL

NET GAS

NET OIL

NET GAS

NET

TOTAL

MO-YEAR

PRODUCTION

PRICE

OIL SALES

GAS SALES

NET SALES

MBBLS

MMCF

MBBLS

MMCF

$/MCF

12-2010

0.000

141.144

0.000

123.501

0.000

6.490

0.000

801.530

12-2011

0.000

403.213

0.000

352.812

0.000

6.461

0.000

2279.585

12-2012

0.000

620.916

0.000

543.301

0.000

6.443

0.000

3500.713

12-2013

0.000

765.638

0.000

669.933

0.000

6.436

0.000

4311.356

12-2014

0.000

738.254

0.000

645.972

0.000

6.410

0.000

4140.571

12-2015

0.000

522.381

0.000

457.084

0.000

6.384

0.000

2917.944

12-2016

0.000

340.624

0.000

298.046

0.000

6.360

0.000

1895.561

12-2017

0.000

239.862

0.000

209.879

0.000

6.327

0.000

1327.979

12-2018

0.000

199.863

0.000

174.880

0.000

6.319

0.000

1105.069

12-2019

0.000

177.538

0.000

155.346

0.000

6.319

0.000

981.632

12-2020

0.000

160.513

0.000

140.502

0.000

6.319

0.000

887.829

12-2021

0.000

147.141

0.000

128.748

0.000

6.319

0.000

813.561

12-2022

0.000

136.184

0.000

119.161

0.000

6.319

0.000

752.979

12-2023

0.000

127.040

0.000

111.160

0.000

6.319

0.000

702.421

12-2024

0.000

119.270

0.000

104.361

0.000

6.319

0.000

659.459

S TOT

0.000

4839.642

0.000

4234.687

0.000

6.394

0.000

27078.186

AFTER

0.000

525.358

0.000

459.688

0.000

6.319

0.000

2904.771

TOTAL

0.000

5365.000

0.000

4694.375

0.000

6.387

0.000

29982.955

END

AD VALOREM

PRODUCTION

DIRECT OPER

INTEREST

CAPITAL

EQUITY

FUTURE NET

CUMULATIVE

CUM. DISC.

MO-YEAR

TAX

EXPENSE

PAID

REPAYMENT

INVESTMENT

CASHFLOW

12-2010

0.000

5.100

0.000

1498.000

-701.570

-683.616

12-2011

0.000

24.250

0.000

2654.000

-398.665

-1100.235

-1055.479

12-2012

0.000

55.350

0.000

2943.000

502.363

-597.872

-690.514

12-2013

0.000

80.700

0.000

2943.000

1287.657

689.785

205.877

12-2014

0.000

101.550

0.000

2601.000

1438.021

2127.806

1131.077

12-2015

0.000

109.350

0.000

2808.594

4936.400

2801.141

12-2016

0.000

106.350

0.000

1789.211

6725.611

3767.554

12-2017

0.000

103.350

0.000

1224.629

7950.240

4368.658

12-2018

0.000

102.600

0.000

1002.469

8952.709

4815.224

12-2019

0.000

102.600

0.000

879.032

9831.741

5171.143

12-2020

0.000

102.600

0.000

785.229

10616.970

5460.142

12-2021

0.000

102.600

0.000

710.961

11327.931

5697.998

12-2022

0.000

102.600

0.000

650.379

11978.310

5895.791

12-2023

0.000

102.600

0.000

599.821

12578.131

6061.616

12-2024

0.000

102.600

0.000

556.859

13134.990

6201.561

S TOT

0.000

1304.200

0.000

12639.000

13134.990

6201.561

AFTER

0.000

518.300

0.000

2386.470

15521.462

6650.898

TOTAL

0.000

1822.500

0.000

12639.000

15521.460

15521.462

6650.898


	OIL		CAS
GROSS WELLS		0.0		43.0
GROSS ULT. , MB & MMF		0.000		5365.000
GROSS CUM. , MB & MMF		0.000		0.000
GROSS RES., MB & MMF		0.000		5365.000
NET RES., MB & MMF		0.000		4694.375
NET REVENUE, M$		0.000		29982.955
INITIAL PRICE, $		0.000		6.408
INITIAL N.I., PCT.		0.000		87.500

P.W.

P.W., M$

LIFE, YRS.

