10-K

 UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 5(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Year ended December 31, 2014

OR

[    ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM             TO         

Commission File Number 000-08187

NEW CONCEPT ENERGY, INC.

(Exact name of registrant as specified in its charter)

Nevada	75-2399477
(State or other jurisdiction of Incorporation or organization)	(IRS Employer Identification Number)
1603 LBJ Freeway, Suite 300 Dallas, Texas	75234
(Address of principal executive offices)	(Zip Code)
Registrant’s Telephone Number including area code	(972) 407-8400

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of each exchange on which registered
Common Stock, $0.01 par value	NYSE MKT

Securities registered pursuant to Section 12(g) of the Act:               None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [  ]   No [X]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [  ]  No [X]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes [X]    No [  ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website if any, every interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files) Yes [X] No [  ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  [X]

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).  Yes [  ]   No [X]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.  Yes [  ]   No [X]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” ”accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.  (Check one):

Large accelerated filer	______	Accelerated filer	______
Non-accelerated filer	______	Smaller reporting company	__X___

The aggregate market value of the shares of voting and non-voting common equity held by non-affiliates of the Registrant, computed by reference to the closing price at which the common equity was last sold which was the sales price of the Common Stock on the NYSE MKT as of June 30, 2014 (the last business day of the Registrant’s most recently completed second fiscal quarter) was $923,000 based upon a total of 895,982 shares held as of June 30, 2013 by persons believed to be non-affiliates of the Registrant.  The basis of the calculation does not constitute a determination by the Registrant as defined in Rule 405 of the Securities Act of 1933, as amended, such calculation, if made as of a date within sixty days of this filing, would yield a different value.

As of March 31, 2015, there were 1,946,935 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:  NONE 

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NEW CONCEPT ENERGY, INC.

Index to Annual Report on Form 10-K

Fiscal year ended December 31, 2014

Forward-Looking Statements	3
PART I	3
Item 1.  Business	3
Item 1A.  Risk Factors	5
Item 1B.  Unresolved Staff Comments	5
Item 2.  Properties	6
Item 3.  Legal Proceedings	8
Item 4.  Mine Safety Disclosures	9
PART II	10
Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	10
Item 6.  Selected Financial Data	10
Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operation	11
Item 7A:  Quantitative And Qualitative Disclosures About Market Risk	14
Item 8.  Financial Statements	14
Item 9.  Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	14
Item 9A.  Controls and Procedures	14
Item 9B.   Other Information	15
PART III	16
Item 10.  Directors, Executive Officers and Corporate Governance	16
Item 11.  Executive Compensation	18
Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	20
Item 13.  Certain Relationships and Related Transactions, and Director Independence	21
Item 14.  Principal Accounting Fees and Services	22
PART IV	24
Item 15.  Exhibits and Financial Statement Schedules	24
SIGNATURES	46

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NEW CONCEPT ENERGY, INC.

Forward-Looking Statements

Certain statements in this Form 10-K are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934.  The words “estimate”, “plan”, “intend”, “expect”, “anticipate”, “and believe” and similar expressions are intended to identify forward-looking statements.  These forward-looking statements are found at various places throughout this Report and in the documents incorporated herein by reference.  New Concept Energy, Inc. disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.  Although we believe that our expectations are based upon reasonable assumptions, we can give no assurance that our goals will be achieved.  Important factors that could cause our actual results to differ from estimates or projections contained in any forward-looking statements are described under Item 1A. Risk Factors beginning on page 5.

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

The Company, through its wholly owned subsidiaries Mountaineer State Energy, Inc. and Mountaineer State Operations, LLC, owns and operates oil and gas wells and mineral leases in Athens and Meigs Counties in Ohio and in Calhoun, Jackson and Roane Counties in West Virginia. The majority of our oil & gas operation was acquired through the acquisition of the Carl E. Smith Companies in 2008.  

As of December 31, 2014 the Company has 153 producing gas wells, 31 non-producing wells and related equipment and mineral leases covering approximately 20,000 acres.

Retirement Community

The Company leases and operates Pacific Pointe Retirement Inn (“Pacific Pointe”) in King City, Oregon.  Pacific Pointe, a retirement center, 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.  Our 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.

Business Strategy

The Company is a Nevada corporation which owns and operates oil and gas wells in Ohio and West Virginia.

The Company intends to continue to pursue acquisition of undervalued or distressed oil and gas related businesses, as well as additional acquisitions of oil and gas leases.  The Company may choose to develop or resell the acquired acreage as management deems most beneficial to the Company. The Company’s strategy is dependent on available financing as well as the market price for oil and gas.

The Company intends to maintain its interest in the retirement center it currently operates, however, management has no current intentions to own or operate any additional retirement facilities.

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.

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Employees

At December 31, 2014, the Company employed, in all segments, 49 people (27 full-time and 22 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

The Company’s sell its oil and natural gas production to a limited number of purchasers. While there is an available market for crude oil and natural gas production, we cannot be assured that the loss of these purchasers would not have a material impact on the Company. Further a reduction in the market price for oil and gas will have a negative effect on the Company’s financial position.

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

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

Competition

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

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

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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).

Available Information

The Company maintains an internet website at www.newconceptenergy.com.  The Company has available through the website, free of charge, Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, reports filed pursuant to Section 16 of the Securities Exchange Act of 1934 (the “Exchange Act”) and amendments to those reports as soon as rea­sonably practicable after we electronically file or furnish such materials to the Securities and Exchange Commission.  In addition, the Company has posted the charters for our Audit Committee, Compensation Committee and Governance and Nominating Committee, as well as our Code of Business Conduct and Ethics, Corporate Governance Guidelines on Director Independence and other information on the website.  These charters and principles are not incorporated in this Report by reference.  The Company will also provide a copy of these documents free of charge to stockholders upon request.  The Company issues Annual Reports containing audited financial statements to its common stockholders.

Item 1A.  Risk Factors

Risks Related to the Company

An investment in our securities involves various risks.  An investor should carefully consider the following risk factors in conjunction with the other information in this report before trading our securities.

The oil & gas industry is highly competitive.  Competition for leasehold interests, subcontractors and qualified employees are keen and we are competing against companies that are larger, more experienced and better capitalized than we are.

The oil & gas industry faces exposure from changes in oil and gas prices due to market fluctuations beyond the Company’s control.

Our governing documents contain anti-takeover provisions that may make it more difficult for a third party to acquire control of us.  Our Articles of Incorporation contain provisions designed to discourage attempts to acquire control of the Company by a merger, tender offer, proxy contest or removal of incumbent management without the approval of our Board of Directors.  As a result, a transaction which otherwise might appear to be in your best interests as a stockholder could be delayed, deferred or prevented altogether, and you may be deprived of an opportunity to receive a premium for your shares over prevailing market rates.  The provisions contained in our Articles of Incorporation include:

● the requirement of an 80% vote to make, adopt, alter, amend, change or repeal our Bylaws or certain key provisions of the Articles of Incorporation that embody, among other things, the anti-takeover provisions;

● the so-called business combination “control act” requirements involving the Company and a person that beneficially owns 10% or more of the outstanding common stock except under certain circumstances; and

● the requirement of holders of at least 80% of the outstanding Common Stock to join together to request a special meeting of stockholders.

As of March 27, 2015 a group of entities owned and controlled approximately 42% of the Company’s outstanding common stock.  This group has significant voting power to block any attempted change in control – See Item 12 – Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters.

Item 1B.  Unresolved Staff Comments

Not applicable.

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Item 2.  Properties

The Company’s principal offices are located at 1603 LBJ Freeway Suite 300, Dallas, Texas 75234.  The Company believes this space is presently suitable, fully utilized and will be adequate for the foreseeable future.

Retirement Community

The Company under a long term lease 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.

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

The average occupancy and lease rate per resident for our one retirement facility is as follows:

                                                                                                                                           Average                             Average

        OccupancyMonthly Rate

December 2014                                                                                                  85.5%                                    $2,235

December 2013                                                                                                  90.0%                                    $2,290

December 2012                                                                                                  92.1%                                    $2,225

December 2011                                                                                                  90.5%                                    $2,191

December 2010                                                                                                  91.3%                                    $2,139

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.

 According to our independent reserve engineering firm, Lee Keeling & Associates, Inc. as of December 31, 2014, our Proved Reserves in Ohio and West Virginia were approximately 2.9 million Mcf of natural gas and 139 thousand Bbls of oil.  Of the total Proved Reserves, approximately 33% were Proved Developed Reserves.  As of December 31, 2014, the related PV-10 of our Proved Reserves was approximately $10.8 million from Ohio & West Virginia.

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Additional Oil and Gas Information

Production

2014 - 159,000 Mcf of natural gas and 10,459 Bbls of oil

2013 - 194,000 Mcf of natural gas and 12,404 Bbls of oil

2012 - 178,000 Mcf of natural gas and   8,115 Bbls of oil

Average sales price per unit

2014 - $4.53 per Mcf and $90.82 per Bbls

2013 - $4.23 per Mcf and $96.00 per Bbls

2012 - $3.59 per Mcf and $92.43 per Bbls

Productive wells

2014 – 153

2013 – 152

2012 – 152

Developed acreage – approximately 20,000 acres

Drilling activity – The Company acquired the operations in Ohio and West Virginia in October 2008 and has, for the most part, focused on improving production from wells. Since the acquisition the Company has drilled 15 wells.

Development plan

In September 2008, the Company through its acquisition of Carl E. Smith, Inc. (now known as Mountaineer State Energy, Inc.) acquired 20,000 acres of mineral rights in Ohio and West Virginia.  The 20,000 acres are both surrounded and interspersed of hundreds of existing wells of which 138 producing wells were owned by the Company and other non-related entities owned the rest of such wells.  The entire area has pipelines in place and decades of information regarding reserves.

In connection with the acquisition, the Company formulated a development plan to rework existing wells, to improve production using modern technology (both in Proved Developed and Proved Undeveloped Reserves), and to follow up with the drilling of new wells. The Company’s plan is to use the current knowledge of the area and new technologies available to both rework its existing wells and drill new wells.

Proved Reserves

The following table presents our estimated Proved Reserves as of December 31, 2014.  These estimates correspond with the method used in presenting the “Supplemental Information on Oil and Gas Operations” in Note N to our consolidated financial statements included in this report.

	Gas		Oil
	(MMCF)		(MBBLS)
Proved Reserves
U.S. Onshore
Developed Producing		673		53
Developed Non-Producing		25		18
Undeveloped		2,168		68
Total Proved Reserves		2,866		139

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

	Gas		Oil
	(MMCF)		(MBBLS)
Proved Undeveloped Reserves as of December 31, 2013		2,168		68
Revaluation of Undeveloped Reserves		-		-
Conversion to Proved Developed Reserves		-		-
Proved Undeveloped Reserves as of December 31, 2014		2,168		68

Well Statistics

The following table sets forth our wells (all natural gas) as of December 31, 2014.

	Wells
	Gross (1)		Net (2)
U.S. Onshore
Producing		153		148
Non-Producing		31		31
Total wells		184		179

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

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

Acreage Statistics

The following table sets forth our developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2014.

	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.

Item 3.  Legal Proceedings

Carlton Energy Group, LLC

In December 2006, Carlton Energy Group, LLC (“Carlton”) instituted litigation against an individual, Eurenergy Resources Corporation (“Eurenergy”) and several other entities including the Company (which was then known as CabelTel International Corporation) alleging tortuous conduct, breach of contract and other matters and as to the Company that it was the alter ego of Eurenergy. The Carlton claims were based upon an alleged tortuous interference with a contract by the individual and Eurenergy related to the right to explore a coal bed methane concession in Bulgaria which had never (and has not to this day) produced a drop of hydrocarbons. At no time during the pendency of this project or since did the Company or any of its officers or directors have any interest whatsoever in the success or failure of the so-called “Bulgaria Project”. However, in the litigation, Carlton alleged that the Company was the “alter-ego” of certain of the other Defendants including Eurenergy.

Following a jury trial in 2009, the Trial Court (295th District Court of Harris County, Texas) reduced the actual damages found by the jury of $66.5 million and entered judgment against EurEnergy and the individual jointly and severally for $31.12 million in actual damages on its tortuous-interference claim and the Court further assessed exemplary damages against The individual and EurEnergy in the amount of $8.5 million each. The Court granted a judgment for the Company finding that it was not the “alter ego” of any of the other parties and thereby would not incur any damages.

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Cross appeals were filed by Carlton, the individual and EurEnergy to the Court of Appeals for the First District of Texas (the “Court of Appeals”) which rendered its opinion on February 14, 2012.  The Court of Appeals opinion, among other things, reinstated the jury award of actual damages jointly and severely against the individual and EurEnergy in the amount of $66.5 million and overturned the Trial Court’s ruling favorable to the Company rendering a judgment for that amount plus exemplary damages against the Company as the “alter ego” of Eurenergy.

The Company and other defendants filed a Petition for Review of the Court of Appeals Opinion with the Supreme Court of the State of Texas. After requesting a response from the Plaintiff the Supreme Court requested a full briefing on the merits. In March 2013 the Court granted the Petition for Review and oral arguments were heard in September 2013. The parties are awaiting a decision by the Court

 The Company vigorously denies that it is the “alter ego” of any other entity; further the Company strongly believes that the Court of Appeals opinion is erroneous in concluding that the Company is an “alter ego” of any other entity which is contrary to Nevada substantive law. There are also questions regarding the underlying liability of EurEnergy and if Eurenergy is successful in its petition for review or, even if unsuccessful if the Company is successful on its positions described above, the Trial Court’s judgment could be reinstated and the Company would have no liability on this claim.

Chesapeake Exploration Limited Partnership and Chesapeake Operating, Inc. (“Chesapeake”)

 In January 2006, the Company entered into a joint operating agreement evidencing its acquisition of a 5% interest in two gas wells being drilled and ultimately operated by Chesapeake.  The Company relied on the cost projections provided by Chesapeake to make its investment decision.  Subsequent to its investment, the Company received an invoice from Chesapeake for $556,217 which, according to Chesapeake, represents the Company’s 5% share of additional costs incurred by Chesapeake in drilling the wells.  The Company believed that these additional costs far exceed any reasonable expense that should have been incurred in drilling the two wells and were incurred without notifying the Company of such expenses. The Company did not pay the additional charges.  In April 2007, Chesapeake filed a lawsuit against the Company and others in District Court of Tarrant County, Texas.

 In March 2011, Chesapeake received a summary judgment award including prejudgment interest for $686,874 plus $65,000 in legal fees. Further, the judgment awarded Chesapeake additional legal fees of $30,000 should the Company file unsuccessful appeals to the Court of Appeals and the Texas Supreme Court. Chesapeake would also receive to post judgment interest.

The judgment did however acknowledge that the plaintiff did not pay the Company for it’s pro rata share of the gas produced by the two wells during the entire period in question.

The Company appealed the judgment to the Court of Appeals which reduced the judgment by $22,000, but otherwise affirmed the lower court ruling. The Company filed an appeal with the Texas Supreme Court; however on February 15, 2013 the Texas Supreme Court denied the petition.

Following the ruling in March 2011, the Company arranged for a bond to the benefit of Chesapeake from a third party bonding company for approximately $791,960. In February 2014 the Company paid the bonding company $791,960 which in turn paid Chesapeake.

There still remains the matter of the gas that is owed to the Company for it’s pro rata share of the gas produced and withheld by Chesapeake. The Company has estimated that there is approximately 70,000 MCF of gas for which the Company needs to be paid or receive in kind which would then be sold. In 2013, Chesapeake sold the two wells to BHP Billiton Petroleum (“BHP”). In 2014 BHP has begun paying the Company for its oil and gas interests out of current monthly production.

Other

The Company has been named as a defendant in other lawsuits in the ordinary course of business.  Management is of the opinion that these lawsuits will not have a material effect on the financial condition, results of operations or cash flows of the Company.

Item 4.  Mine Safety Disclosures

Not Applicable

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PART II

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

The common stock of the Company is listed and traded on the NYSE MKT using the symbol “GBR”.  The following table sets forth the high and low sales prices as reported in the reporting system of the NYSE MKT and other published financial sources.

	2014				2013
	High		Low		High		Low
First Quarter	$	2.16	$	1.62	$	1.89	$	1.23
Second Quarter	$	5.25	$	1.72	$	1.49	$	1.00
Third Quarter	$	3.37	$	1.56	$	1.56	$	1.06
Fourth Quarter	$	1.51	$	0.85	$	2.58	$	1.24

On March 20, 2015 the closing price of the Company’s Common Stock was $2.32 per share.  According to the Transfer Agent’s records, at March 22, 2015 the Company’s Common Stock was held by approximately 398 holders of record.

Dividends

The Company paid no dividends on its Common Stock in 2014 or 2013.  The Company has not paid cash dividends on its Common stock during at least the last ten fiscal years and it has been the policy of the Board of Directors of the Company to retain all earnings to pay down debt and finance future expansion and development of its businesses.  The payment of dividends, if any, will be determined by the Board of Directors in the future in light of conditions then existing, including the Company’s financial condition and requirements, future prospects, restrictions in financing agreements, business conditions and other factors deemed relevant by the Board of Directors.

Purchases of Equity Securities

The Board of Directors has not authorized the repurchase of any shares of its Common Stock under any share repurchase program, except when stockholders owning less than one round lot (100 shares) so request, the Company will purchase shares at market closing on the last trading day prior to receipt of the certificate(s).  The Company repurchased no shares during the three months ended December 31, 2014.

Item 6.  Selected Financial Data

The selected consolidated financial data presented below are derived from the Company’s audited financial statements.

	December 31,
	2014		2013			2012
	(amounts in thousands, except per share amounts)
Operating revenue	$	4,363	$	4,222		$	3,944
Operating expenses		5,253		5,064			5,766
Operating profit (loss)		(890		(842	)		(1,822	)

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Earnings (loss) from continuing operations before income taxes		(779	)		426		168
Income tax (expense)		—			—		—
Earnings (loss) from continuing operations		(779	)		426		168
NET EARNINGS (LOSS)	$	(779	)	$	426	$	168
Earnings (loss) per common share – basic and diluted
Continuing operations	$	(0.40	)	$	0.22	$	0.09
Net earnings per share	$	(0.40	)	$	0.22	$	0.09
Basic weighted average common shares		1,947			1,947		1,947
Balance Sheet Data:
Total assets	$	12,274		$	13,308	$	12,484
Long-term debt		1,428			2,195		2,857
Asset retirement obligation		2,770			2,770		2,770
Total liabilities		5,981			6,236		5,838
Total stockholders’ equity	$	6,293		$	7,072	$	6,646

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

Overview

The Company, through its wholly owned subsidiaries Mountaineer State Energy, Inc. and Mountaineer State Operations, LLC, owns and operates oil and gas wells and mineral leases in Athens and Meigs Counties in Ohio and in Calhoun, Jackson and Roane Counties in West Virginia. The majority of our oil & gas operation was acquired through the acquisition of the Carl E. Smith Companies in 2008.  