22.33

5.00

9917.177

DISCOUNT %

10.00

9.00

7182.122

UNDISCOUNTED PAYOUT, YRS,

3.46

15.00

4608.048

DISCOUNTED PAYOUT, YRS.

3.77

20.00

3256.811

UNDISCOUNTED NET/INVEST.

2.23

25.00

2322.867

DISCOUNTED NET/INVEST.

1.67

30.00

1654.621

RATE-OF-RETURN, PCT.

59.38

40.00

793.668

INITIAL W.I., PCT.

100.000

60.00

-19.261

80.00

-349.971

100.00

-498.634

THIS SCHEDULE IS PART OF A REPORT AND SUBJECT TO QUALIFICATIONS OF THE REPORT.
LEE KEELING AND ASSOCIATES, INC.

Page No. 4

MOUNTAINEER STATE ENERGY INC.
OHIO AND WEST VIRGINIA OIL AND GAS PROPERTIES
MAXIMUM TO MINIMUM SUMMARY AS OF DECEMBER 31, 2009

DFNR

ARIES

GROSS OIL

GROSS GAS

NET OIL

NET GAS

WORKING

REVENUE

CASHFLOW

DISC. 10%

I.D.

LEASE

STATE

COUNTY

FIELD

MBO

MMCF

MBO

MMCF

INTEREST

(M$)

172

MEIGS CO., OHIO-COMPOSIT

1PDP

MEIGS

8.951

2.081.627

7.832

1,821.424

1.000000

0.875000

5,858.034

2,973.514

216

ORISKANY PUD 1

5PUD

JACKSON

0.000

400.000

0.000

350.000

1.000000

0.875000

1,938.200

1,599.702

217

ORISKANY PUD 2

5PUD

JACKSON

0.000

400.000

0.000

350.000

1.000000

0.875000

1,938.200

1,454.275

218

ORISKANY PUD 3

5PUD

JACKSON

0.000

400.000

0.000

350.000

1.000000

0.875000

1,938.200

1,322.068

219

ORISKANY PUD 4

5PUD

JACKSON

0.000

400.000

0.000

350.000

1.000000

0.875000

1,938.200

1,201.880

168

ATHENS CO. OHIO—COMPOSI

1PDP

ATHENS

6.100

383.667

5.338

335.709

1.000000

0.875000

2,411.172

830.046

170

JACKSON CO., WV—COMPOSI

1PDP

JACKSON

0.482

267.837

0.422

205.180

1.000000

0.875000

613.567

527.435

169

ROANE CO., WV—COMPOSITE

1PDP

ROANE

0.000

112.065

0.000

85.800

1.000000

0.875000

131.061

91.422

171

CALHOUN CO., WV—COMPOSI

1PDP

CALHOUN

6.513

24.425

5.699

18.707

1.000000

0.875000

55.077

50.892

174

SHALE PUD 01

5PUD

ATHENS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

41.988

186

SHALE PUD 02

5PUD

ATHENS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

41.656

187

SHALE PUD 03

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

41.326

188

SHALE PUD 04

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

40.999

189

SHALE PUD 05

5PUD

ATHENS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

40.675

190

SHALE PUD 06

5PUD

ATHENS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

40.353

191

SHALE PUD 07

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

40.034

192

SHALE PUD 08

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

38.782

193

SHALE PUD 09

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

38.475

194

SHALE PUD 10

5PUO

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

38.171

195

SHALE PUD 11

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

37.869

196

SHALE PUD 12

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

37.569

197

SHALE PUD 13

5PUO

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

37.272

198

SHALE PUD 14

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

36.977

199

SHALE PUD 15

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

36.685

200

SHALE PUD 16

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

36.395

201

SHALE PUD 17

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

35.256

202

SHALE PUD 18

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

34.977

203

SHALE PUD 19

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

34.701

THIS SCHEDULE IS PART OF A REPORT AND SUBJECT TO QUALIFICATIONS OF THE REPORT.
LEE KEELING AND ASSOCIATES, INC.

MOUNTAINEER STATE ENERGY INC.
OHIO AND WEST VIRGINIA OIL AND GAS PROPERTIES
MAXIMUM TO MINIMUM SUMMARY AS OF DECEMBER 31, 2009

DFNR

ARIES

GROSS OIL

GROSS GAS

NET OIL

NET GAS

WORKING

REVENUE

CASHFLOW

DISC. 10%

I.D.