As of December 31, 2014 the Company has 153 producing gas wells, 31 non-producing wells and related equipment and mineral leases covering approximately 20,000 acres.

A component of the purchase price for the acquisition of Carl E. Smith, Inc. were certain non-interest bearing long term obligations which the Company will paid out over the next 14 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 $1,513,000 at December 31, 2014.

As of December 31, 2014, the Company leased one independent living community in Oregon, with a capacity of 114 residents.

A number of years ago the Company owned, leased and operated assisted living and retirement communities throughout the United States of America.  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.

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.

11

Oil and Gas Property Accounting

The Company uses the full cost method of accounting for its investment in oil and natural gas properties.  Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas properties (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred.

The full cost method requires the Company to calculate quarterly, by cost center, a “ceiling,” or limitation on the amount of properties that can be capitalized on the balance sheet.  To the extent capitalized costs of oil and natural gas properties, less accumulated depletion and related deferred taxes exceed the sum of the discounted future net revenues of proved oil and natural gas reserves, the lower of cost or estimated fair value of unproved properties subject to amortization, the cost of properties not being amortized, and the related tax amounts, such excess capitalized costs are charged to expense.  Beginning December 31, 2009, full cost companies use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date to calculate the future net revenues of 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 any unproved oil and gas properties on an annual basis for possible impairment or reduction in value.  The Company assesses properties on an individual basis or as a group if properties are individually insignificant.  The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned.  During any period in which these factors indicate an impairment of unproved properties not subject to amortization, the associated costs incurred to date for such properties are then included in unproved properties subject to amortization.

Oil and Gas Reserves

Our 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, 2014, 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.

12

Liquidity and Capital Resources

At December 31, 2014, the Company had current assets of $698,000 and current liabilities of $1,783,000.

Cash and cash equivalents totaled $300,000 at December 31, 2014 and $1,621,000 at December 31, 2013.  New Concept’s principal sources of cash are property operations, sales of oil and gas, and proceeds from sales of assets.

Net cash provided (used) by continuing operating activities was ($282,000) in 2014, $1,602,000 in 2013 and $501,000 in 2012.

Net cash used in investing activities was $954,000 in 2014, $401,000 in 2013 and $209,000 in 2012.

Net cash provided by (used in) financing activities was ($85,000) in 2014, $22,000 in 2013 and ($3,000) in 2012.

Results of Operations

Fiscal 2014 as compared to 2013

Revenues: Total revenues was $4.4 million in 2014 and $4.2 million in 2013.  Net revenue for our oil and gas operation increased by $200,000 for the first nine months of the year but decreased by $200,000 in the final quarter of the year. The fluxuation was principally due to the price the Company received for its oil in 2014 as compared to 2013. The revenue for the retirement community increased by approximately $200,000 in 2014 compared to 2013 principally due to rate increases.

Operating Expenses: Operating expenses were $5.3 million in 2014 and $5.1 million in 2013.

Oil & gas operating expenses decreased by a net of $214,000 in 2014. Pursuant to the requirements of the “full cost ceiling test” in 2013 the Company recorded a non-cash charge to operations of $ 200,000 to write down its investment of $250,000 in two small wells in Arkansas.

 In 2012 the Company recorded a similar non-cash charge to operations of $912,000 for its operations in West Virginia / Ohio. In 2013 the value calculated in accordance with the “full cost ceiling test” was recovered however, the accounting rules prohibit the recovery of a previously taken write-down.

Real estate operating expenses were $2.6 million in 2014 as compared to $2.5 million in 2013. The principal cause of the increase were non-payroll related expenses at the Company’s retirement facility.

Corporate Expenses were $823,000 in 2014 and $500,000 in 2013. The increase is primarily due to consulting fees paid to assist the Company in its oil and gas operations and to identify new oil and gas opportunities.

Interest Income & Expense:Interest Expense was $91,000 in 2014 as compared to $114,000 in 2013. The decrease was due to a reduction in the long term debt owed to the previous owners of the Company’s oil and gas operation in West Virginia / Ohio.

Other Income & (Expense): Other income & (expense) was $197,000 for 2014 as compared to $ ($189,000) in 2013. The balances in 2014 and 2013 are comprised of numerous events.

Bad Debt Expense (Recovery): In 2011 the company recorded a bad debt expense with respect to a note receivable of $10 million dollars. In 2013 and 2012 the company recovered $1.6 million and $2.1 million, respectively, and recorded income (see: Item 13. on page 21 and Note C on page 34 for an explanation of the transaction)

Fiscal 2013 as compared to 2012

Revenues: Total revenues was $4.2 million in 2013 and $3.9 million in 2012.  Net revenue for our oil and gas operation increased by $300,000 principally due to both the quantity of both oil and gas produced as well as the price in 2013 as compared to 2012.

Operating Expenses: Operating expenses were $5.1 million in 2013 and $5.8 million in 2012.

Oil & gas operating expenses increased by a net of $47,000 in 2013. Operating costs including payroll increased by $83,000 which was offset by a $36,000 reduction in depletion.

13

Real estate operating expenses were $2,500,000 in 2013 as compared to $2,400,000 in 2012. The principal cause of the increase was payroll increases at the Company’s retirement facility.

Corporate Expenses were $500,000 in 2013 and $577,000 in 2012. The Company incurred less legal fees in 2013 which was the principal cause of the reduction in costs

Pursuant to the requirements of the “full cost ceiling test” in 2013 the Company recorded a non-cash charge to operations of $ 200,000 to write down its investment of $250,000 in two small wells in Arkansas. These two wells are the subject of ongoing litigation with Chesapeake Exploration L.P.

In 2012 the Company recorded a similar non-cash charge to operations of $912,000 for its operations in West Virginia / Ohio. In 2013 the value calculated in accordance with the “full cost ceiling test” was recovered however the accounting rules prohibit the recovery of a previously taken write-down.

Interest Income & Expense:Interest Expense was $114,000 in 2013 as compared to $208,000 in 2012. The decrease was due to a reduction in the long term debt owed to the previous owners of the Companies oil and gas operation in West Virginia / Ohio.

Other Income & (Expense): Other income & (expense) was $(189,000) for 2013 as compared to $ 122,000 in 2012. The balances in 2013 and 2012 are comprised of numerous events.

Bad Debt Expense (Recovery): In 2011 the company recorded a bad debt expense with respect to a note receivable of $10 million dollars. In 2013 and 2012 the company recovered $1.6 million and $2.1 million respectively and recorded income (see: Item 13. on page 22 and Footnote C on page 37 for an explanation of the transaction)

Item 7a:  Quantitative and Qualitative Disclosures about Market Risk

All of the Company’s debt is financed at fixed rates of interest.  Therefore, the Company has minimal risk from exposure to changes in interest rates.

Item 8.  Financial Statements

The consolidated financial statements required by this Item begin at page 24 of this Report.

Item 9.  Changes In and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Based on an evaluation by our management (with the participation of our Principal Executive Officer and Principal Financial Officer), as of the end of the period covered by this report, our Principal Executive Officer and Principal Financial Officer concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) were effective to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and that such information is accumulated and communicated to our management, including our Principal Executive Officer and Principal Financial Officer, to allow timely decisions regarding required disclosures.

There has been no change in our internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)) during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

14

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company.  Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles.  There are inherent limitations to the effectiveness of any system of internal control over financial reporting.  These limitations include the possibility of human error, the circumvention of overriding of the system and reasonable resource constraints.  Because of its inherent limitations, our internal control over financial reporting may not prevent or detect misstatements.  Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with policies or procedures may deteriorate.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009.  In making this assessment, management used the criteria set forth in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on management’s assessments and those criteria, management has concluded that Company’s internal control over financial reporting was effective as of December 31, 2014.

This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial report.  Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.

Changes in Internal Control over Financial Reporting

In preparation for management’s report on internal control over financial reporting, we documented and tested the design and operating effectiveness of our internal control over financial reporting.  There were no changes in our internal controls over financial reporting (as such term is defined in Exchange Act Rule 13a-15(f)) that occurred during the quarter ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.  Other Information

Not applicable.

15

PART III

Item 10.  Directors, Executive Officers and Corporate Governance

Directors

The affairs of the Company are managed by the Board of Directors.  The directors are elected at the Annual Meeting of Stockholders or appointed by the incumbent Board and serve until the next Annual Meeting of Stockholders, until a successor has been elected or approved, or until earlier resignation, removal or death.

It is the Board’s objective that a majority of the Board consists of independent directors.  For a director to be considered “independent”, the Board must determine that the director does not have any direct or indirect material relationship with the Company.  The Board has established guidelines to assist it in determining director independence, which conform to, or are more exacting than, the independence requirements in the American Stock Exchange listing rules.  The independence guidelines are set forth in the Company’s “Corporate Governance Guidelines”.  The text of this document has been posted on the Company’s internet website at http://www.newconceptenergy.com, and is available in print to any stockholder who requests it.  In addition to applying these guidelines, the Board will consider all relevant facts and circumstances in making an independent determination.

The Company has adopted a code of conduct that applies to all directors, officers and employees, including our principal executive officer, principal financial officer and principal accounting officer.  Stockholders may find our Code of Conduct on our internet website address at http://www.newconceptenergy.com.  We will post any amendments to the Code of Conduct as well as any waivers that are required to be disclosed by the rules of the SEC or the NYSE MKT on our website.

Our Board of Directors has adopted charters for our Audit, Compensation and Governance and Nominating Committees of the Board of Directors.  Stockholders may find these documents on our website by going to the website address http://www.newconceptenergy.com. Stockholders may also obtain a printed copy of the materials referred to by contacting us at the following address:

New Concept Energy, Inc.

Attn: Investor Relations

1603 LBJ Freeway, Suite 300

Dallas, Texas 75234

972-407-8400 (Telephone)

The Audit Committee of the Board of Directors is an “audit committee” for the purposes of Section 3(a) (58) of the Exchange Act.  The members of that Committee are Dan Locklear (Chairman), James Huffstickler and Victor L. Lund.  Mr. Locklear is qualified as an “audit committee financial expert” within the meaning of SEC regulations and the Board has determined that he has the accounting and related financial management expertise within the meaning of the listing standards of the NYSE MKT.  All of the members of the Audit Committee meet the independence and experience requirements of the listing standards of the NYSE MKT.

All members of the Audit Committee, Compensation Committee and the Governance and Nominating Committee must be independent directors.  Members of the Audit Committee must also satisfy additional independence requirements which provide (i) that they may not accept, directly or indirectly, any consulting, advisory or compensatory fee from the Company or any of its subsidiaries other than their director’s compensation (other than in their capacity as a member of the Audit Committee, the Board of Directors or any other Committee of the Board), and (ii) no member of the Audit Committee may be an “affiliated person” of the Company or any of its subsidiaries, as defined by the Securities and Exchange Commission.

The current directors of the Company are listed below, together with their ages, terms of service, all positions and offices with the Company, their principal occupations, business experience and directorships with other companies during the last five years or more.  The designation “affiliated”, when used below with respect to a director, means that the director is an officer or employee of the Company or one of its subsidiaries.  The designation “independent”, when used below with respect to a director, means that the director is neither an officer of the Company nor a director, officer or employee of a subsidiary of the Company, although the Company may have certain business or professional relationships with the director as discussed in Item 13. Certain Relationships and Related Transactions.

16

Roz Campisi Beadle, age 57, (Independent) Director since December 2003

Ms. Beadle is Executive Vice President of Unified Housing Foundationand a licensed realtor.  She is also a Director, President, and Treasurer of Arcadian Energy, Inc., a Nevada corporation, and the holder, together with its subsidiary, of more than 40% of the Common Stock of the Company. She has a background in public relations and marketing.  Ms. Beadle is also extremely active in various civic and community services.

Gene S. Bertcher, age 66, (Affiliated) Director November 1989 to September 1996 and since June 1999

Mr. Bertcher was elected President and Chief Financial Officer effective November 1, 2004.  He was elected Chairman and Chief Executive Officer in December 2006.  Mr. Bertcher has been Chief Financial Officer and Treasurer of the Company since November 1989 and Executive Vice President from November 1989 until he was elected President.  Also, Mr. Bertcher is Executive Vice-President and Chief Financial Officer of American Realty Investors, Inc. (NYSE), Transcontinental Realty Investors, Inc. (NYSE), and Income Opportunity Realty Investors, Inc. NYSE MKT, positions he has occupied since February 2008.  He has been a certified public accountant since 1973.  No family relationship exists between Mr. Bertcher and any director or executive officer of the Company.

James E. Huffstickler, age 70, (Independent) Director since December 2003

Mr. Huffstickler has been Chief Financial Officer of Sunchase America, Ltd., a multi-state property management company, for more than twenty two years.  He is a graduate of the University of South Carolina.  Mr. Huffstickler has been a certified public accountant since 1976.

Dan Locklear, age 61, (Independent) Director since December 2003

Mr. Locklear has been Chief Financial Officer of Sunridge Management Group, a real estate management company, for more than five years.  Mr. Locklear was formerly employed by Johnstown Management Company, Inc. and Trammel Crow Company.  Mr. Locklear has been a certified public accountant since 1981 and a licensed real estate broker in the State of Texas since 1978.

Victor L. Lund, age 85, (Independent) Director since March 1996

Mr. Lund founded Wedgwood Retirement Inns, Inc. (“Wedgwood”) in 1977, which became a wholly owned subsidiary of the Company in 1996.  For most of Wedgwood’s existence, Mr. Lund was Chairman of the Board, President and Chief Executive Officer, positions he held until Wedgwood was acquired by the Company.  Mr. Lund is President and Chief Executive Officer of Wedgwood Services, Inc., a construction services company not affiliated with the Company.

Board Committees

The Board of Directors held five meetings during 2014.  For such year, no incumbent director attended fewer than 75% of the aggregate of (i) the total number of meetings held by the Board during the period for which he or she had been a director, and (ii) the total number of meetings held by all Committees of the Board on which he or she served during the period that he or she served.

The Board of Directors has standing Audit, Compensation and Governance and Nominating Committees.  The Audit Committee was formed on December 12, 2003, and its function is to review the Company’s operating and accounting procedures.  A Charter of the Audit Committee has been adopted by the Board.  The current members of the Audit Committee, all of whom are independent within the SEC regulations, the listing standards of the NYSE MKT and the Company’s Corporate Governance Guidelines are Messrs. Locklear (Chairman), Huffstickler and Lund.  Mr. Dan Locklear is qualified as an Audit Committee financial expert within the meaning of SEC regulations, and the Board has determined that he has the accounting and related financial management expertise within the meaning of the listing standards of the NYSE MKT. The Audit Committee met four times in 2014.

The Governance and Nominating Committee is responsible for developing and implementing policies and practices relating to the corporate governance, including reviewing and monitoring implementation of the Company’s Corporate Governance Guidelines.  In addition, the Committee develops and reviews background information on candidates for the Board and makes recommendations to the Board regarding such candidates.  The Committee also prepares and supervises the Board’s annual review of director independence and the Board’s performance and self-evaluation.  The Charter of the Governance and Nominating Committee was adopted on October 20, 2004.  The members of the Committee are Messrs. Huffstickler (Chairman), Lund and Ms. Beadle.  The Governance and Nominating Committee met once in 2014.

17

The Board has also formed a Compensation Committee of the Board of Directors, adopted a Charter for the Compensation Committee on October 20, 2004, and selected Ms. Beadle (Chairman) and Messrs. Huffstickler and Locklear as members of that Committee.  The Compensation Committee met once in 2014.

The members of the Board of Directors at the date of this Report and the Committees of the Board on which they serve are identified below:

Director	Audit Committee	Governance and Nominating Committee	Compensation Committee
Roz Campisi Beadle		ü	Chairman
Gene S. Bertcher
James E. Huffstickler	ü	Chairman	ü
Dan Locklear	Chairman		ü
Victor L. Lund	ü	ü

Executive Officers

The following person currently serves as the sole executive officer of the Company:  Gene S. Bertcher, Chairman of the Board, President, Chief Executive Officer and Treasurer.  His position with the Company is not subject to a vote of stockholders.  His age, term of service and all positions and offices with the Company, other principal occupations, business experience and directorships with other companies during the last five years or more are listed under the caption “Directors” above.

In addition to the foregoing officers, the Company has other officers not listed herein who are not considered executive officers.

Code of Ethics

The Board of Directors has adopted a code of ethics entitled “Code of Business Conduct and Ethics” that applies to all directors, officers and employees of the Company and its subsidiaries.  In addition, the Company has adopted a code of ethics entitled “Code of Ethics for Senior Financial Officers” that applies to the principal executive officer, president, principal financial officer, chief financial officer, principal accounting officer and controller.  The text of these documents is posted on the Company’s internet website address at http://www.newconceptenergy.com and is available in print to any stockholder who requests them.

Section 16(a) Beneficial Ownership Reporting Compliance

Based solely upon a review of Forms 3, 4 and 5 furnished to the Company pursuant to Rule 16a-3(e) promulgated under the Securities Exchange Act of 1934 (the “Exchange Act“), upon written representations received by the Company, the Company is not aware of any failure by any director, officer or beneficial owner of more than 10% of the Company’s common stock to file with the Securities and Exchange Commission on a timely basis.

Item 11.  Executive Compensation

The following tables set forth the compensation in all categories paid by the Company for services rendered during the fiscal years ended December 31, 2014, 2013 and 2012 by the Chief Executive Officer of the Company and to the other executive officers and Directors of the Company whose total annual salary in 2014 exceeded $100,000.