LEASE

STATE

COUNTY

FIELD

MBO

MMCF

MBO

MMCF

INTEREST

(M$)

204

SHALE PUD 20

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

34.426

205

SHALE PUD 21

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

34.154

206

SHALE PUD 22

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

33.884

207

SHALE PUD 23

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

33.616

208

SHALE PUD 24

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

33.350

209

SHALE PUD 25

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

33.086

210

NO. 191 D D PUD

5PUD

ATHENS

0.000

100.000

0.000

87.500

1.000000

0.875000

190.413

31.670

211

NO. 197 D D PUD

5PUD

ATHENS

0.000

100.000

0.000

87.500

1.000000

0.875000

190.413

31.419

212

NO. 199 D D PUD

5PUD

ATHENS

0.000

100.000

0.000

87.500

1.000000

0.875000

190.413

31.171

213

NO. 222 D D PUD

5PUD

ATHENS

0.000

100.000

0.000

87.500

1.000000

0.875000

190.413

30.196

214

NO. 237 D D PUD

5PUD

ATHENS

0.000

100.000

0.000

87.500

1.000000

0.875000

190.413

29.957

215

2009 REWORKS

2PNP

MEIGS

0.000

49.249

0.000

43.093

1.000000

0.875000

171.225

29.233

220

2009 REWORKS

2PNP

MEIGS

0.000

49.069

0.000

42.935

1.000000

0.875000

170.235

28.672

221

2009 REWORKS

2PNP

MEIGS

0.000

48.797

0.000

42.697

1.000000

0.875000

168.735

27.845

222

2009 REWORKS

2PNP

MEIGS

0.000

48.520

0.000

42.455

1.000000

0.875000

167.214

27.035

223

2009 REWORKS

2PNP

MEIGS

0.000

48.241

0.000

42.211

1.000000

0.875000

165.675

26.243

224

2009 REWORKS

2PNP

MEIGS

0.000

47.958

0.000

41.963

1.000000

0.875000

164.115

25.468

225

2009 REWORKS

2PNP

MEIGS

0.000

47.671

0.000

41.712

1.000000

0.875000

162.535

24.708

226

2009 REWORKS

2PNP

MEIGS

0.000

47.380

0.000

41.458

1.000000

0.875000

160.935

23.965

227

2009 REWORKS

2PNP

MEIGS

0.000

47.086

0.000

41.200

1.000000

0.875000

159.314

23.236

228

2009 REWORKS

2PNP

MEIGS

0.000

23.394

0.000

20.470

1.000000

0.875000

78.836

11.262

185

BEREA PUD 9

5PUD

ATHENS

0.000

85.000

0.000

74.375

1.000000

0.875000

140.976

-1.492

184

BEREA PUD 8

5PUD

MEIGS

0.000

85.000

0.000

74.375

1.000000

0.875000

140.976

-1.504

183

BEREA PUD 7

5PUD

MEIGS

0.000

85.000

0.000

74.375

1.000000

0.875000

140.976

-1.515

182

BEREA PUD 6

5PUD

MEIGS

0.000

85.000

0.000

74.375

1.000000

0.875000

140.976

-1.528

181

BEREA PUD 5

5PUD

MEIGS

0.000

85.000

0.000

74.375

1.000000

0.875000

140.976

-1.540

180

BEREA PUD 4

5PUD

MEIGS

0.000

85.000

0.000

74.375

1.000000

0.875000

140.976

-1.577

179

BEREA PUD 3

5PUD

MEIGS

0.000

85.000

0.000

74.375

1.000000

0.875000

140.976

-1.615

THIS SCHEDULE IS PART OF A REPORT AND SUBJECT TO QUALIFICATIONS OF THE REPORT.
LEE KEELING AND ASSOCIATES, INC.

Page 2 of 3

MOUNTAINEER STATE ENERGY INC.
OHIO AND WEST VIRGINIA OIL AND GAS PROPERTIES
ALPHABETICAL ONE-LINE SUMMARY AS OF DECEMBER 31, 2009

(SORTED BY LEASE, WELL ID, RESERVE CATEGORY)

DFNR

ARIES

RES.

GROSS OIL

GROSS GAS

NET OIL

NET GAS

WORKING

REVENUE

CASHFLOW

DISC 10%

LD.

LEASE

CAT.