SUMMARY COMPENSATION TABLE
							Change in
						Non-	Pension
						Equity	Value and
Name						Incentive	Nonqualified	All
and						Plan	Deferred	Other
Principal				Stock	Option	Compen-	Compensation	Compen-
Position	Year	Salary	Bonus	Awards	Awards	sation	Earnings	sation	Total
Gene S. Bertcher (1) Chairman, President & Chief Financial Officer	2014	$107,300							$107,300
	2013	$103,300							$103,300
	2012	$103,300							$103,300

18

Commencing in February 2008, three other publicly held entities needed a chief financial officer, Income Opportunity Realty Investors, Inc. (“IOT”), Transcontinental Realty Investors, Inc. (“TCI”) and American Realty Investors, Inc. (“ARL”) each of which have the same contractual advisor, now Pillar Income Asset Management, Inc. (“Pillar”). On an interim basis, these three entities made an arrangement with the Company for the accounting and administrative services of the Company, specifically Gene S. Bertcher, President and principal executive officer of the Company who is a certified public accountant and has a long history in that industry. At the time NCE, through Bertcher, was also providing accounting and administrative services to other entities on a fee based arrangement to assist those entities when NCE has excess capacity and personnel to provide accounting services. Commencing February 2008, Mr. Bertcher was elected as an officer and chief financial officer of each of IOT, TCI and ARL. As a compensation arrangement evolved over time, the three entities agreed to reimburse NCE for one-half of the gross compensation and related expenses of Bertcher at NCE and from and after December 31, 2010, arranged to provide office space for Mr. Bertcher and certain other NCE personnel rather than requiring operating out of two separate locations. Beginning January 1, 2011, the NCE accounting department moved into offices maintained by the contractual advisor of the three entities. Further, NCE was allowed the use of certain administrative services such as space on the contractual advisor’s computer server, use of copiers, telephone services, etc. NCE has not been charged for the use of office space, computer services, telephone service or other day-to-day cost of operating an office. Each of IOT, TCI and ARL effectively split the cost one-third each. ARL owns in excess of 80% of the Common Stock of TCI and TCI in turn owns in excess of 80% of the Common Stock of IOT. The agreement renews on an annual basis and is terminable on sixty days written notice.

The salary in the above table represents the portion of Mr. Bertcher’s compensation paid by the Company.

GRANTS OF PLAN-BASED AWARDS

None

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END

None

OPTION EXERCISES AND STOCK VESTED

 None

PENSION BENEFITS

None

NONQUALIFIED DEFERRED COMPENSATION

None

19

DIRECTOR COMPENSATION
Name	Fees Earned Or Paid in Cash	Stock Awards	Option Awards	Non-Equity Incentive Plan Compensation	Change in Pension Value and Nonqualified Deferred Compensation Earnings	All Other Compensation	Total
Roz Campisi Beadle	$           10,500						$10,500
Gene S. Bertcher	$           —						$—
James E. Huffstickler	$           10,500						$10,500
Dan Locklear	$           10,500						$10,500
Victor L. Lund	$           10,500						$10,500

MANAGEMENT AND CERTAIN SECURITY HOLDERS

None

Compensation of Directors

The Company pays each non-employee director a fee of $2,500 per year, plus a meeting fee of $2,000 for each board meeting attended.  Employee directors serve without compensation.

Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth, as of March 27, 2015, certain information with respect to all stockholders known by the Company to own beneficially more than 5% of the outstanding Common Stock, which is the only outstanding class of securities of the Company, except for Series B Preferred Stock (the ownership of which is immaterial), as well as information with respect to the Company’s Common Stock owned beneficially by each director and current executive officers, whose compensation from the Company in 2014 exceeded $100,000, and by all directors and executive officers as a group.  Unless otherwise indicated, each of these stockholders has sole voting and investment power with respect to the shares beneficially owned.

		Common Stock
Name of Beneficial Owner	No. of Shares		Percent of Class*
Arcadian Energy, Inc.(3)(5)		813,968	41.81	%
Roz Campisi Beadle(3)(5)		814,068	41.81%
Gene S. Bertcher(2)		40,811	2.1	%
Go Green Fuel N.A., L.P. (6)		100,000	5.14	%
HKS Investment Corporation(1)		108,944	5.6	%
Albert Spiesman(7)		112,326	5.77	%
James E. Huffstickler		—	0	%
Dan Locklear		—	0	%
Victor L. Lund		—	0	%
TacCo Financial, Inc.(3)(4)		14,974	0.77	%
URC Energy, LLC(3)(5)		672,630	34.54	%
All executive officers and directors as a group (five persons)		40,911	2.1	%

*           Based on 1,946,935 shares of common stock outstanding at March 27, 2015

20

(1)   Consists of 108,994 shares of common stock owned by HKS Investment Corporation (“HKS”). According to an original statement on Schedule 13D dated January 9, 2006, the group consists of HKS Investment Corporation, David Hensel, John Kellar and Marshall Stagg, each of whom are deemed to be the beneficial owner of all 108,994 shares.  Hensel is stated to be a shareholder, director and President of HKS; Kellar is a shareholder, director, Vice President and Treasurer of HKS; and Stagg is a shareholder, director and Secretary of HKS.

(2)   Consists of 40,811 shares of common stock owned by Mr. Bertcher.

(3)   Based on Amendment 22 to Schedule 13D, amended February 11, 2015, filed by each of these entities.  Arcadian Energy, Inc. owns 141,338 shares directly and is the sole member of URC Energy, LLC which owns 672,630 shares.  The amended Schedule 13D indicates that these entities, collectively, may be deemed a “Person” within the meaning of Section 13D of the Securities Exchange Act of 1934. Includes 100 shares owned directly by Ms. Beadle, a director, President, and Treasurer of Arcadian Energy, Inc. (“Arcadian”), which owns 127,968 shares direct and is the sole member of URC Energy, LLC, which owns 672,630 shares direct. Arcadian is the sole member of URC Energy, LLC, and Arcadian is deemed to be the beneficial owner of such 672,630 shares. Ms. Beadle shares voting power with one other director over the shares owned by Arcadian and URC Energy, LLC.

(4)   Consists of 14,974 shares of common stock.  Officers and Directors of TacCo Financial, Inc. (“TFI”) are Ted P. Stokely, Chairman; RL S. Lemke, President and Treasurer and Craig E. Landess, Secretary.  TFI’s stock is owned by Ted P. Stokely (100%).

(5)   The direct owner of the 672,630 shares of common stock is URC Energy, LLC.  Under Rule 13d-3 of the Exchange Act, Arcadian Energy, Inc. as the sole member of URC Energy, LLC is deemed to be the beneficial owner of such shares.

(6)   Consists of 100,000 shares of Common Stock owned by Go Green Fuel N.A., L.P. a Texas limited partnership, the sole General Partner of which is GGF North American, LLC, a Texas limited liability company.  According to an original statement on Schedule 13D dated December 31, 2009, Go Green Fuel N.A., L.P. acquired 100,000 shares of Common Stock from West Go Green, LLC a Nevada limited liability company at a price of $6.90 per share and Go Green Fuel N.A., LP granted to West Go Green LLC a “Repurchase Option” for a period of three calendar years from December 31, 2009 to repurchase all or any portion of the 100,000 shares purchased at the original purchase price of $6.90 per share, which Repurchase Option.

 (7) According to a schedule 13G, filed for an event occurring February 27, 2015, by Albert Spiesman, Roth retirement accounts for Albert Spiesman own and hold 82,701 shares; Albert Spiesman, a Trustee for a Roth retirement account f/b/o Joyce E. Spiesman, owns and holds 14,625 shares; and Albert and Joyce E. Spiesman hold, as joint tenancy, 15,000 shares of Common Stock, for an aggregate total of 112,326 shares of Common Stock, beneficially owned by Albert Spiesman.

Item 13.  Certain Relationships and Related Transactions, and Director Independence

Prime Income Asset Management, Inc (“PIAMI”) is a real estate management company that also invests in real estate for its own account. Pillar Income Asset Management, Inc. (“Pillar”) is a real estate management company. Both PIAMI and Pillar are indirectly owned by a private trust. URC Energy, Inc. (“URC”) is and has been a significant investor in the Company. URC is indirectly owned by a private trust. While the trusts for PIAMI and Pillar and URC are separate they have similar trustees and beneficiaries and therefore the Company has noted PIAMI and Pillar as related parties.

Eurenergy Resources, Inc (“ERC”) is an oil & gas company that owned and operated oil and gas wells. Beginning in 2006 the Company made loans to PIAMI and ERC at interest rates higher than the Company believes it could have gotten elsewhere.

In July 2006, the Company made an unsecured $1.4 million loan to ERC at an annual interest rate of 8%.  In June of 2008, the Company entered into a letter of credit agreement with ERC. The terms of the agreement called for interest at the prime rate plus two percent. At May 21, 2009, the balance of the two notes and accrued interest thereon was $3,970,897. On November 20, 2007, the Company made a $630,000 loan PIAMI. In 2008, the Company made additional net advances on the loan totaling approximately $6.3 million. The initial loan and the additional advances were combined into a new loan with interest at the prime rate plus two percent. On May 21, 2009, PIAMI acquired both Eurenergy notes receivable at face value plus accrued interest totaling $3,970,897. Effective May 21, 2009 the Company and PIAMI entered into a new note combing all of the above loans into one note. The loan calls for interest at the prime rate plus 2% with principal and interest payable within 30 days after demand, and if not sooner demanded, on January 31, 2013.

At December 31, 2009, the balance due including accrued interest on the note receivable from PIAMI was $11.1 million.

During 2010 the note was paid down whereby as of December 31, 2010 the outstanding principal and interest totaled $10.4 million. During the first three quarters of 2011 the Company accrued interest of $360,000 and received $715,000 in payments from PIAMI. In the fourth quarter of 2011 the Company determined that the financial condition of PIAMI had deteriorated and there could be no assurance that the amount owed would or could be collected. The company has recorded a reserve of $10 million (the full balance) for the combined note.

Beginning in 2011 the Company conducted business with Pillar whereby Pillar provided the Company with services including processing payroll, acquiring insurance and other administrative matters (rent). The Company believes that by purchasing these services through certain large entities it can get lower costs and better service. In addition, Pillar loaned the Company $225,000 which was used to settle a lawsuit. Pillar does not charge the Company a fee for providing these services.

21

While separate companies, both PIAMI and Pillar are both owned by Realty Advisors, Inc. (“RAI”).  During 2011 and 2012 the Company incurred obligations to Pillar totaling approximately $1.7 million. In a joint agreement among Pillar, PIAMI and the Company, Pillar agreed to relieve the Company of its obligation to pay $1.7 million and the Company agreed to reduce the amount owed by Prime by a like amount. In the third quarter of 2012 the Company recorded a $1.7 million gain on the transaction. In the fourth quarter of 2012 Pillar incurred expenses on behalf of the Company of $376,000 and agreed to forego payment in exchange for a reduction in the PIAMI obligation. The Company recorded an additional $376,000 gain.

During 2014, the Company incurred obligations to Pillar totaling approximately $1.6 million. In a joint agreement among Pillar, PIAMI and the Company, Pillar agreed to relieve the Company of its obligation to pay $1.6 million and the Company agreed to reduce the amount owed by Prime by a like amount.

During 2012, the Company and several other defendants settled a lawsuit for $225,000. The Company paid the entire amount and has a note receivable from one of the other defendants (a subsidiary of Arcadian Energy, Inc) for $112,500 representing its share of the settlement. In addition, the Company paid $48,800 to a consultant and will be reimbursed by Arcadian for a portion of his services.

Except as set forth above, the Reporting Persons do not have any contracts, arrangements, understandings or relationships, legal or otherwise, with any person with respect to any securities of the Issuer, including but not limited to, transfer or voting of any of the securities, finders’ fees, joint ventures, loan or option arrangements, puts or calls, guarantees of profits, divisions of profits or losses, or the giving or withholding of proxies.

It is the policy of the Company that all transactions between the Company and any officer or director, or any of their affiliates, must be approved by non-management members of the Board of Directors of the Company.  All of the transactions described above were so approved.

Item 14.  Principal Accounting Fees and Services

The following table sets forth the aggregate fees for professional services rendered to the Company for the years 2014 and 2013 by the Company’s principal accounting firm Swalm & Associates, P.C.:

Type of Fees	2014		2013
Audit Fees	$	59,566	$	57,536
Audit Related Fees		0		0
Tax Fees		8,525		8,525
Total Fees	$	68,091	$	66,061

All services rendered by the principal auditors are permissible under applicable laws and regulations and were pre-approved by either of the Board of Directors or the Audit Committee, as required by law.  The fees paid to principal auditors for services described in the above table fall under the categories listed below:

Audit Fees: These are fees for professional services performed by the principal auditor for the audit of the Company’s annual financial statements and review of financial statements included in the Company’s Form 10-Q filings and services that are normally provided in connection with statutory and regulatory filings or engagements.

Audit-Related Fees: These are fees for assurance and related services performed by the principal auditor that are reasonably related to the performance of the audit or review of the Company’s financial statements.  These services include attestation by the principal auditor that is not required by statute or regulation and consulting on financial accounting/reporting standards.

Tax Fees: These are fees for professional services performed by the principal auditor with respect to tax compliance, tax planning, tax consultation, returns preparation and reviews of returns.  The review of tax returns includes the Company and its consolidated subsidiaries.

All Other Fees: These are fees for other permissible work performed by the principal auditor that does not meet the above category descriptions.

These services are actively monitored (as to both spending level and work content) by the Audit Committee to maintain the appropriate objectivity and independence in the principal auditor’s core work, which is the audit of the Company’s consolidated financial statements.

22

Financial Information Systems Design and Implementation Fees

Swalm & Associates, P.C. did not render professional services to the Company in 2014 with respect to financial information systems design and implementation.

Under the Sarbanes-Oxley Act of 2002 (the “SO Act”), and the rules of the Securities and Exchange Commission (the “SEC”), the Audit Committee of the Board of Directors is responsible for the appointment, compensation and oversight of the work of the independent auditor.  The purpose of the provisions of the SO Act and the SEC rules for the Audit Committee’s role in retaining the independent auditor is two-fold.  First, the authority and responsibility for the appointment, compensation and oversight of the auditors should be with directors who are independent of management.  Second, any non-audit work performed by the auditors should be reviewed and approved by these same independent directors to ensure that any non-audit services performed by the auditor do not impair the independence of the independent auditor.  To implement the provisions of the SO Act, the SEC issued rules specifying the types of services that an independent auditor may not provide to its audit client, and governing the Audit Committee’s administration of the engagement of the independent auditor.  As part of this responsibility, the Audit Committee is required to pre-approve the audit and non-audit services performed by the independent auditor in order to assure that they do not impair the auditor’s independence.  Accordingly, the Audit Committee has adopted a pre-approval policy of audit and non-audit services (the “Policy”), which sets forth the procedures and conditions pursuant to which services to be performed by the independent auditor are to be pre-approved.  Consistent with the SEC rules establishing two different approaches to pre-approving non-prohibited services, the Policy of the Audit Committee covers pre-approval of audit services, audit-related services, international administration tax services, non-U.S. income tax compliance services, pension and benefit plan consulting and compliance services, and U.S. tax compliance and planning.  At the beginning of each fiscal year, the Audit Committee will evaluate other known potential engagements of the independent auditor, including the scope of work proposed to be performed and the proposed fees, and the approve or reject each service, taking into account whether services are permissible under applicable law and the possible impact of each non-audit service on the independent auditor’s independence from management.  Typically, in addition to the generally pre-approved services, other services would include due diligence for an acquisition that may or may not have been known at the beginning of the year.  The Audit Committee has also delegated to any member of the Audit Committee designated by the Board or the financial expert member of the Audit Committee responsibilities to pre-approve services to be performed by the independent auditor not exceeding $25,000 in value or cost per engagement of audit and non-audit services, and such authority may only be exercised when the Audit Committee is not in session.

23

PART IV

Item 15.  Consolidated Financial Statement And Supplementary Schedules

INDEX TO FINANCIAL STATEMENTS

                                                                                                                                            Page

FINANCIAL STATEMENTS
Report of Swalm & Associates, P.C.	25
Consolidated Balance Sheets	26
Consolidated Statements of Operations	28
Consolidated Statements of Cash Flows	29
Consolidated Statements of Changes in Stockholders’ Equity	30
Notes to Consolidated Financial Statements	31
FINANCIAL STATEMENT SCHEDULES:  Other financial statement schedules have been omitted because they are not required, are not applicable, or the information required is included in the Consolidated Financial Statements or the notes thereto.

24

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

New Concept Energy, Inc.

We have audited the accompanying consolidated balance sheets of New Concept Energy, Inc., and Subsidiaries, as of December 31, 2014 and 2013, and the related consolidated statements of income, shareholders' equity and cash flows for each of the years in the three-year period ended December 31, 2014.  These consolidated financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on the consolidated financial statements based on our audit.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, audits of its internal control over financial reporting.  Our audits include consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion of the effectiveness of the Company’s internal control over financial reporting.  Accordingly, we express no such opinion.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of New Concept Energy, Inc., and Subsidiaries as of December 31, 2014 and 2013, and the consolidated results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

As described in Note C to the consolidated financial statements, the Company had significant balances due from an affiliate which was fully reserved in 2011.

As described in Note K to the financial statements, the Company is named as a party to a significant lawsuit judgment.  The Company and its legal counsel believe that the judgment is in error and that while the outcome of the matter cannot presently be determined, they do not believe that the matter will have a material effect on the Company’s consolidated financial position.  Accordingly, no provision for any liability that may result has been made in the financial statements.  Nevertheless, due to the nature of the uncertainty, it is reasonably possible that management’s view of the outcome will change in the near term.

/s/ Swalm & Associates, P.C.

Richardson, Texas

March 31, 2015

25

NEW CONCEPT ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(amounts in thousands)
	December 31
	2014		2013
Assets
Current assets
Cash and cash equivalents	$	300	$	1,621
Accounts receivable from oil and gas sales		216		195
Other current assets		182		203
Total current assets		698		2,019
Oil and natural gas properties (full cost accounting method)
Proved developed and undeveloped oil and gas properties, net of depletion		8,809		9,190
Property and equipment, net of depreciation
Land, buildings and equipment - oil and gas operations		1,476		1,442
Other		162		183
Total property and equipment		1,638		1,625
Other assets (including $126,000 and $122,000 in 2014 and 2013 due from related parties)		1,129		474
Total assets	$	12,274	$	13,308

The accompanying notes are an integral part of these consolidated financial statements.

26

NEW CONCEPT ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - CONTINUED
(amounts in thousands, except share amounts)
	December 31
	2014			2013
Liabilities and stockholders' equity
Current liabilities
Accounts payable - trade (including $494 in 2014 due to related parties)	$	673		$	121
Accrued expenses		229			965
Current portion of long term debt		881			185
Total current liabilities		1,783			1,271
Long-term debt
Notes payable less current portion		1,428			2,195
Asset retirement obligation		2,770			2,770
Total liabilities		5,981			6,236
Stockholders' equity
Series B convertible preferred stock, $10 par value, liquidation value
of $100 authorized 100 shares, issued and outstanding one share		1			1
Common stock, $.01 par value; authorized, 100,000,000
shares; issued and outstanding, 1,946,935 shares
at December 31, 2014 and 2013		20			20
Additional paid-in capital		58,838			58,838
Accumulated deficit		(52,566	)		(51,787	)
		6,293			7,072
Total liabilities & stockholders' equity	$	12,274		$	13,308

The accompanying notes are an integral part of these consolidated financial statements.

27

NEW CONCEPT ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATION
(amounts in thousands, except per share data)
	Year Ended December 31,
	2014			2013			2012
Revenue
Oil and gas operations, net of royalties	$	1,489		$	1,477		$	1,182
Real estate operations		2,874			2,745			2,762
		4,363			4,222			3,944
Operating expenses
Oil and gas operations		1,853			1,867			1,820
Real estate operations		1,616			1,555			1,465
Lease expense		961			942			924
Corporate general and administrative		823			500			577
Accretion of asset retirement obligation		-			-			68
Impairment of natural gas and oil properties		-			200			912
		5,253			5,064			5,766
Operating earnings (loss)		(890	)		(842	)		(1,822	)
Other income (expense)
Interest income		5			9			-
Interest expense		(91	)		(114	)		(208	)
Bad debt expense (recovery) - note receivable		-			1,562			2,076
Other income (expense), net		197			(189	)		122
		111			1,268			1,990
Earnings (loss) from continuing operations		(779	)		426			168
Net income (loss) applicable to common shares	$	(779	)	$	426		$	168
Net income (loss) per common share-basic and diluted	$	(0.40	)	$	0.22		$	0.09
Weighted average common and equivalent shares outstanding - basic		1,947			1,947			1,947

The accompanying notes are an integral part of these consolidated financial statements.

28

NEW CONCEPT ENERGY, INC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in thousands)
	Year ended December 31,
	2014			2013			2012
Cash flows from operating activities
Net income (loss)	$	(779	)	$	426		$	168
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion and amortization		732			763			779
Impairment of natural gas and oil properties		-			200			912
Accretion of asset retirement obligation		-			-			68
Write-off (recovery) of affiliate receivable		-			(1,562	)		(2,076	)
Reserve for liability in Chesapeake litigation		-			381
Changes in operating assets and liabilities
Other current and non-current assets		5			(163	)		(227	)
Accounts payable and other liabilities		(240	)		1,557			756
Interest payable		-			-			121
Net cash provided by (used) in operating activities		(282	)		1,602			501
Cash flows from investing activities
Investment in oil and gas properties		(129	)		(240	)		(103	)
Fixed asset additions		(175	)		(161	)		(106	)
Real estate held for investment		(650	)
Net cash used in investing activities		(954	)		(401	)		(209	)
Cash flows from financing activities
Payment on notes payable		(213	)		(40	)		(54	)
Proceeds from loans		128			62			51
Net cash provided by (used in) financing activities		(85	)		22			(3	)
Net increase (decrease) in cash and cash equivalents		(1,321	)		1,223			289
Cash and cash equivalents at beginning of year		1,621			398			109
Cash and cash equivalents at end of year	$	300		$	1,621		$	398
Supplemental disclosures of cash flow information
Cash paid for interest on notes payable:	$	77		$	72		$	87

The accompanying notes are an integral part of these consolidated financial statements.

29

New Concept Energy Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(amounts in thousands)

	Series B				Common				Additional		Accum-
	Preferred stock				Stock				paid in		ulated
	Shares		Amount		Shares		Amount		capital		deficit			Total
Balance at December 31, 2011		1	$	1		1,947	$	20	$	58,838	$	(52,381	)	$	6,478
Net Income												168			168
Balance at December 31, 2012		1		1		1,947		20		58,838		(52,213	)		6,646
Net Income												426			426
Balance at December 31, 2013		1		1		1,947		20		58,838		(51,787	)		7,072
Net Income												(779	)		(779	)
Balance at December 31, 2014		1	$	1		1,947	$	20	$	58,838	$	(52,566	)	$	6,293

The accompanying notes are an integral part of these consolidated financial statements.

30

New Concept Energy Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014

NOTE A – BUSINESS DESCRIPTION AND PRESENTATION

The Company, through its wholly owned subsidiaries Mountaineer State Energy, Inc. and Mountaineer State Operations, LLC, operates oil and gas wells and mineral leases in Athens and Meigs Counties in Ohio and in Calhoun, Jackson and Roane Counties in West Virginia. As of December 31, 2014 the Company has 153 producing oil & gas wells, 31 non-producing wells and related equipment and mineral leases covering approximately 20,000 acres.

The Company engaged the firm of independent oil and gas engineers Lee Keeling & Associates, Inc. to estimate the net oil and gas reserves.  On the basis of their study, the estimates of future net revenues using a present value discount of 10% were estimated to be $10.8 million at December 31, 2014.

NCE also leases and operates a retirement community in King City Oregon, with a capacity of 114 residents.

In February 2014 the Company acquired 7.4 acres of undeveloped land in Desoto TX. For $624,000. The Company believes the highest and best use of this property is for the construction and development of multifamily housing. The Company acquired the property for investment purposes.  This investment is included in assets on the balance sheet.

NOTE B - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Principles of Consolidation

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

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, which is included in operations, was $176,000, $188,000 and $165,000 for 2014, 2013 and 2012, respectively.

Depreciation, Depletion and Amortization of Producing Oil & Gas Properties

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.

The Company recorded depletion of mineral rights of $510,000, $650,000 and $614,000 in 2014, 2013 and 2012 respectively.

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 sells most of its natural gas production to one purchaser and all of its oil production to one purchaser.  While there is an available market for crude oil and natural gas production, we cannot be assured that the loss of this purchaser would not have a material impact on the Company.

31

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

The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission.  Such assumptions include using recent oil and gas prices and year-end costs for estimated future development and production expenditures.  Discounted future net cash flows are calculated using a 10% rate.  Changes in any of these assumptions could have a significant impact on the standardized measure.  Accordingly, the standardized measure does not represent management’s estimated current market value of proved reserves. At December 31, 2014, 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, 2014.

Full cost accounting

The Company uses the full cost method of accounting for its investment in oil and natural gas properties.  Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas properties (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred.

The full cost method requires the Company to calculate quarterly, by cost center, a “ceiling,” or limitation on the amount of properties that can be capitalized on the balance sheet.  To the extent capitalized costs of oil and natural gas properties, less accumulated depletion and related deferred taxes exceed the sum of the discounted future net revenues of proved oil and natural gas reserves, the lower of cost or estimated fair value of unproved properties subject to amortization, the cost of properties not being amortized, and the related tax amounts, such excess capitalized costs are charged to expense.  Beginning December 31, 2009, full cost companies use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date to calculate the future net revenues of 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 any unproved oil and gas properties on an annual basis for possible impairment or reduction in value.  The Company assesses properties on an individual basis or as a group if properties are individually insignificant.  The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned.  During any period in which these factors indicate an impairment of unproved properties not subject to amortization, the associated costs incurred to date for such properties are then included in unproved properties subject to amortization.

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, 2014 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.

32

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

Revenue Recognition

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

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

The Company follows the sales method of accounting for natural gas production imbalances and would recognize a liability if the existing 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 consolidated financial statements and revenues and expenses during the reporting period.  Actual results could differ from those estimates.

Cash Equivalents

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

Other Intangible Assets

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

Impairment of Notes Receivable

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

Impairment of Long-Lived Assets

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

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

Sales of Real Estate

Gains on sales of real estate are recognized to the extent permitted by Accounting Standards Codification Topic 360-20, “Real Estate Sales – Real Estate Sales”, (“ASC 360-20”).  Until the requirements of ASC 360-20 have been met for full profit recognition, sales are accounted for by the installment or cost recovery method, whichever is appropriate.

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Real Estate Held for Sale

Accounting Standards Codification Topic 360, “Property, Plant, & Equipment” (“ASC 360”)requires that properties held for sale be reported at the lower of carrying amount or fair value less costs of sale.  If a reduction in a held for sale property’s carrying amount to fair value less costs of sale is required, a provision for loss is recognized by a charge against earnings.  Subsequent revisions, either upward or downward, to a held for sale property’s estimated fair value less costs of sale are recorded as an adjustment to the property’s carrying amount, but not in excess of the property’s carrying amount when originally classified as held for sale.  A corresponding charge against or credit to earnings is recognized.  Properties held for sale are not depreciated.

Asset Retirement Obligation

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

Income Taxes

The Company accounts for income taxes in accordance with Accounting Standards Codification, (“ASC”) No. 740, “Accounting for Income Taxes”. ASC 740 requires an asset and liability approach to financial accounting for income taxes. In the event differences between the financial reporting basis and the tax basis of the Company’s assets and liabilities result in deferred tax assets, ASC 740 requires an evaluation of the probability of being able to realize the future benefits indicated by such assets. A valuation allowance is provided for a portion or all of the deferred tax assets when there is an uncertainty regarding the Company’s ability to recognize the benefits of the assets in future years.  Recognition of the benefits of deferred tax assets will require the Company to generate future taxable income.  There is no assurance that the Company will generate earnings in future years.  Since management could not determine the likelihood that the benefit of the deferred tax asset would be realized, no deferred tax asset was recognized by the Company.

Recent Accounting Pronouncements

There were no recent accounting pronouncements that our Company has not implemented that materially affect our consolidated financial statements.

NOTE C – RECEIVABLES – PAYABLES – RELATED PARTIES

Prime Income Asset Management, Inc.

Prime Income Asset Management, Inc. (“PIAMI”) is a real estate management company that also invests in real estate for its own account. Pillar Income Asset Management, Inc. (“Pillar”) is a real estate management company. Both PIAMI and Pillar are indirectly owned by a private trust. URC Energy Inc. (“URC”) is and has been a significant investor in the Company. URC is indirectly owned by a private trust  While the trusts for PIAMI and Pillar and URC are separate they have similar trustees and beneficiaries and therefore the Company has noted PIAMI and Pillar as related parties. Eurenergy Resources, Inc. (“ERC”) is an oil & gas company that owned and operated oil and gas wells.

Beginning in 2006 the Company made loans to PIAMI and ERC at interest rates higher than the Company believes it could have gotten elsewhere.  On May 21, 2009, PIAMI acquired both Eurenergy notes receivable at face value plus accrued interest totaling $3,970,897. Effective May 21, 2009 the Company and PIAMI entered into a new note combing all of the above loans into one note. The loan calls for interest at the prime rate plus 2% with principal and interest payable within 30 days after demand, and if not sooner demanded, on January 31, 2013.

At December 31, 2009, the balance due including accrued interest on the note receivable from PIAMI was $11.1 million. During 2010 the note was paid down whereby as of December 31, 2010 the outstanding principal and interest totaled $10.4 million.  During the first three quarters of 2011 the Company accrued interest of $360,000 and received $715,000 in payments from PIAMI. In the fourth quarter of 2011 the Company determined that the financial condition of PIAMI had deteriorated and there could be no assurance that the amount owed would or could be collected. The company has recorded a reserve of $10 million (the full balance) for the combined note.

Beginning in 2011, the Company conducted business with Pillar whereby Pillar provided the Company with services including processing payroll, acquiring insurance and other administrative matters (rent). The Company believes that by purchasing these services through certain large entities it can get lower costs and better service. Pillar does not charge the Company a fee for providing these services.

34

While separate companies, both PIAMI and Pillar are both owned by Realty Advisors, Inc. (“RAI”).  During 2011 and 2012, the Company incurred obligations to Pillar totaling approximately $2.1 million. In a joint agreement among Pillar, PIAMI and the Company, Pillar agreed to relieve the Company of its obligation to pay $2.1 million and the Company agreed to reduce the amount owed by Prime by a like amount. In 2012 the Company recorded a $2.1 million recovery on the transaction reduction in the PIAMI obligation.

During 2013, the Company incurred obligations to Pillar totaling approximately $1.6 million. In a joint agreement among Pillar, PIAMI and the Company, Pillar agreed to relieve the Company of its obligation to pay $1.6 million and the Company agreed to reduce the amount owed by Prime by a like amount.

Coastland Operations, LLC

During 2012, the Company and several other defendants settled a lawsuit for $225,000. The Company paid the entire amount and has a note receivable from one of the other defendants, Coastland Operations, LLC (a subsidiary of Arcadian Energy, Inc) for $112,500 representing its share of the settlement Arcadian for a portion of his services. Arcadian, through its subsidiary URC is a significant shareholder of the Company and is therefore considered a related party. In March 2015 the $112,500 plus all accrued interest thereon was paid to the Company.

NOTE D – FAIR VALUE OF FINANCIAL INSTRUMENTS

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate values.

Cash and cash equivalents - The carrying amount approximates fair value because of the short maturity of these instruments.

Long-term debt - The fair value of the Company’s long-term debt is estimated based on market rates for the same or similar issues.  The carrying value of long-term debt approximates its fair value.

Notes receivable – The fair value of the note receivable from an affiliate partnership is estimated to approximate fair value based on its short maturity.  It is not practical to estimate the fair value of notes receivable from sale of properties because no quoted market exists and there are no comparable debt instruments to provide a basis for valuation.

NOTE E – NOTES PAYABLE

Notes payable is comprised of the following (in thousands):

	2014		2013
Notes payable from the acquisition of Mountaineer State Energy, Inc.	$	1,514	$	1,499
Bank Debt	$	795	$	881
	$	2,309	$	2,380

Mountaineer State Energy, Inc. was acquired in 2008. As part of the purchase price the Company issued non-interesting bearing notes with the first payment being required in 2015 and the final payment due in 2032. The balance reflected above is the present value of those obligations.

Bank debt represent loans from a bank to finance drilling and equipment at the Company’s oil and gas operation. The interest rate ranges from 5% to 5 ½ %. The loans are collateralized by the Company’s oil & gas leases as well as real property and equipment.

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Aggregate annual principal maturities of long-term debt at December 31, 2014 are as follows (in thousands):

2014		881
2015		263
2016		261
2017		256
2018		107
Thereafter		541
	$	2,309

NOTE F – OPERATING LEASES

The Company leases a retirement community under an operating lease which expires January 31, 2017, with an option to renew for an additional five-year period. The Company also has operating leases for equipment and office space.  The leases generally provide that the Company pay property taxes, insurance and maintenance.

Future minimum payments for the primary lease following December 31, 2014 are as follows (in thousands):

2015		980
2016		1,000
2017		83
	$	2,063

Lease expense in 2014, 2013 and 2012 was$961,000, $942,000 and $924,000 respectively.

NOTE G - EARNINGS PER SHARE

The following table sets forth the computations of basic and diluted earnings per share (in thousands, except per share data):

	Year Ended December 31,
	2014			2013		2012
Basic Earnings Per Share:
Numerator:
Net income from continuing operations	$	(779	)	$	426	$	168
Denominator:
Weighted average shares outstanding		1,947			1,947		1,947
Basic earnings (loss) per share from continuing operations		(0.40	)		0.22		0.09
Basic earnings per share from discounted operations	$	-		$	-	$	-

NOTE H – INCOME TAXES

At December 31, 2014, the Company had net operating loss carry forwards of approximately $7.4 million, which expire between 2014 and 2027.

Forms 1120, U.S, Corporation Income Tax Returns, for the years ending December 31, 2014, 2013, 2012 are subject to examination, by the IRS, generally for three years after they are filed.

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The following table presents the principal reasons for the difference between the Company's effective tax rate and the United States statutory income tax rate.

	2014			2013			2012
Federal income tax at statutory rate per books	$	0		$	149		$	59
Change in valuation allowance		0			0			0
Net operating loss		0			(149	)		(59	)
Federal income tax per tax return	$	0		$	0		$	0
Effective income tax rate		0.00	%		0.00	%		0.00	%

NOTE I – STOCKHOLDERS’ EQUITY

Outstanding Preferred Stock

Preferred stock consists of the following (amounts in thousands):

	Year Ended
	December 31,
	2014		2013
Series B convertible preferred stock, $10 par value, liquidation value of $100, authorized 100 shares, issued and outstanding one share		1		1

The Series B preferred stock has a liquidation value of $100 per share. The right to convert expired April 30, 2003.  Dividends at a rate of 6% are payable in cash or preferred shares at the option of the Company.

NOTE J – OTHER INCOME (EXPENSE)

Other income (expense) consists of the following: (amounts in thousands)

	Year ended December 31,
	2014		2013			2012
Litigation costs for the Chesapeake matter	$	-		(382	)		-
Income for gas held by Chesapeake		-		200			-
Other		197		(7	)		122
	$	197	$	(189	)	$	122

NOTE K – CONTINGENCIES

Carlton Energy Group, LLC

In December 2006, Carlton Energy Group, LLC (“Carlton”) instituted litigation against an individual, Eurenergy Resources Corporation (“Eurenergy”) and several other entities including New Concept Energy, Inc., which was then known as CabelTel International Corporation (the “Company”) alleging tortuous conduct, breach of contract and other matters and as to the Company that it was the alter ego of Eurenergy. The Carlton claims were based upon an alleged tortuous interference with a contract by the individual and Eurenergy related to the right to explore a coal bed methane concession in Bulgaria which had never (and has not to this day) produced any hydrocarbons. At no time during the pendency of this project or since did the company or any of its officers or directors have any interest whatsoever in the success or failure of the so-called “Bulgaria Project”. However, in the litigation, Carlton alleged that the Company was the alter-ego of certain of the other Defendants including Eurenergy.

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Following a jury trial in 2009, the Trial Court (295th District Court of Harris County, Texas) reduced the actual damages found by the jury of $66.5 million and entered judgment against EurEnergy and the individual jointly and severally for $31.12 million in actual damages on its tortuous-interference claim and the Court further assessed exemplary damages against The individual and EurEnergy in the amount of $8.5 million each. The Court granted a judgment for the Company that it was not the alter ego of any of the other parties and thereby would not incur any damages.

Cross appeals were filed by Carlton, the individual and EurEnergy to the Court of Appeals for the First District of Texas (the “Court of Appeals”) which rendered its opinion on February 14, 2012.  The Court of Appeals opinion, among other things, reinstated the jury award of actual damages jointly and severely against the individual and EurEnergy in the amount of $66.5 million and overturned the Trial Court’s ruling favorable to the Company rendering a judgment for that amount plus exemplary damages against the Company as the “alter ego” of Eurenergy.

The Company and the other defendants, filed a Petition for Review of the Court of Appeals Opinion with the Supreme Court of the State of Texas. After requesting a response from the Plaintiff the Supreme Court requested full briefing on the merits. In March 2013 the Court granted the Petition for Review and in September 2013 the Court heard oral arguments. The parties are awaiting a ruling.