STATE

COUNTY

LOCATION

MBO

MMCF

MBO

MMCF

INTEREST

(M$)

221

2009 REWORKS

2PNP

MEIGS

0.000

48.797

0.000

42.697

1.000000

0.875000

168.735

27.845

225

2009 REWORKS

2PNP

MEIGS

0.000

47.671

0.000

41.712

1.000000

0.875000

162.535

24.708

228

2009 REWORKS

2PNP

MEIGS

0.000

23.394

0.000

20.470

1.000000

0.875000

78.836

11.262

227

2009 REWORKS

2PNP

MEIGS

0.000

47.086

0.000

41.200

1.000000

0.875000

159.314

23.236

224

2009 REWORKS

2PNP

MEIGS

0.000

47.958

0.000

41.963

1.000000

0.875000

164.115

25.468

226

2009 REWORKS

2PNP

MEIGS

0.000

47.380

0.000

41.458

1.000000

0.875000

160.935

23.965

223

2009 REWORKS

2PNP

MEIGS

0.000

48.241

0.000

42.211

1.000000

0.875000

165.675

26.243

222

2009 REWORKS

2PNP

MEIGS

0.000

48.520

0.000

42.455

1.000000

0.875000

167.214

27.035

220

2009 REWORKS

2PNP

MEIGS

0.000

49.069

0.000

42.935

1.000000

0.875000

170.235

28.672

215

2009 REWORKS

2PNP

MEIGS

0.000

49.249

0.000

43.093

1.000000

0.875000

171.225

29.233

188

ATHENS CO., OHIO—COMPOS

1PDP

ATHENS

8.100

383.667

5.338

335.709

1.000000

0.875000

2,411.172

830.046

173

BEREA PUD 1

5PUD

MEIGS

0.000

85.000

0.000

74.375

1.000000

0.875000

140.976

-1.694

178

BEREA PUD 2

5PUD

MEIGS

0.000

85.000

0.000

74.375

1.000000

0.875000

140.976

-1.654

179

BEREA PUD 3

5PUD

MEIGS

0.000

85.000

0.000

74.375

1.000000

0.875000

140.976

-1.615

180

BEREA PUD 4

5PUD

MEIGS

0.000

85.000

0.000

74.375

1.000000

0.875000

140.976

-1.577

181

BEREA PUD 5

5PUD

MEIGS

0.000

85.000

0.000

74.375

1.000000

0.875000

140.976

-1.540

182

BEREA PUD 6

5PUD

MEIGS

0.000

85.000

0.000

74.375

1.000000

0.875000

140.976

-1.528

183

BEREA PUD 7

5PUD

MEIGS

0.000

85.000

0.000

74.375

1.000000

0.875000

140.976

-1.515

184

BEREA PUD 8

5PUD

MEIGS

0.000

85.000

0.000

74.375

1.000000

0.875000

140.976

-1.504

185

BEREA PUD 9

5PUD

ATHENS

0.000

85.000

0.000

74.375

1.000000

0.875000

140.976

-1.492

171

CALHOUN CO., WV-COMPOSI

1PDP

CALHOUN

6.513

24.425

5.699

18.707

1.000000

0.875000

55.077

50.892

170

JACKSON CO., WV-COMPOSI

1PDP

JACKSON

0.482

267.837

0.422

205.180

1.000000

0.875000

613.567

527.435

172

MEIGS CO., OHIO — COMPOSIT

1PDP

MEIGS

8.951

2,081.627

7.832

1,821.424

1.000000

0.875000

5,858.034

2,973.514

210

NO. 191 D D PUD

5PUD

ATHENS

0.000

100.000

0.000

87.500

1.000000

0.875000

190.413

31.670

211

NO. 197 D D PUD

5PUD

ATHENS

0.000

100.000

0.000

87.500

1.000000

0.875000

190.413

31.419

212

NO. 199 D D PUD

5PUD

ATHENS

0.000

100.000

0.000

87.500

1.000000

0.875000

190.413

31.171

213

NO.222D D PUD

5PUD

ATHENS

0.000

100.000

0.000

87.500

1.000000

0.875000

190.413

30.196

214

NO.237D D PUD

5PUD

ATHENS

0.000

100.000

0.000

87.500

1.000000

0.875000

190.413

29.957

THIS SCHEDULE IS PART OF A REPORT AND SUBJECT TO QUALIFICATIONS OF THE REPORT.
LEE KEELING AND ASSOCIATES, INC.