 The Company vigorously denies that it is the “alter ego” of any other entity; further the Company strongly believes that the Court of Appeals opinion is erroneous in concluding that the Company is an “alter ego” of any other entity which is contrary to Nevada substantive law. There are also questions regarding the underlying liability of EurEnergy and if Eurenergy is successful in its petition for review or, even if unsuccessful if the Company is successful on its positions described above, the Trial Court’s judgment could be reinstated and the Company would have no liability on this claim.

Chesapeake Exploration Limited Partnership and Chesapeake Operating, Inc. (“Chesapeake”)  In January 2006, the Company entered into a joint operating agreement evidencing its acquisition of a 5% interest in two gas wells being drilled and ultimately operated by Chesapeake.  The Company relied on the cost projections provided by Chesapeake to make its investment decision.  Subsequent to its investment, the Company received an invoice from Chesapeake for $556,217 which, according to Chesapeake, represents the Company’s 5% share of additional costs incurred by Chesapeake in drilling the wells.  The Company believes that these additional costs far exceed any reasonable expense that should have been incurred in drilling the two wells and were incurred without notifying the Company of such expenses.  The Company has requested an accounting of the additional expenses and a reconciliation of the final costs to the cost estimates previously presented.  In April 2007, Chesapeake filed a lawsuit against the Company and others in District Court of Tarrant County, Texas.

 In March 2011, Chesapeake received a summary judgment award including prejudgment interest for $686,874 plus $65,000 in legal fees. Further the judgment awarded Chesapeake additional legal fees of $30,000 should the Company file unsuccessful appeals to the Court of Appeals and the Texas Supreme Court. Chesapeake would also receive to post judgment interest.

The judgment did however acknowledge that the plaintiff did not pay the company for it’s pro rata share of the gas produced by the two wells during the entire period in question.

The Company has appealed the judgment to the Court of Appeals which reduced the judgment by $22,000, but otherwise affirmed the lower court ruling. The Company filed an appeal with the Texas Supreme Court, however on February 15, 2013 the Texas Supreme Court denied the petition.

Following the ruling in March 2011, the Company arranged for a bond to the benefit of Chesapeake from a third party bonding Company for approximately $791,960. In February 2014, the Company paid the bonding company $791,960, who in turn paid Chesapeake.

There still remains the matter of the gas that is owed to the Company for it’s pro rata share of the gas produced and withheld by Chesapeake. The Company has estimated that there is approximately 70,000 MCF of gas for which the Company needs to be paid or receive in kind which would then be sold. In 2013 Chesapeake sold the two wells to BHP Billiton Petroleum (“BHP”). In 2014 BHP has begun paying the Company for its oil and gas interests out of current monthly production.

Other

The Company has been named as a defendant in other lawsuits in the ordinary course of business.  Management is of the opinion that these lawsuits will not have a material effect on the financial condition, results of operations or cash flows of the Company.

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NOTE L – OPERATING SEGMENTS

The following table reconciles the segment information to the corresponding amounts in the Consolidated Statements of Operations and total assets:

Year ended December 31, 2014	Oil and Gas Operations			Retirement Facility		Corporate			Total
Operating revenue	$	1,489		$	2,874	$	-		$	4,363
Operating expenses		1,233			2,512		823		$	4,568
Depreciation, depletion and amortization		620			65		-		$	685
Impairment of oil and gas properties		-			-		-		$	-
Total Operating Expenses		1,853			2,577		823			5,253
Interest expense		91			-		-		$	91
Other income		(19	)		36		180		$	197
Interest income		-					5		$	5
Segment operating income	$	(474	)	$	333	$	(638	)	$	(779	)
Assets	$	10,621		$	445	$	1,208		$	12,274
Year ended December 31, 2013	Oil and Gas Operations			Retirement Facility		Corporate			Total
Operating revenue	$	1,477		$	2,745	$	-		$	4,222
Operating expenses		1,213			2,436		498		$	4,147
Depreciation, depletion and amortization		654			61		2		$	717
Impairment of oil and gas properties		200			-		-		$	200
Total Operating Expenses		2,067			2,497		500			5,064
Interest expense		114			-		-		$	114
Other income		29			-		1,344		$	1,373
Interest income		-					9			9
Segment operating income	$	(675	)	$	248	$	853		$	426
Assets	$	11,859		$	842	$	607		$	13,308
Year ended December 31, 2012	Oil and Gas Operations			Retirement Facility		Corporate			Total
Operating revenue	$	1,182		$	2,762	$	-		$	3,944
Operating expenses		1,130			2,339		575			4,044
Depreciation, Depletion and Amortization		690			50		2			742
Accretion of Asset Retirement Obligation		68			-		-			68
Impairment of oil and gas properties		912			-					912
Total Operating Expenses		2,800			2,389		577			5,766
Interest expense		-			-		(208	)		(208	)
Other income		-			-		2,198			2,198
Segment operating income	$	(1,618	)	$	373	$	1,413		$	168
Assets	$	11,199		$	611	$	674		$	12,484

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NOTE M - QUARTERLY DATA (UNAUDITED)

The table below reflects the Company’s selected quarterly information for the years ended December 31, 2014, 2013 and 2010.  Amounts shown are in thousands except per share amounts.

	First			Second			Third			Fourth
Year ended December 31, 2014	Quarter			Quarter			Quarter			Quarter
Revenue	$	1,069		$	1,213		$	1,131		$	950
Operating (expense)		(1,119	)		(1,053	)		(1,087	)		(1,171	)
Corporate general and administrative expense		(192	)		(205	)		(208	)		(218	)
Impairment of natural gas and oil properties		-						-			-
Other income (expense) net		202			(54	)		(40	)		3
Net income (loss) from continuing operations		(40	)		(99	)		(204	)		(436	)
Income (loss) allocable to common shareholders	$	(40	)	$	(99	)	$	(204	)		(436	)
Income (loss) per common share – basic	$	(0.02	)	$	(0.05	)	$	(0.10	)	$	(0.23	)
	First			Second			Third			Fourth
Year ended December 31, 2013	Quarter			Quarter			Quarter			Quarter
Revenue	$	1,020		$	1,050		$	1,018		$	1,134
Operating (expense)		(1,078	)		(1,112	)		(1,102	)		(1,072	)
Corporate general and administrative expense		(173	)		(170	)		(170	)		(129	)
Impairment of natural gas and oil properties											(200	)
Other income (expense) net		262			370			387			391
Net income (loss) from continuing operations		31			138			133			124
Income (loss) allocable to common shareholders	$	31		$	138		$	133		$	124
Income (loss) per common share – basic	$	0.02		$	0.07		$	0.07		$	0.06
	First			Second			Third			Fourth
Year ended December 31, 2012	Quarter			Quarter			Quarter			Quarter
Revenue	$	964		$	988		$	976		$	1,016
Operating (expense)		(1,102	)		(1,071	)		(1,022	)		(1,082	)
Corporate general and administrative expense		(159	)		(134	)		(108	)		(176	)
Impairment of natural gas and oil properties		(912	)		-			-			-
Other income (expense) net		(58	)		48			1,674			534
Net income (loss) from continuing operations		(1,267	)		(169	)		1,520			84
Income (loss) allocable to common shareholders	$	(1,267	)	$	(169	)	$	1,520		$	84
Income (loss) per common share – basic	$	(0.65	)	$	(0.08	)	$	0.78		$	0.04

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NOTE N - 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:

	2014
	Gas (MMCF)			Oil (MBBLS)
Proved developed and undeveloped reserves -
January 1, 2014		2,887			173
Purchase of oil and natural gas properties in place		0			0
Discoveries and exclusions		0			0
Revisions		138			(24	)
Sales of oil and gas properties in place		0			0
Production		(159	)		(10	)
December 31, 2014		2,866			139
Proved developed at  beginning of year		719			105
Proved developed reserves at end of year		698			70
	2013
	Gas (MMCF)			Oil (MBBLS)
Proved developed and undeveloped reserves -
January 1, 2013		2,849			103
Purchase of oil and natural gas properties in place		0			0
Discoveries and exclusions		0			0
Revisions		232			82
Sales of oil and gas properties in place		0			0
Production		(194	)		(12	)
December 31, 2013		2,887			173
Proved developed at  beginning of year		593			35
Proved developed reserves at end of year		719			105

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

	Gas			Oil
	(MMCF)			(MBBLS)
Proved undeveloped reserves as of December 31, 2012		2,256			68
Revaluation of undeveloped reserves		-			-
Conversion to prove developed reserves		(88	)		-
Proved undeveloped reserves as of December 31, 2013		2,168			68
Conversion to prove developed reserves		-			-
Revaluation of undeveloped reserves		-			-
Proved undeveloped reserves as of December 31, 2014		2,168			68

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

	2014			2013
Property acquisition costs:
Proved properties	$	11,496		$	11,328
Unproved properties		-			-
Accumulated depreciation, depletion and amortization
and valuation allowance		(2,178	)		(2,178	)
Net capitalized costs	$	8,809		$	9,190

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

	2014		2013
Property acquisition costs:
Proved properties	$	-	$	-
Unproved properties		-		-
Exploration costs		-		-
Development costs		129		240
Total cost incurred	$	129	$	240

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

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	2014			2013
Oil and gas sales	$	1,489		$	1,477
Operating expenses		(1,233	)		(1213	)
Depreciation, depletion and amortization		(620	)		(654	)
Impairment of oil & gas properties		-			(200	)
Results of operations	$	(364	)	$	(590	)

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

	2014			2013
Future oil and gas cash inflows	$	25,595		$	30,060
Future oil & gas operating expenses		(4,170	)		(5,445	)
Future development costs		(2,983	)		(3,350	)
Future tax expense		(1,666	)		(1,257	)
Future net cash flows	$	16,776		$	20,008
10% discount to reflect timing of cash flows		(5,998	)		(7,787	)
	$	10,778		$	12,221

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NOTE O – ASSET RETIREMENT OBLIGATION

The Company records an asset retirement obligation (ARO) when the total depth of a drilled well is reached and the Company can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs.  The Company records the ARO liability on the consolidated balance sheets and capitalizes a portion of the cost in “Oil and natural gas properties” during the period in which the obligation is incurred.  In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date and adjusted for the Company’s credit risk.  This amount is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for the Company.  After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds.  The additional capitalized costs are depreciated on a unit-of-production basis or straight-line basis.

In the third quarter of 2012, the Company re-evaluated its method of plugging abandoned wells and determined by doing so in-house it could lower the cost. Based upon the Company’s current calculations, we have established a sufficient reserve, for accounting purposes, to plug the existing wells when necessary.

	2014		2013
Asset retirement obligation, January 1	$	2,770	$	2,770
Acquisition of oil and gas properties		-		-
Revisions in the estimated cash flows		-		-
Liability incurred upon acquiring and drilling wells		-		-
Liability settled upon plugging and abandoning wells		-		-
Accretion of discounnt expense		-		-
Asset retirement obligation, December 31	$	2,770	$	2,770

NOTE P –SUBSEQUENT EVENTS

The Company has evaluated subsequent events through March 31, 2015, the date the financial statements were available to be issued, and has determined that there are none to be reported. 

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The following documents are filed as exhibits (or are incorporated by reference as indicated) into this Report:

Exhibit Designation	Exhibit Description
3.1	Articles of Incorporation of Medical Resource Companies of America (incorporated by reference to Exhibit 3.1 to Registrant’s Form S-4 Registration Statement No. 333-55968 dated December 21, 1992)
3.2	Amendment to the Articles of Incorporation of Medical Resource Companies of America (incorporated by reference to Exhibit 3.5 to Registrant’s Form 8-K dated April 1, 1993)

3.3	Restated Articles of Incorporation of Greenbriar Corporation (incorporated by reference to Exhibit 3.1.1 to Registrant’s Form 10-K dated December 31, 1995)
3.4	Amendment to the Articles of Incorporation of Medical Resource Companies of America (incorporated by reference to Exhibit to Registrant’s PRES 14-C dated February 27, 1996)
3.5	Certificate of Decrease in Authorized and Issued Shares effective November 30, 2001 (incorporated by reference to Exhibit 2.1.7 to Registrant’s Form 10-K dated December 31, 2002)
3.6	Certificate of Designations, Preferences and Rights of Preferred Stock dated May 7, 1993 relating to Registrant’s Series B Preferred Stock (incorporated by reference to Exhibit 4.1.2 to Registrant’s Form S-3 Registration Statement No. 333-64840 dated June 22, 1993)
3.7	Certificate of Voting Powers, Designations, Preferences and Rights of Registrant’s Series F Senior Convertible Preferred Stock dated December 31, 1997 (incorporated by reference to Exhibit 2.2.2 of Registrant’s Form 10-KSB for the fiscal year ended December 31, 1997)
3.8	Certificate of Voting Powers, Designations, Preferences and Rights of Registrant’s Series G Senior Non-Voting Convertible Preferred Stock dated December 31, 1997 (incorporated by reference to Exhibit 2.2.3 of Registrant’s Form 10-KSB for the fiscal year ended December 31, 1997)
3.9	Certificate of Designations dated October 12, 2004 as filed with the Secretary of State of Nevada on October 13, 2004 (incorporated by reference to Exhibit 3.4 of Registrant’s Current Report on Form 8-K for event occurring October 12, 2004)
3.10	Certificate of Amendment to Articles of Incorporation effective February 8, 2005 (incorporated by reference to Exhibit 3.5 of Registrant’s Current Report on Form 8-K for event occurring February 8, 2005)
3.11	Certificate of Amendment to Articles of Incorporation effective March 21, 2007 (incorporated by reference to Exhibit 3.13 of Registrant’s Current Report on Form 8-K for event occurring March 21, 2005)
3.12	Amended and restated bylaws of New Concept Energy, Inc. dated November 18, 2008.
10.1	Registrant’s 1997 Stock Option Plan (filed as Exhibit 4.1 to Registrant’s Form S-8 Registration Statement, Registration No. 333-33985 and incorporated herein by this reference).
10.2	Registrant’s 2000 Stock Option Plan (filed as Exhibit 4.1 to Registrant’s Form S-8 Registration Statement, Registration No. 333-50868 and incorporated herein by this reference)
14.0	Code of Ethics for Senior Financial Officers (incorporated by reference to Exhibit 14.0 to Registrant’s Annual Report on Form 10-K for the fiscal year ended December 31, 2003)
21.1*	Subsidiaries of the Registrant
31.1*	Rule 13a-14(a) Certification by Principal Executive Officer and Chief Financial Officer
32.1*	Certification of Principal Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1*	Reserve Study dated March 16, 2015 prepared by Lee Keeling and Associates, Inc is included as an exhibit
99.2	Shared Services Agreement effective December 31, 2010 (incorporated by reference to Exhibit 99.2 to Registrants Form 10K/A for the year ended December 31, 2011 filed March 21, 2013)
101	Interactive data files pursuant to Rule 405 of Regulation S-T

45

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	NEW CONCEPT ENERGY, INC.
March 31, 2015	by:      /s/ Gene S. Bertcher
	Gene S. Bertcher, Principal Executive
	Officer, President and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Gene S. Bertcher Gene S. Bertcher	Chairman, President, Principal Executive Officer, Chief Financial Officer and Director	March 31, 2015
/s/ Roz Campisi Beadle Roz Campisi Beadle	Director	March 31, 2015
/s/ James Huffstickler James Huffstickler	Director	March 31, 2015
/s/ Dan Locklear Dan Locklear	Director	March 31, 2015
/s/ Victor L. Lund Victor L. Lund	Director	March 31, 2015

46

EX-21.1

EXHIBIT 21.1

SUBSIDIARIES OF REGISTRANT

	State or
Entity Name	County	% Owned
Cardinal Oil & Gas, Inc.	Nevada	100%
King City Retirement Corporation	Oregon	100%
Mockingbird Energy, LLC	Nevada	100%
Mountaineer State Energy, Inc.	West Virginia	100%
Mountaineer State Operations, LLC	Nevada	100%
DeSoto Development, LLC	Nevada	100%

EX-31.1

CERTIFICATIONS EXHIBIT 31.1

PRINCIPAL EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER’S RULE 13a-14(a)/15d-14(a)

I, Gene S. Bertcher, certify that:

1)           I have reviewed this annual report of Form 10-K of New Concept Energy, Inc.;

2)           Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made in light of the circumstances under which such statements were made, and is not misleading with respect to the period covered by this report;

3)           Based on my knowledge, the financial statements and other financial information included in this report fairly present, in all material respects, the financial condition, results of operations and cash flows of the Registrant as of and for the periods presented in this report;

4)           I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13-15(e) and 15(d)-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15(d)-15(f)) for the Registrant and have:

(a)           Designed such disclosure controls and procedures, or used such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

(b)           Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principals;

(c)           Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the controls and procedures as of the end of the period covered by this report based on such evaluation; and

(d)           Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting.

5)           I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of Registrant’s board of directors (or persons performing the equivalent functions):

(a)           All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and

(b)           Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal controls.

Dated: March 31, 2015  /s/ Gene S. Bertcher Gene S. Bertcher, Principal Executive Officer, President and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. § 1350, AS ADOPTED

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of New Concept Energy, Inc. (the “Company”) of Form 10-K for the period ended December 31, 2014, as filed with the Securities Exchange Commission on the date hereof (the “Report”), I, Gene S. Bertcher, President and Chief Financial Officer of the Company, do hereby certify pursuant to 18 U.S.C. §1350 that:

(i)           The Report fully complies with the requirements of Section 13(a) or I 5(d) of the Securities Exchange Act of 1934, as amended; and

(ii)           The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company, at the end of the period indicated and for the periods indicated.

Dated:     March 31, 2015

/s/ Gene S. Bertcher

Gene S. Bertcher, Principal Executive

Officer, President and Chief Financial

Officer

EX-99.1

XML

Aggregate annual principal maturities of long-term debt at December 31, 2014 are as follows (in thousands): (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014
Aggregate annual principal maturities of long-term debt
Annual principal maturities 2014	$ 881
Annual principal maturities 2015	263
Annual principal maturities 2016	261
Annual principal maturities 2017	256
Annual principal maturities 2018	107
Annual principal maturities Thereafter	541
Total Annual principal maturities	$ 2,309

XML

Asset retirement obligation (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Asset retirement obligations
Asset retirement obligation, January 1	$ 2,770	$ 2,770
Acquisition of oil and gas properties	0	0
Revisions in the estimated cash flows	0	0
Liability incurred upon acquiring and drilling wells	0	0
Liability settled upon plugging and abandoning wells	0	0
Accretion of discount expense	0	0
Asset retirement obligation, December 31	$ 2,770	$ 2,770

XML

OTHER INCOME (EXPENSE) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
OTHER INCOME EXPENSE
Litigation costs for the Chesapeake matter		$ (382)
Income for gas held by Chesapeake		200
Other	197	(7)	122
Other income total	$ 197	$ (189)	$ 122

XML

Schedule of information on Oil and Gas Industries (Tables)

12 Months Ended

Dec. 31, 2014

Schedule of information on Oil and Gas Industries (Tables)

Schedule of Oil and Gas In Process Activities

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:

	2014
	Gas (MMCF)			Oil (MBBLS)
Proved developed and undeveloped reserves -
January 1, 2014		2,887			173
Purchase of oil and natural gas properties in place		0			0
Discoveries and exclusions		0			0
Revisions		148			(24	)
Sales of oil and gas properties in place		0			0
Production		(169	)		(10	)
December 31, 2014		2,866			139
Proved developed at  beginning of year		719			105
Proved developed reserves at end of year		698			70
	2013
	Gas (MMCF)			Oil (MBBLS)
Proved developed and undeveloped reserves -
January 1, 2013		2,849			103
Purchase of oil and natural gas properties in place		0			0
Discoveries and exclusions		0			0
Revisions		232			82
Sales of oil and gas properties in place		0			0
Production		(194	)		(12	)
December 31, 2013		2,887			173
Proved developed at  beginning of year		593			35
Proved developed reserves at end of year		719			105

Schedule of changes in total proved undeveloped reserves Table Text Block

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

	Gas			Oil
	(MMCF)			(MBBLS)
Proved undeveloped reserves as of December 31, 2012		2,256			68
Revaluation of undeveloped reserves		-			-
Conversion to prove developed reserves		(88	)		-
Proved undeveloped reserves as of December 31, 2013		2,168			68
Conversion to prove developed reserves		-			-
Revaluation of undeveloped reserves		-			-
Proved undeveloped reserves as of December 31, 2014		2,168			68

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

	2014			2013
Property acquisition costs:
Proved properties	$	11,496		$	11,328
Unproved properties		-			-
Accumulated depreciation, depletion and amortization
and valuation allowance		(2,687	)		(2,178	)
Net capitalized costs	$	8,809		$	9,190

Schedule of the capitalized costs relating to oil and gas producing activitiesTable Text Block

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

	2014			2013
Property acquisition costs:
Proved properties	$	11,496		$	11,328
Unproved properties		-			-
Accumulated depreciation, depletion and amortization
and valuation allowance		(2,678	)		(2,178	)
Net capitalized costs	$	8,809		$	9,190

Schedule of the costs incurred in oil and gas property acquisition, exploration and development activities.Table Text Block

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

	2014		2013
Property acquisition costs:
Proved properties	$	-	$	-
Unproved properties		-		-
Exploration costs		-		-
Development costs		129		240
Total cost incurred	$	129	$	240

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities

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.

	2014			2013
Oil and gas sales	$	1,489		$	1,477
Operating expenses		(1,233	)		(1213	)
Depreciation, depletion and amortization		(620	)		(654	)
Impairment of oil & gas properties		-			(200	)
Results of operations	$	(364	)	$	(590	)

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

	2014			2013
Future oil and gas cash inflows	$	25,595		$	30,060
Future oil & gas operating expenses		(4,170	)		(5,445	)
Future development costs		(2,983	)		(3,350	)
Future tax expense		(1,666	)		(1,257	)
Future net cash flows	$	16,776		$	20,008
10% discount to reflect timing of cash flows		(5,998	)		(7,787	)
	$	10,778		$	12,221

XML

Schedule of Aggregate annual principal maturities of long-term debt (Tables)

12 Months Ended

Dec. 31, 2014

Schedule of Aggregate annual principal maturities of long-term debt

Schedule of Aggregate annual principal maturities of long-term debt Table Text Block

Aggregate annual principal maturities of long-term debt at December 31, 2014 are as follows (in thousands):

2014		881
2015		263
2016		261
2017		256
2018		107
Thereafter		541
	$	2,309

XML

Company's effective Income tax rate (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Company's effective Income tax rate
Federal income tax at statutory rate per books	$ 0	$ 149	$ 59
Change in valuation allowance	0	0	0
Net operating loss	$ 0	$ (149)	$ (59)
Federal income tax per tax return	0.00%	0.00%	0.00%
Effective income tax rate	0.00%	0.00%	0.00%

XML

Related party transactions (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2010	Dec. 31, 2009	Mar. 21, 2009	Nov. 20, 2007	Jul. 01, 2007	Jul. 01, 2006
Related party transactions
Company made an unsecured loan to ERC in millions							$ 1.4	$ 1,400,000
Annual interest rate of unsecured loan to ERC							8.00%	8.00%
Balance of the two notes and accrued interest (rate of interest 2%)					3,970,897
Company made a loan to PIAMI						630,000
Company made additional net advances on the loan to PIAMI in millions		360,000				6,300,000
Balance due including accrued interest PIAMI in millions				11,100,000
Outstanding principal and interest in millions			10,400,000
Payments from PIAMI		715,000
The Company and several other defendants settled a lawsuit	225,000
Paid the entire amount and has a note receivable from one of the other defendants	112,500
The company has recorded a reserve of $million (the full balance) for the combined note.		10,000,000
Company paid to a consultant and was reimbursed by Arcadian for a portion of his services.	48,800
Company incurred obligations to Pillar totaling to which was reduced by Prime by a like amount approximately $ million	1,600,000
Company incurred obligations to Pillar totaling approximately $ million		2,100,000
Pillar agreed to relieve the Company of its obligation to pay $ million		2,100,000
Company recorded a gain on the transaction $ million		2,100,000
Pillar incurred expenses on behalf of the Company and agreed to forego payment in exchange for a reduction in the PIAMI obligation		$ 715,000

XML

Contingencies and litigations (Details) (USD $)	Dec. 31, 2014	Feb. 14, 2012	Mar. 31, 2011	Dec. 31, 2009	Jan. 31, 2006
Contingencies and litigations
Acutal damages found by jury in millions				$ 66,500,000
Actual damages in tortous interference claim millions				31,120,000
Exemplary damages and individual and Eurenergy millions				8,500,000
reinstated the jury award of actual damages jointly and severely against The individual and EurEnergy millions		66,500,000
Received an invoice from Chesapeake					556,217
Chesapeake received a summary judgment award			686,874
Further the judgment awarded Chesapeake additional legal fees of (Total legal fee awarded)			30,000
Company arranged for a bond to the benefit of Chesapeake from a third party bonding Company for payment of the amount			791,960
Company has appealed the judgment to the Court of Appeals which reduced the judgment	22,000
Chesapeake received a summary judgment including prejudgment interest			$ 65,000

XML

RECEIVABLES, PAYABLES RELATED PARTIES

12 Months Ended

Dec. 31, 2014

RECEIVABLES, PAYABLES RELATED PARTIES

RECEIVABLES, PAYABLES RELATED PARTIES

NOTE C – RECEIVABLES – PAYABLES – RELATED PARTIES

Prime Income Asset Management, Inc.

Prime Income Asset Management, Inc. (“PIAMI”) is a real estate management company that also invests in real estate for its own account. Pillar Income Asset Management, Inc. (“Pillar”) is a real estate management company. Both PIAMI and Pillar are indirectly owned by a private trust. URC Energy Inc. (“URC”) is and has been a significant investor in the Company. URC is indirectly owned by a private trust  While the trusts for PIAMI and Pillar and URC are separate they have similar trustees and beneficiaries and therefore the Company has noted PIAMI and Pillar as related parties. Eurenergy Resources, Inc. (“ERC”) is an oil & gas company that owned and operated oil and gas wells.

Beginning in 2006 the Company made loans to PIAMI and ERC at interest rates higher than the Company believes it could have gotten elsewhere.  On May 21, 2009, PIAMI acquired both Eurenergy notes receivable at face value plus accrued interest totaling $3,970,897. Effective May 21, 2009 the Company and PIAMI entered into a new note combing all of the above loans into one note. The loan calls for interest at the prime rate plus 2% with principal and interest payable within 30 days after demand, and if not sooner demanded, on January 31, 2013.

At December 31, 2009, the balance due including accrued interest on the note receivable from PIAMI was $11.1 million. During 2010 the note was paid down whereby as of December 31, 2010 the outstanding principal and interest totaled $10.4 million.  During the first three quarters of 2011 the Company accrued interest of $360,000 and received $715,000 in payments from PIAMI. In the fourth quarter of 2011 the Company determined that the financial condition of PIAMI had deteriorated and there could be no assurance that the amount owed would or could be collected. The company has recorded a reserve of $10 million (the full balance) for the combined note.

Beginning in 2011, the Company conducted business with Pillar whereby Pillar provided the Company with services including processing payroll, acquiring insurance and other administrative matters (rent). The Company believes that by purchasing these services through certain large entities it can get lower costs and better service. Pillar does not charge the Company a fee for providing these services.

While separate companies, both PIAMI and Pillar are both owned by Realty Advisors, Inc. (“RAI”).  During 2011 and 2012, the Company incurred obligations to Pillar totaling approximately $2.1 million. In a joint agreement among Pillar, PIAMI and the Company, Pillar agreed to relieve the Company of its obligation to pay $2.1 million and the Company agreed to reduce the amount owed by Prime by a like amount. In 2012 the Company recorded a $2.1 million recovery on the transaction reduction in the PIAMI obligation.

During 2013, the Company incurred obligations to Pillar totaling approximately $1.6 million. In a joint agreement among Pillar, PIAMI and the Company, Pillar agreed to relieve the Company of its obligation to pay $1.6 million and the Company agreed to reduce the amount owed by Prime by a like amount.

Coastland Operations, LLC

During 2012, the Company and several other defendants settled a lawsuit for $225,000. The Company paid the entire amount and has a note receivable from one of the other defendants, Coastland Operations, LLC (a subsidiary of Arcadian Energy, Inc) for $112,500 representing its share of the settlement Arcadian for a portion of his services. Arcadian, through its subsidiary URC is a significant shareholder of the Company and is therefore considered a related party. In March 2015 the $112,500 plus all accrued interest thereon was paid to the Company.

XML

Income tax (details) (USD $)	Dec. 31, 2014
Net operating loss carry forward Details
Net operating loss carry forward	$ 7,400,000

XML

Schedule of Preferred Stock (Tables)

12 Months Ended

Dec. 31, 2014

Schedule of Preferred Stock (Tables):

Schedule of Preferred stock (Tables)

Preferred stock consists of the following (amounts in thousands):

	Year Ended
	December 31,
	2014		2013
Series B convertible preferred stock, $10 par value, liquidation value of $100, authorized 100 shares, issued and outstanding one share		1		1

XML

Schedule of effective tax rate (Tables)

12 Months Ended

Dec. 31, 2014

Schedule of effective tax rate (Tables):

Schedule of effective tax rate (Tables)

The following table presents the principal reasons for the difference between the Company's effective tax rate and the United States statutory income tax rate.

	2014			2013			2012
Federal income tax at statutory rate per books	$	0		$	149		$	59
Change in valuation allowance		0			0			0
Net operating loss		0			(149	)		(59	)
Federal income tax per tax return	$	0		$	0		$	0
Effective income tax rate		0.00	%		0.00	%		0.00	%

XML

Preferred stock consists of the following (Details) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Preferred stock consists of the following
Series B convertible preferred stock, $10 par value, liquidation value of $100, authorized 100 shares, issued and outstanding one share	1	1

XML

SCHEDULE OF OTHER INCOME (EXPENSE) (Tables)

12 Months Ended

Dec. 31, 2014

SCHEDULE OF OTHER INCOME (EXPENSE

SCHEDULE OF OTHER INCOME (EXPENSE) TABLE TEXT BLOCK

Other income (expense) consists of the following: (amounts in thousands)

	Year ended December 31,
	2014		2013			2012
Litigation costs for the Chesapeake matter	$	-		(382	)		-
Income for gas held by Chesapeake		-		200			-
Other		197		(7	)		122
	$	197	$	(189	)	$	122

XML

Schedule of Segment Reporting (Tables)

12 Months Ended

Dec. 31, 2014

Schedule of Segment Reporting (Tables):

Schedule of Segment Reporting Information, by Segment

The following table reconciles the segment information to the corresponding amounts in the Consolidated Statements of Operations and total assets:

Year ended December 31, 2014	Oil and Gas Operations			Retirement Facility		Corporate			Total
Operating revenue	$	1,489		$	2,874	$	-		$	4,363
Operating expenses		1,233			2,512		823		$	4,568
Depreciation, depletion and amortization		620			65		-		$	685
Impairment of oil and gas properties		-			-		-		$	-
Total Operating Expenses		1,853			2,577		823			5,253
Interest expense		91			-		-		$	91
Other income		(19	)		36		180		$	197
Interest income		-					5		$	5
Segment operating income	$	(474	)	$	333	$	(638	)	$	(779	)
Assets	$	10,621		$	445	$	1,208		$	12,274
Year ended December 31, 2013	Oil and Gas Operations			Retirement Facility		Corporate			Total
Operating revenue	$	1,477		$	2,745	$	-		$	4,222
Operating expenses		1,213			2,436		498		$	4,147
Depreciation, depletion and amortization		654			61		2		$	717
Impairment of oil and gas properties		200			-		-		$	200
Total Operating Expenses		2,067			2,497		500			5,064
Interest expense		114			-		-		$	114
Other income		29			-		1,344		$	1,373
Interest income		-					9			9
Segment operating income	$	(675	)	$	248	$	853		$	426
Assets	$	11,859		$	842	$	607		$	13,308
Year ended December 31, 2012	Oil and Gas Operations			Retirement Facility		Corporate			Total
Operating revenue	$	1,182		$	2,762	$	-		$	3,944
Operating expenses		1,130			2,339		575			4,044
Depreciation, Depletion and Amortization		690			50		2			742
Accretion of Asset Retirement Obligation		68			-		-			68
Impairment of oil and gas properties		912			-					912
Total Operating Expenses		2,800			2,389		577			5,766
Interest expense		-			-		(208	)		(208	)
Other income		-			-		2,198			2,198
Segment operating income	$	(1,618	)	$	373	$	1,413		$	168
Assets	$	11,199		$	611	$	674		$	12,484

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2014

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NOTE B - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Principles of Consolidation

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

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, which is included in operations, was $176,000, $188,000 and $165,000 for 2014, 2013 and 2012, respectively.

Depreciation, Depletion and Amortization of Producing Oil & Gas Properties

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.

The Company recorded depletion of mineral rights of $510,000, $650,000 and $614,000 in 2014, 2013 and 2012 respectively.

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 sells most of its natural gas production to one purchaser and all of its oil production to one purchaser.  While there is an available market for crude oil and natural gas production, we cannot be assured that the loss of this purchaser would not have a material impact on the Company.

Oil and Gas Reserves

Our 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 recent prices of the evaluation, estimated reserve quantities can be significantly impacted by changes in product prices.

The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission.  Such assumptions include using recent oil and gas prices and year-end costs for estimated future development and production expenditures.  Discounted future net cash flows are calculated using a 10% rate.  Changes in any of these assumptions could have a significant impact on the standardized measure.  Accordingly, the standardized measure does not represent management’s estimated current market value of proved reserves. At December 31, 2014, 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, 2014.

Full cost accounting

The Company uses the full cost method of accounting for its investment in oil and natural gas properties.  Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas properties (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred.

The full cost method requires the Company to calculate quarterly, by cost center, a “ceiling,” or limitation on the amount of properties that can be capitalized on the balance sheet.  To the extent capitalized costs of oil and natural gas properties, less accumulated depletion and related deferred taxes exceed the sum of the discounted future net revenues of proved oil and natural gas reserves, the lower of cost or estimated fair value of unproved properties subject to amortization, the cost of properties not being amortized, and the related tax amounts, such excess capitalized costs are charged to expense.  Beginning December 31, 2009, full cost companies use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date to calculate the future net revenues of 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 any unproved oil and gas properties on an annual basis for possible impairment or reduction in value.  The Company assesses properties on an individual basis or as a group if properties are individually insignificant.  The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned.  During any period in which these factors indicate an impairment of unproved properties not subject to amortization, the associated costs incurred to date for such properties are then included in unproved properties subject to amortization.

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, 2014 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. The Company includes royalties in its revenues and cost of revenues when settlement of the royalties is paid in cash, while royalties settled by the delivery of volumes are excluded from revenues and cost of revenues.

The Company follows the sales method of accounting for natural gas production imbalances and would recognize a liability if the existing 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 consolidated financial statements and revenues and expenses during the reporting period.  Actual results could differ from those estimates.

Cash Equivalents

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

Other Intangible Assets

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

Impairment of Notes Receivable

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

Impairment of Long-Lived Assets

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

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

Sales of Real Estate

Gains on sales of real estate are recognized to the extent permitted by Accounting Standards Codification Topic 360-20, “Real Estate Sales – Real Estate Sales”, (“ASC 360-20”).  Until the requirements of ASC 360-20 have been met for full profit recognition, sales are accounted for by the installment or cost recovery method, whichever is appropriate.

Real Estate Held for Sale

Accounting Standards Codification Topic 360, “Property, Plant, & Equipment” (“ASC 360”)requires that properties held for sale be reported at the lower of carrying amount or fair value less costs of sale.  If a reduction in a held for sale property’s carrying amount to fair value less costs of sale is required, a provision for loss is recognized by a charge against earnings.  Subsequent revisions, either upward or downward, to a held for sale property’s estimated fair value less costs of sale are recorded as an adjustment to the property’s carrying amount, but not in excess of the property’s carrying amount when originally classified as held for sale.  A corresponding charge against or credit to earnings is recognized.  Properties held for sale are not depreciated.

Asset Retirement Obligation

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

Income Taxes

The Company accounts for income taxes in accordance with Accounting Standards Codification, (“ASC”) No. 740, “Accounting for Income Taxes”. ASC 740 requires an asset and liability approach to financial accounting for income taxes. In the event differences between the financial reporting basis and the tax basis of the Company’s assets and liabilities result in deferred tax assets, ASC 740 requires an evaluation of the probability of being able to realize the future benefits indicated by such assets. A valuation allowance is provided for a portion or all of the deferred tax assets when there is an uncertainty regarding the Company’s ability to recognize the benefits of the assets in future years.  Recognition of the benefits of deferred tax assets will require the Company to generate future taxable income.  There is no assurance that the Company will generate earnings in future years.  Since management could not determine the likelihood that the benefit of the deferred tax asset would be realized, no deferred tax asset was recognized by the Company.

Recent Accounting Pronouncements

There were no recent accounting pronouncements that our Company has not implemented that materially affect our consolidated financial statements.