MOUNTAINEER STATE ENERGY INC.
OHIO AND WEST VIRGINIA OIL AND GAS PROPERTIES
ALPHABETICAL ONE-LINE SUMMARY AS OF DECEMBER 31, 2009

(SORTED BY LEASE, WELL ID, RESERVE CATEGORY)

DFNR

ARIES

RES.

GROSS OIL

GROSS GAS

NET OIL

NET GAS

WORKING

REVENUE

CASHFLOW

DISC 10%

LD.

LEASE

CAT.

STATE

COUNTY

LOCATION

MBO

MMCF

MBO

MMCF

INTEREST

(M$)

216

ORISKANY PUD 1

5PUD

JACKSON

0.000

400.000

0.000

350.000

1.000000

0.875000

1,938.200

1,599.702

217

ORISKANY PUD 2

5PUD

JACKSON

0.000

400.000

0.000

350.000

1.000000

0.875000

1,938.200

1,454.275

218

ORISKANY PUD 3

5PUD

JACKSON

0.000

400.000

0.000

350.000

1.000000

0.875000

1,938.200

1,322.068

219

ORISKANY PUD 4

5PUD

JACKSON

0.000

400.000

0.000

350.000

1.000000

0.875000

1,938.200

1,201.880

169

ROANE CO., WV — COMPOSITE

1PDP

ROANE

0.000

112.065

0.000

85.800

1.000000

0.875000

131.061

91.422

174

SHALE PUD 01

5PUD

ATHENS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

41.988

186

SHALE PUD 02

5PUD

ATHENS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

41.656

187

SHALE PUD 03

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

41.326

188

SHALE PUD 04

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

40.999

189

SHALE PUD 05

5PUD

ATHENS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

40.675

190

SHALE PUD 08

5PUD

ATHENS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

40.353

191

SHALE PUD 07

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

40.034

192

SHALE PUD 08

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

38.782

193

SHALE PUD 09

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

38.475

194

SHALE PUD 10

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

38.171

195

SHALE PUD 11

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

37.869

196

SHALE PUD 12

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

37.569

197

SHALE PUD 13

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

37.272

198

SHALE PUD 14

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

36.977

199

SHALE PUD 15

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

36.685

200

SHALE PUD 16

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

36.395

201

SHALE PUD 17

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

35.256

202

SHALE PUD 18

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

34.977

203

SHALE PUD 19

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

34.701

204

SHALE PUD 20

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

34.426

205

SHALE PUD 21

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

34.154

206

SHALE PUD 22

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

33.884

207

SHALE PUD 23

5PUD

MEIGS

0.000

100.000

0.000

87.500

1.000000

0.875000

221.913

33.616

THIS SCHEDULE IS PART OF A REPORT AND SUBJECT TO QUALIFICATIONS OF THE REPORT.
LEE KEELING AND ASSOCIATES, INC.

Page 2 of 3


	Acres
	Gross (1)		Net (2)
U.S. Onshore
Producing		122		122
Non-Producing		93		93


Total wells		215		215


(1)		Gross wells are the sum of all wells in which we own an interest.

(2)		Net wells are gross wells multiplied by our fractional working interests on the well.


	Acres
	Gross (1)		Net (2)
U. S Onshore
Developed		19,375		19,375
Undeveloped		—		—


Total Acreage		19,375		19,375


(1)		Gross acres are the sum of all acres in which we own an interest.

(2)		Net acres are gross acres multiplied by our fractional working interests on the acreage.


Assets
Cash	$	1,586
A/R Receivable		482
Oil & Gas Properties		13,134
Property and Equipment		1,363
Other Assets		807


Total Assets	$	17,372

Liabilities & Shareholder’s Equity
Accounts Payable	$	162
Long Term Debt		1,026
Asst Retirement Obligation		2,334
Equity		13,850


Total Liabilities & Shareholders Equity	$	17,372


	Number
SCHEDULES
Summary Forecasts of Production, Income and Net Revenue Discounted at 10 Per Cent		1
Maximum to Minimum by Discounted Future Net Revenue All Reserve Categories		2
One-Line Summary of Valuation and Reserves By Lease Name		3
SUPPLEMENTAL DATA
Forecasts of Production, Income and Net Revenue With Historical and Forecast Production Curves By Reserve Category and Start Date