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Schedule of Quarterly Financial Information (Tables)

12 Months Ended

Dec. 31, 2014

Schedule of Quarterly Financial Information (Tables):

Schedule of Quarterly Financial Information

The table below reflects the Company’s selected quarterly information for the years ended December 31, 2014, 2013 and 2010.  Amounts shown are in thousands except per share amounts.

	First			Second			Third			Fourth
Year ended December 31, 2014	Quarter			Quarter			Quarter			Quarter
Revenue	$	1,069		$	1,213		$	1,131		$	950
Operating (expense)		(1,119	)		(1,053	)		(1,087	)		(1,171	)
Corporate general and administrative expense		(192	)		(205	)		(208	)		(218	)
Impairment of natural gas and oil properties		-						-			-
Other income (expense) net		202			(54	)		(40	)		3
Net income (loss) from continuing operations		(40	)		(99	)		(204	)		(436	)
Income (loss) allocable to common shareholders	$	(40	)	$	(99	)	$	(204	)		(436	)
Income (loss) per common share – basic	$	(0.02	)	$	(0.05	)	$	(0.10	)	$	(0.23	)
	First			Second			Third			Fourth
Year ended December 31, 2013	Quarter			Quarter			Quarter			Quarter
Revenue	$	1,020		$	1,050		$	1,018		$	1,134
Operating (expense)		(1,078	)		(1,112	)		(1,102	)		(1,072	)
Corporate general and administrative expense		(173	)		(170	)		(170	)		(129	)
Impairment of natural gas and oil properties											(200	)
Other income (expense) net		262			370			387			391
Net income (loss) from continuing operations		31			138			133			124
Income (loss) allocable to common shareholders	$	31		$	138		$	133		$	124
Income (loss) per common share – basic	$	0.02		$	0.07		$	0.07		$	0.06
	First			Second			Third			Fourth
Year ended December 31, 2012	Quarter			Quarter			Quarter			Quarter
Revenue	$	964		$	988		$	976		$	1,016
Operating (expense)		(1,102	)		(1,071	)		(1,022	)		(1,082	)
Corporate general and administrative expense		(159	)		(134	)		(108	)		(176	)
Impairment of natural gas and oil properties		(912	)		-			-			-
Other income (expense) net		(58	)		48			1,674			534
Net income (loss) from continuing operations		(1,267	)		(169	)		1,520			84
Income (loss) allocable to common shareholders	$	(1,267	)	$	(169	)	$	1,520		$	84
Income (loss) per common share – basic	$	(0.65	)	$	(0.08	)	$	0.78		$	0.04

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Operating leases (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating leases Future Minimum Payments
Lease expensesincurred	$ 961,000	$ 942,000	$ 924,000
Primary lease Minimum payments 2015	980
Primary lease Minimum payments 2016	1,000
Primary lease Minimum payments 2017	83
Primary lease Minimum payments total	$ 2,063

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current assets
Cash and cash equivalents	$ 300	$ 1,621
Accounts receivable from oil and gas sales	216	195
Other current assets	182	203
Total current assets	698	2,019
Oil and natural gas properties (full cost accounting method)
Proved developed and undeveloped oil and gas properties, net of depletion	8,809	9,190
Property and equipment, net of depreciation
Land, buildings and equipment - oil and gas operations	1,476	1,442
Other	162	183
Total property and equipment	1,638	1,625
Other assets (including $126,000 and $122,000 in 2014 and 2013 due from related parties)	1,129	474
Total assets	12,274	13,308
Current liabilities
Accounts payable - trade (including $494 in 2014 due to related parties)	673	121
Accrued expenses	229	965
Current portion of long term debt	881	185
Total current liabilities	1,783	1,271
Long-term debt
Notes payable less current portion	1,428	2,195
Asset retirement obligation	2,770	2,770
Total liabilities	5,981	6,236
Stockholders' equity
Series B convertible preferred stock, $10 par value, liquidation value of $100 authorized 100 shares, issued and outstanding one share	1	1
Common stock, $.01 par value; authorized, 100,000,000 shares; issued and outstanding, 1,946,935 shares at December 31, 2014 and 2013	20	20
Additional paid-in capital	58,838	58,838
Accumulated deficit	(52,566)	(51,787)
Total Stockholders' equity	6,293	7,072
Total liabilities & stockholders' equity	$ 12,274	$ 13,308

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Series B preferred stock has a liquidation value (Details) (USD $)	Dec. 31, 2014
Series B preferred stock has a liquidation value
Series B preferred stock has a liquidation value per share	$ 100
Dividends at a rate	6.00%

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CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (USD $) In Thousands	Series B Preferred Stock Shares	Series B Preferred Stock Amount USD ($)	Common Stock Shares	Common Stock Amount USD ($)	Additional Paid-in Capital USD ($)	Accumulated deficit USD ($)	Total USD ($)
Balance at Dec. 31, 2011	1	1	1,947	20	58,838	(52,381)	6,478
Net Income		$ 0		$ 0	$ 0	$ 168	$ 168
Balance at Dec. 31, 2012	1	1	1,947	20	58,838	(52,213)	6,646
Net Income		0		0	0	426	426
Balance at Dec. 31, 2013	1	1	1,947	20	58,838	(51,787)	7,072
Net Income		$ 0		$ 0	$ 0	$ (779)	$ (779)
Balance at Dec. 31, 2014	1	1	1,947	20	58,838	(52,566)	6,293

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DESCRIPTION AND PRESENTATION (Details) (USD $)	Dec. 31, 2014	Feb. 28, 2014
DESCRIPTION AND PRESENTATION
Oil and gas wells of the company	152
Non-producing wells	31
Related equipment and mineral leases in acres	20,000
Estimates of future net revenues in millions	$ 10,800,000
Residents in retirement community	114
Company acquired 7.4 acres of undeveloped land in Desoto		$ 624,000

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SUBSEQUENT EVENTS

12 Months Ended

Dec. 31, 2014

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS

NOTE P –SUBSEQUENT EVENTS

The Company has evaluated subsequent events through March 31, 2015, the date the financial statements were available to be issued, and has determined that there are none to be reported. 

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SIGNIFICANT ACCOUNTING POLICIES - Depreciation (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Depreciation and amortization expense included in operations
Depreciation and amortization expense included in operations	$ 176,000	$ 188,000	$ 165,000
Depletion of mineral rights	$ 510,000	$ 650,000	$ 614,000

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Schedule of Notes-Payable (Tables)

12 Months Ended

Dec. 31, 2014

Schedule of Notes-Payable (Tables):

Schedule of Notes-Payable (Tables)

Notes payable is comprised of the following (in thousands):

	2014		2013
Notes payable from the acquisition of Mountaineer State Energy, Inc.	$	1,514	$	1,499
Bank Debt	$	795	$	881
	$	2,309	$	2,380

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BASIS OF PRESENTATION

12 Months Ended

Dec. 31, 2014

BASIS OF PRESENTATION:

BASIS OF PRESENTATION

NOTE A – BUSINESS DESCRIPTION AND PRESENTATION

The Company, through its wholly owned subsidiaries Mountaineer State Energy, Inc. and Mountaineer State Operations, LLC, operates oil and gas wells and mineral leases in Athens and Meigs Counties in Ohio and in Calhoun, Jackson and Roane Counties in West Virginia. As of December 31, 2014 the Company has 153 producing oil & gas wells, 31 non-producing wells and related equipment and mineral leases covering approximately 20,000 acres.

The Company engaged the firm of independent oil and gas engineers Lee Keeling & Associates, Inc. to estimate the net oil and gas reserves.  On the basis of their study, the estimates of future net revenues using a present value discount of 10% were estimated to be $10.8 million at December 31, 2014.

NCE also leases and operates a retirement community in King City Oregon, with a capacity of 114 residents.

In February 2014 the Company acquired 7.4 acres of undeveloped land in Desoto TX. For $624,000. The Company believes the highest and best use of this property is for the construction and development of multifamily housing. The Company acquired the property for investment purposes.  This investment is included in  other assets on the balance sheet.

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CONSOLIDATED BALANCE SHEETS PARENTHETICALS (USD $) In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
PARENTHETICALS
Other assets due from related parties	$ 126,000	$ 122,000
Accounts payable due from related parties	494	0
Series B Convertible Preferred stock,par value	$ 10	$ 10
Series B Convertible Preferred stock,shares Value	$ 100	$ 100
Series B Convertible Preferred stock,shares authorized	100	100
Series B Convertible Preferred stock,shares issued	1	1
Series B Convertible Preferred stock,shares outstanding	1	1
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	1,946,935	1,946,935
Common stock, shares outstanding	1,946,935	1,946,935

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CONTINGENCIES

12 Months Ended

Dec. 31, 2014

CONTINGENCIES

CONTINGENCIES

NOTE K – CONTINGENCIES

Carlton Energy Group, LLC

In December 2006, Carlton Energy Group, LLC (“Carlton”) instituted litigation against an individual, Eurenergy Resources Corporation (“Eurenergy”) and several other entities including New Concept Energy, Inc., which was then known as CabelTel International Corporation (the “Company”) alleging tortuous conduct, breach of contract and other matters and as to the Company that it was the alter ego of Eurenergy. The Carlton claims were based upon an alleged tortuous interference with a contract by the individual and Eurenergy related to the right to explore a coal bed methane concession in Bulgaria which had never (and has not to this day) produced any hydrocarbons. At no time during the pendency of this project or since did the company or any of its officers or directors have any interest whatsoever in the success or failure of the so-called “Bulgaria Project”. However, in the litigation, Carlton alleged that the Company was the alter-ego of certain of the other Defendants including Eurenergy.

Following a jury trial in 2009, the Trial Court (295th District Court of Harris County, Texas) reduced the actual damages found by the jury of $66.5 million and entered judgment against EurEnergy and the individual jointly and severally for $31.12 million in actual damages on its tortuous-interference claim and the Court further assessed exemplary damages against The individual and EurEnergy in the amount of $8.5 million each. The Court granted a judgment for the Company that it was not the alter ego of any of the other parties and thereby would not incur any damages.

Cross appeals were filed by Carlton, the individual and EurEnergy to the Court of Appeals for the First District of Texas (the “Court of Appeals”) which rendered its opinion on February 14, 2012.  The Court of Appeals opinion, among other things, reinstated the jury award of actual damages jointly and severely against the individual and EurEnergy in the amount of $66.5 million and overturned the Trial Court’s ruling favorable to the Company rendering a judgment for that amount plus exemplary damages against the Company as the “alter ego” of Eurenergy.

The Company and the other defendants, filed a Petition for Review of the Court of Appeals Opinion with the Supreme Court of the State of Texas. After requesting a response from the Plaintiff the Supreme Court requested full briefing on the merits. In March 2013 the Court granted the Petition for Review and in September 2013 the Court heard oral arguments. The parties are awaiting a ruling.

 The Company vigorously denies that it is the “alter ego” of any other entity; further the Company strongly believes that the Court of Appeals opinion is erroneous in concluding that the Company is an “alter ego” of any other entity which is contrary to Nevada substantive law. There are also questions regarding the underlying liability of EurEnergy and if Eurenergy is successful in its petition for review or, even if unsuccessful if the Company is successful on its positions described above, the Trial Court’s judgment could be reinstated and the Company would have no liability on this claim.

Chesapeake Exploration Limited Partnership and Chesapeake Operating, Inc. (“Chesapeake”)  In January 2006, the Company entered into a joint operating agreement evidencing its acquisition of a 5% interest in two gas wells being drilled and ultimately operated by Chesapeake.  The Company relied on the cost projections provided by Chesapeake to make its investment decision.  Subsequent to its investment, the Company received an invoice from Chesapeake for $556,217 which, according to Chesapeake, represents the Company’s 5% share of additional costs incurred by Chesapeake in drilling the wells.  The Company believes that these additional costs far exceed any reasonable expense that should have been incurred in drilling the two wells and were incurred without notifying the Company of such expenses.  The Company has requested an accounting of the additional expenses and a reconciliation of the final costs to the cost estimates previously presented.  In April 2007, Chesapeake filed a lawsuit against the Company and others in District Court of Tarrant County, Texas.

 In March 2011, Chesapeake received a summary judgment award including prejudgment interest for $686,874 plus $65,000 in legal fees. Further the judgment awarded Chesapeake additional legal fees of $30,000 should the Company file unsuccessful appeals to the Court of Appeals and the Texas Supreme Court. Chesapeake would also receive to post judgment interest.

The judgment did however acknowledge that the plaintiff did not pay the company for it’s pro rata share of the gas produced by the two wells during the entire period in question.

The Company has appealed the judgment to the Court of Appeals which reduced the judgment by $22,000, but otherwise affirmed the lower court ruling. The Company filed an appeal with the Texas Supreme Court, however on February 15, 2013 the Texas Supreme Court denied the petition.

Following the ruling in March 2011, the Company arranged for a bond to the benefit of Chesapeake from a third party bonding Company for approximately $791,960. In February 2014, the Company paid the bonding company $791,960, who in turn paid Chesapeake.

There still remains the matter of the gas that is owed to the Company for it’s pro rata share of the gas produced and withheld by Chesapeake. The Company has estimated that there is approximately 70,000 MCF of gas for which the Company needs to be paid or receive in kind which would then be sold. In 2013 Chesapeake sold the two wells to BHP Billiton Petroleum (“BHP”). In 2014 BHP has begun paying the Company for its oil and gas interests out of current monthly production.

Other

The Company has been named as a defendant in other lawsuits in the ordinary course of business.  Management is of the opinion that these lawsuits will not have a material effect on the financial condition, results of operations or cash flows of the Company.

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Mar. 27, 2015	Jun. 30, 2014
Document and Entity Information:
Entity Registrant Name	New Concept Energy, Inc.
Entity Trading Symbol	NCEI
Document Type	10-K
Document Period End Date	Dec. 31, 2014
Amendment Flag	false
Entity Central Index Key	0000105744
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		1,946,935
Entity Filer Category	Smaller Reporting Company
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	No
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Entity Public Float			$ 895,982

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OPERATING SEGMENTS

12 Months Ended

Dec. 31, 2014

OPERATING SEGMENTS

OPERATING SEGMENTS

NOTE L – OPERATING SEGMENTS

The following table reconciles the segment information to the corresponding amounts in the Consolidated Statements of Operations and total assets:

Year ended December 31, 2014	Oil and Gas Operations			Retirement Facility		Corporate			Total
Operating revenue	$	1,489		$	2,874	$	-		$	4,363
Operating expenses		1,233			2,512		823		$	4,568
Depreciation, depletion and amortization		620			65		-		$	685
Impairment of oil and gas properties		-			-		-		$	-
Total Operating Expenses		1,853			2,577		823			5,253
Interest expense		91			-		-		$	91
Other income		(19	)		36		180		$	197
Interest income		-					5		$	5
Segment operating income	$	(474	)	$	333	$	(638	)	$	(779	)
Assets	$	10,621		$	445	$	1,208		$	12,274
Year ended December 31, 2013	Oil and Gas Operations			Retirement Facility		Corporate			Total
Operating revenue	$	1,477		$	2,745	$	-		$	4,222
Operating expenses		1,213			2,436		498		$	4,147
Depreciation, depletion and amortization		654			61		2		$	717
Impairment of oil and gas properties		200			-		-		$	200
Total Operating Expenses		2,067			2,497		500			5,064
Interest expense		114			-		-		$	114
Other income		29			-		1,344		$	1,373
Interest income		-					9			9
Segment operating income	$	(675	)	$	248	$	853		$	426
Assets	$	11,859		$	842	$	607		$	13,308
Year ended December 31, 2012	Oil and Gas Operations			Retirement Facility		Corporate			Total
Operating revenue	$	1,182		$	2,762	$	-		$	3,944
Operating expenses		1,130			2,339		575			4,044
Depreciation, Depletion and Amortization		690			50		2			742
Accretion of Asset Retirement Obligation		68			-		-			68
Impairment of oil and gas properties		912			-					912
Total Operating Expenses		2,800			2,389		577			5,766
Interest expense		-			-		(208	)		(208	)
Other income		-			-		2,198			2,198
Segment operating income	$	(1,618	)	$	373	$	1,413		$	168
Assets	$	11,199		$	611	$	674		$	12,484

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CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenue
Oil and gas operations, net of royalties	$ 1,489	$ 1,477	$ 1,182
Real estate operations	2,874	2,745	2,762
Total Revenues	4,363	4,222	3,944
Operating expenses
Oil and gas operations	1,853	1,867	1,820
Real estate operations	1,616	1,555	1,465
Lease expense	961	942	924
Corporate general and administrative	823	500	577
Accretion of asset retirement obligation	0	0	68
Impairment of natural gas and oil properties	0	200	912
Total Operating expenses	5,253	5,064	5,766
Operating earnings (loss)	(890)	(842)	(1,822)
OTHER INCOME EXPENSE
Interest income	5	9	0
Interest expense	(91)	(114)	(208)
Bad debt expense (recovery) - note receivable	0	1,562	2,076
Other income (expense), net	197	(189)	122
Total Other income (expense)	111	1,268	1,990
Earnings (loss) from continuing operations	(779)	426	168
Net income (loss) applicable to common shares	$ (779)	$ 426	$ 168
Net income (loss) per common share-basic and diluted	$ (0.40)	$ 0.22	$ 0.09
Weighted average common and equivalent shares outstanding - basic	1,947	1,947	1,947

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OPERATING LEASES

12 Months Ended

Dec. 31, 2014

OPERATING LEASES

OPERATING LEASES

NOTE F – OPERATING LEASES

The Company leases a retirement community under an operating lease which expires January 31, 2017, with an option to renew for an additional five-year period. The Company also has operating leases for equipment and office space.  The leases generally provide that the Company pay property taxes, insurance and maintenance.

Future minimum payments for the primary lease following December 31, 2014 are as follows (in thousands):

2015		980
2016		1,000
2017		83
	$	2,063

Lease expense in 2014, 2013 and 2012 was $961,000, $942,000 and $924,000 respectively.

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NOTES PAYABLE

12 Months Ended

Dec. 31, 2014

Notes Payable {1}

NOTES PAYABLE

NOTE E – NOTES PAYABLE

Notes payable is comprised of the following (in thousands):

	2014		2013
Notes payable from the acquisition of Mountaineer State Energy, Inc.	$	1,514	$	1,499
Bank Debt	$	795	$	881
	$	2,309	$	2,380

Mountaineer State Energy, Inc. was acquired in 2008. As part of the purchase price the Company issued non-interesting bearing notes with the first payment being required in 2015 and the final payment due in 2032. The balance reflected above is the present value of those obligations.

Bank debt represent loans from a bank to finance drilling and equipment at the Company’s oil and gas operation. The interest rate ranges from 5% to 5 ½ %. The loans are collateralized by the Company’s oil & gas leases as well as real property and equipment.

Aggregate annual principal maturities of long-term debt at December 31, 2014 are as follows (in thousands):

2014		881
2015		263
2016		261
2017		256
2018		107
Thereafter		541
	$	2,309

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ACCOUNTING POLICIES (POLICIES)

12 Months Ended

Dec. 31, 2014

ACCOUNTING POLICIES (POLICIES):

Principles of Consolidation

Principles of Consolidation

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

Depreciation and Amortization

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, which is included in operations, was $176,000, $188,000 and $165,000 for 2014, 2013 and 2012, respectively.

Depreciation, Depletion and Amortization of Producing Oil & Gas Properties

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.

The Company recorded depletion of mineral rights of $510,000, $650,000 and $614,000 in 2014, 2013 and 2012 respectively.

Segments

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

Major Purchaser

The Company sells most of its natural gas production to one purchaser and all of its oil production to one purchaser.  While there is an available market for crude oil and natural gas production, we cannot be assured that the loss of this purchaser would not have a material impact on the Company.

Oil and Gas Reserves

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

The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission.  Such assumptions include using recent oil and gas prices and year-end costs for estimated future development and production expenditures.  Discounted future net cash flows are calculated using a 10% rate.  Changes in any of these assumptions could have a significant impact on the standardized measure.  Accordingly, the standardized measure does not represent management’s estimated current market value of proved reserves. At December 31, 2014, 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, 2014.

Full Cost accounting

Full cost accounting

The Company uses the full cost method of accounting for its investment in oil and natural gas properties.  Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas properties (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred.

The full cost method requires the Company to calculate quarterly, by cost center, a “ceiling,” or limitation on the amount of properties that can be capitalized on the balance sheet.  To the extent capitalized costs of oil and natural gas properties, less accumulated depletion and related deferred taxes exceed the sum of the discounted future net revenues of proved oil and natural gas reserves, the lower of cost or estimated fair value of unproved properties subject to amortization, the cost of properties not being amortized, and the related tax amounts, such excess capitalized costs are charged to expense.  Beginning December 31, 2009, full cost companies use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date to calculate the future net revenues of 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 any unproved oil and gas properties on an annual basis for possible impairment or reduction in value.  The Company assesses properties on an individual basis or as a group if properties are individually insignificant.  The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned.  During any period in which these factors indicate an impairment of unproved properties not subject to amortization, the associated costs incurred to date for such properties are then included in unproved properties subject to amortization.

Gas gathering assets

Gas gathering assets

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

Office and field Equipment

Office and field equipment

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

Revenue recognition and gas imbalances

Revenue recognition and gas imbalances

We use the sales method of accounting for oil and natural gas revenues.  Under the sales method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers.  Gas imbalances at December 31, 2014 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

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

Revenue Recognition

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

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

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

Use of Estimates

 Use of Estimates

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

Cash Equivalents

Cash Equivalents

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

Other Intangible Assets

Other Intangible Assets

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

Impairment of Notes Receivable

Impairment of Notes Receivable

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

Impairment of Long-Lived Assets

Impairment of Long-Lived Assets

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

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

Sales of Real Estate

Sales of Real Estate

Gains on sales of real estate are recognized to the extent permitted by Accounting Standards Codification Topic 360-20, “Real Estate Sales – Real Estate Sales”, (“ASC 360-20”).  Until the requirements of ASC 360-20 have been met for full profit recognition, sales are accounted for by the installment or cost recovery method, whichever is appropriate.

Real Estate Held for Sale

Real Estate Held for Sale

Accounting Standards Codification Topic 360, “Property, Plant, & Equipment” (“ASC 360”)requires that properties held for sale be reported at the lower of carrying amount or fair value less costs of sale.  If a reduction in a held for sale property’s carrying amount to fair value less costs of sale is required, a provision for loss is recognized by a charge against earnings.  Subsequent revisions, either upward or downward, to a held for sale property’s estimated fair value less costs of sale are recorded as an adjustment to the property’s carrying amount, but not in excess of the property’s carrying amount when originally classified as held for sale.  A corresponding charge against or credit to earnings is recognized.  Properties held for sale are not depreciated.

Asset Retirement Obligations

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 O.

Income Tax

Income Taxes

The Company accounts for income taxes in accordance with Accounting Standards Codification, (“ASC”) No. 740, “Accounting for Income Taxes”. ASC 740 requires an asset and liability approach to financial accounting for income taxes. In the event differences between the financial reporting basis and the tax basis of the Company’s assets and liabilities result in deferred tax assets, ASC 740 requires an evaluation of the probability of being able to realize the future benefits indicated by such assets. A valuation allowance is provided for a portion or all of the deferred tax assets when there is an uncertainty regarding the Company’s ability to recognize the benefits of the assets in future years.  Recognition of the benefits of deferred tax assets will require the Company to generate future taxable income.  There is no assurance that the Company will generate earnings in future years.  Since management could not determine the likelihood that the benefit of the deferred tax asset would be realized, no deferred tax asset was recognized by the Company.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

There were no recent accounting pronouncements that our Company has not implemented that materially affect our consolidated financial statements.

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QUARTERLY DATA (UNAUDITED)

12 Months Ended

Dec. 31, 2014

QUARTERLY DATA (UNAUDITED)

QUARTERLY DATA (UNAUDITED)

NOTE M - QUARTERLY DATA (UNAUDITED)

The table below reflects the Company’s selected quarterly information for the years ended December 31, 2014, 2013 and 2010.  Amounts shown are in thousands except per share amounts.

	First			Second			Third			Fourth
Year ended December 31, 2014	Quarter			Quarter			Quarter			Quarter
Revenue	$	1,069		$	1,213		$	1,131		$	950
Operating (expense)		(1,119	)		(1,053	)		(1,087	)		(1,171	)
Corporate general and administrative expense		(192	)		(205	)		(208	)		(218	)
Impairment of natural gas and oil properties		-						-			-
Other income (expense) net		202			(54	)		(40	)		3
Net income (loss) from continuing operations		(40	)		(99	)		(204	)		(436	)
Income (loss) allocable to common shareholders	$	(40	)	$	(99	)	$	(204	)		(436	)
Income (loss) per common share – basic	$	(0.02	)	$	(0.05	)	$	(0.10	)	$	(0.23	)
	First			Second			Third			Fourth
Year ended December 31, 2013	Quarter			Quarter			Quarter			Quarter
Revenue	$	1,020		$	1,050		$	1,018		$	1,134
Operating (expense)		(1,078	)		(1,112	)		(1,102	)		(1,072	)
Corporate general and administrative expense		(173	)		(170	)		(170	)		(129	)
Impairment of natural gas and oil properties											(200	)
Other income (expense) net		262			370			387			391
Net income (loss) from continuing operations		31			138			133			124
Income (loss) allocable to common shareholders	$	31		$	138		$	133		$	124
Income (loss) per common share – basic	$	0.02		$	0.07		$	0.07		$	0.06
	First			Second			Third			Fourth
Year ended December 31, 2012	Quarter			Quarter			Quarter			Quarter
Revenue	$	964		$	988		$	976		$	1,016
Operating (expense)		(1,102	)		(1,071	)		(1,022	)		(1,082	)
Corporate general and administrative expense		(159	)		(134	)		(108	)		(176	)
Impairment of natural gas and oil properties		(912	)		-			-			-
Other income (expense) net		(58	)		48			1,674			534
Net income (loss) from continuing operations		(1,267	)		(169	)		1,520			84
Income (loss) allocable to common shareholders	$	(1,267	)	$	(169	)	$	1,520		$	84
Income (loss) per common share – basic	$	(0.65	)	$	(0.08	)	$	0.78		$	0.04

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STOCKHOLDERS' EQUITY

12 Months Ended

Dec. 31, 2014

STOCKHOLDERS' EQUITY

STOCKHOLDERS' EQUITY

NOTE I – STOCKHOLDERS’ EQUITY

Outstanding Preferred Stock

Preferred stock consists of the following (amounts in thousands):

	Year Ended
	December 31,
	2014		2013
Series B convertible preferred stock, $10 par value, liquidation value of $100, authorized 100 shares, issued and outstanding one share		1		1

The Series B preferred stock has a liquidation value of $100 per share. The right to convert expired April 30, 2003.  Dividends at a rate of 6% are payable in cash or preferred shares at the option of the Company.

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EARNINGS PER SHARE

12 Months Ended

Dec. 31, 2014

EARNINGS PER SHARE

EARNINGS PER SHARE

NOTE G - EARNINGS PER SHARE

The following table sets forth the computations of basic and diluted earnings per share (in thousands, except per share data):

	Year Ended December 31,
	2014			2013		2012
Basic Earnings Per Share:
Numerator:
Net income from continuing operations	$	(779	)	$	426	$	168
Denominator:
Weighted average shares outstanding		1,947			1,947		1,947
Basic earnings (loss) per share from continuing operations		(0.40	)		0.22		0.09
Basic earnings per share from discounted operations	$	-		$	-	$	-

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INCOME TAXES

12 Months Ended

Dec. 31, 2014

INCOME TAXES

INCOME TAXES

NOTE H – INCOME TAXES

At December 31, 2014, the Company had net operating loss carry forwards of approximately $7.4 million, which expire between 2014 and 2027.

Forms 1120, U.S, Corporation Income Tax Returns, for the years ending December 31, 2014, 2013, 2012 are subject to examination, by the IRS, generally for three years after they are filed.

The following table presents the principal reasons for the difference between the Company's effective tax rate and the United States statutory income tax rate.

	2014			2013			2012
Federal income tax at statutory rate per books	$	0		$	149		$	59
Change in valuation allowance		0			0			0
Net operating loss		0			(149	)		(59	)
Federal income tax per tax return	$	0		$	0		$	0
Effective income tax rate		0.00	%		0.00	%		0.00	%

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OTHER INCOME (EXPENSE)

12 Months Ended

Dec. 31, 2014

OTHER INCOME (EXPENSE)

OTHER INCOME (EXPENSE)

NOTE J – OTHER INCOME (EXPENSE)

Other income (expense) consists of the following: (amounts in thousands)

	Year ended December 31,
	2014		2013			2012
Litigation costs for the Chesapeake matter	$	-		(382	)		-
Income for gas held by Chesapeake		-		200			-
Other		197		(7	)		122
	$	197	$	(189	)	$	122

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Schedule of Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2014

ASSET RETIREMENT OBLIGATION

Schedule of Asset Retirement Obligations

In the third quarter of 2012, the Company re-evaluated its method of plugging abandoned wells and determined by doing so in-house it could lower the cost. Based upon the Company’s current calculations, we have established a sufficient reserve, for accounting purposes, to plug the existing wells when necessary.

	2014		2013
Asset retirement obligation, January 1	$	2,770	$	2,770
Acquisition of oil and gas properties		-		-
Revisions in the estimated cash flows		-		-
Liability incurred upon acquiring and drilling wells		-		-
Liability settled upon plugging and abandoning wells		-		-
Accretion of discounnt expense		-		-
Asset retirement obligation, December 31	$	2,770	$	2,770

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ASSET RETIREMENT OBLIGATION

12 Months Ended

Dec. 31, 2014

ASSET RETIREMENT OBLIGATION

ASSET RETIREMENT OBLIGATION

NOTE O – ASSET RETIREMENT OBLIGATION

The Company records an asset retirement obligation (ARO) when the total depth of a drilled well is reached and the Company can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs.  The Company records the ARO liability on the consolidated balance sheets and capitalizes a portion of the cost in “Oil and natural gas properties” during the period in which the obligation is incurred.  In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date and adjusted for the Company’s credit risk.  This amount is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for the Company.  After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds.  The additional capitalized costs are depreciated on a unit-of-production basis or straight-line basis.

In the third quarter of 2012, the Company re-evaluated its method of plugging abandoned wells and determined by doing so in-house it could lower the cost. Based upon the Company’s current calculations, we have established a sufficient reserve, for accounting purposes, to plug the existing wells when necessary.

	2014		2013
Asset retirement obligation, January 1	$	2,770	$	2,770
Acquisition of oil and gas properties		-		-
Revisions in the estimated cash flows		-		-
Liability incurred upon acquiring and drilling wells		-		-
Liability settled upon plugging and abandoning wells		-		-
Accretion of discounnt expense		-		-
Asset retirement obligation, December 31	$	2,770	$	2,770

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Schedule of Future Minimum Rental Payment for Operating Leases (Tables)

12 Months Ended

Dec. 31, 2014

Schedule of Future Minimum Rental Payment for Operating Leases (Tables):

Schedule of Future Minimum Rental Payments for Operating Leases

Future minimum payments for the primary lease following December 31, 2014 are as follows (in thousands):

2015		980
2016		1,000
2017		83
	$	2,063

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Basic Earnings Per Share: (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Basic Earnings Per Share:
Net income from continuing operations	$ (779,000)	$ 426,000	$ 168,000
Weighted average shares outstanding	1,947	1,947	1,947
Basic earnings (loss) per share from continuing operations	$ (0.04)	$ 0.22	$ 0.09
Basic earnings per share from discounted operations	$ 0		$ 0

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities
Net income (loss)	$ (779)	$ 426	$ 168
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion and amortization	732	763	779
Impairment of natural gas and oil properties	0	200	912
Accretion of asset retirement obligation	0	0	68
Write-off (recovery) of affiliate receivable	0	(1,562)	(2,076)
Reserve for liability in Chesapeake litigation	0	381	0
Changes in operating assets and liabilities
Other current and non-current assets	5	(163)	(227)
Accounts payable and other liabilities	(240)	1,557	756
Interest payable	0	0	121
Net cash provided by (used) in operating activities	(282)	1,602	501
Cash flows from investing activities
Investment in oil and gas properties	(129)	(240)	(103)
Fixed asset additions	(175)	(161)	(106)
Real estate held for investment	(650)	0	0
Net cash used in investing activities	(954)	(401)	(209)
Cash flows from financing activities
Payment on notes payable	(213)	(40)	(54)
Proceeds from loans	128	62	51
Net cash provided by (used in) financing activities	(85)	22	(3)
Net increase (decrease) in cash and cash equivalents	(1,321)	1,223	289
Cash and cash equivalents at beginning of year	1,621	398	109
Cash and cash equivalents at end of year	300	1,621	398
Supplemental disclosures of cash flow information
Cash paid for interest on notes payable:	$ 77	$ 72	$ 87

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FAIR VALUE OF FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2014

FAIR VALUE OF FINANCIAL INSTRUMENTS

FAIR VALUE OF FINANCIAL INSTRUMENTS

NOTE D – FAIR VALUE OF FINANCIAL INSTRUMENTS

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate values.

Cash and cash equivalents - The carrying amount approximates fair value because of the short maturity of these instruments.

Long-term debt - The fair value of the Company’s long-term debt is estimated based on market rates for the same or similar issues.  The carrying value of long-term debt approximates its fair value.

Notes receivable – The fair value of the note receivable from an affiliate partnership is estimated to approximate fair value based on its short maturity.  It is not practical to estimate the fair value of notes receivable from sale of properties because no quoted market exists and there are no comparable debt instruments to provide a basis for valuation.

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Schedule of Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2014

Schedule of Earnings Per Share (Tables):

Schedule of Earnings Per Share, Basic and Diluted

The following table sets forth the computations of basic and diluted earnings per share (in thousands, except per share data):

	Year Ended December 31,
	2014			2013		2012
Basic Earnings Per Share:
Numerator:
Net income from continuing operations	$	(779	)	$	426	$	168
Denominator:
Weighted average shares outstanding		1,947			1,947		1,947
Basic earnings (loss) per share from continuing operations		(0.40	)		0.22		0.09
Basic earnings per share from discounted operations	$	-		$	-	$	-

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Notes Payables consists of : (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Notes Payables consists of :
Notes payable from the acquisition of Mountaineer State Energy, Inc.	$ 1,514	$ 1,499
Bank Debt	795	881
Notes payables total	$ 2,309	$ 2,380

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

12 Months Ended

Dec. 31, 2014

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

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

NOTE N - 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:

	2014
	Gas (MMCF)			Oil (MBBLS)
Proved developed and undeveloped reserves -
January 1, 2014		2,887			173
Purchase of oil and natural gas properties in place		0			0
Discoveries and exclusions		0			0
Revisions		148			(24	)
Sales of oil and gas properties in place		0			0
Production		(169	)		(10	)
December 31, 2014		2,866			139
Proved developed at  beginning of year		719			105
Proved developed reserves at end of year		698			70
	2013
	Gas (MMCF)			Oil (MBBLS)
Proved developed and undeveloped reserves -
January 1, 2013		2,849			103
Purchase of oil and natural gas properties in place		0			0
Discoveries and exclusions		0			0
Revisions		232			82
Sales of oil and gas properties in place		0			0
Production		(194	)		(12	)
December 31, 2013		2,887			173
Proved developed at  beginning of year		593			35
Proved developed reserves at end of year		719			105

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

	Gas			Oil
	(MMCF)			(MBBLS)
Proved undeveloped reserves as of December 31, 2012		2,256			68
Revaluation of undeveloped reserves		-			-
Conversion to prove developed reserves		(88	)		-
Proved undeveloped reserves as of December 31, 2013		2,168			68
Conversion to prove developed reserves		-			-
Revaluation of undeveloped reserves		-			-
Proved undeveloped reserves as of December 31, 2014		2,168			68

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

	2014			2013
Property acquisition costs:
Proved properties	$	11,496		$	11,328
Unproved properties		-			-
Accumulated depreciation, depletion and amortization
and valuation allowance		(2,687	)		(2,178	)
Net capitalized costs	$	8,809		$	9,190

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

	2014		2013
Property acquisition costs:
Proved properties	$	-	$	-
Unproved properties		-		-
Exploration costs		-		-
Development costs		129		240
Total cost incurred	$	129	$	240

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.

	2014			2013
Oil and gas sales	$	1,489		$	1,477
Operating expenses		(1,233	)		(1213	)
Depreciation, depletion and amortization		(620	)		(654	)
Impairment of oil & gas properties		-			(200	)
Results of operations	$	(364	)	$	(590	)

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

	2014			2013
Future oil and gas cash inflows	$	25,595		$	30,060
Future oil & gas operating expenses		(4,170	)		(5,445	)
Future development costs		(2,983	)		(3,350	)
Future tax expense		(1,666	)		(1,257	)
Future net cash flows	$	16,776		$	20,008
10% discount to reflect timing of cash flows		(5,998	)		(7,787	)
	$	10,778		$	12,221