10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

x ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

¨ TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year-ended December 31, 2015

Commission file number 000-30234

ENERJEX RESOURCES, INC.  

(Exact name of registrant as specified in its charter)

Nevada	88-0422242
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
4040 Broadway
Suite 508
San Antonio, Texas	78209
(Address of principal executive offices)	(Zip Code)

(210) 451-5545

(Registrant’s telephone number, including area code)

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

Name of each exchange on which registered:

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

Common Stock, $0.001 par value

10% Series A Cumulative Redeemable Perpetual Preferred Stock, $0.001 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

¨   Yes           x   No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.

¨   Yes           x   No

Indicate by checkmark 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.  

x   Yes           ¨   No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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).

x   Yes           ¨   No

Indicate by checkmark 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.     ¨

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

Large accelerated filer  ¨	Accelerated filer  ¨
Non-accelerated filer  ¨  (Do not check if a smaller reporting company)	Smaller reporting company  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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: approximately $6.0 million based on a share value of $1.50.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: 8,423,936 shares of common stock, $0.001 par value, outstanding on April 11, 2016.

DOCUMENTS INCORPORATED BY REFERENCE

List hereunder the following documents if incorporated by reference and the Part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is incorporated: (1) Any annual report to security holders; (2) Any proxy or information statement; and (3) Any prospectus filed pursuant to Rule 424(b) or (c) under the Securities Act of 1933. The listed documents should be clearly described for identification purposes (e.g., annual report to security holders for fiscal year ended December 24, 1980).

NONE.

ENERJEX RESOURCES, INC.

FORM 10-K

TABLE OF CONTENTS

		Page
PART I		4
ITEMS 1 AND 2.	BUSINESS AND PROPERTIES	4
ITEM 1A.	RISK FACTORS	19
ITEM 1B.	UNRESOLVED STAFF COMMENTS	32
ITEM 3.	LEGAL PROCEEDINGS	32
ITEM 4.	MINE SAFETY DISCLOSURE	32
PART II		32
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	32
ITEM 6.	SELECTED FINANCIAL DATA	33
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	34
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	39
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	40
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	40
ITEM 9A	CONTROLS AND PROCEDURES	41
ITEM 9B.	OTHER INFORMATION	41
PART III		41
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	41
ITEM 11.	EXECUTIVE COMPENSATION	44
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	48
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	49
ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	52
PART IV		53
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	53

2 

 FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements that involve risks and uncertainties. The statements contained in this document that are not purely historical are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Forward-looking statements are statements regarding future events, our future financial performance, and include statements regarding projected operating results. These forward-looking statements are based on current expectations, beliefs, intentions, strategies, forecasts and assumptions and involve a number of risks and uncertainties that could cause actual results to differ materially from those anticipated by these forward-looking statements. We have attempted to identify forward-looking statements by terminology including “anticipates,” “believes,” “can,” “continue,” “could,” “estimates,” “expects,” “intends,” “may,” “plans,” “potential,” “predicts” or “should” or the negative of these terms or other comparable terminology. Although we do not make forward-looking statements unless we believe we have a reasonable basis for doing so, we cannot guarantee their accuracy. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time and it is not possible for us to predict all risk factors, nor can we address the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause our actual results to differ materially from those contained in any forward-looking statements. All forward-looking statements included in this document are based on information available to us on the date of this Annual Report on Form 10-K, and we assume no obligation to update any such forward-looking statements, except as may otherwise be required by law.

Our actual results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth in the “Risk Factors” section in Part I, Item 1A of this Annual Report on Form 10-K and elsewhere in this document. The factors impacting these risks and uncertainties include, but are not limited to:

· inability to attract and obtain additional development capital;

· inability to achieve sufficient future sales levels or other operating results;

· inability to efficiently manage our operations;

· effect of our hedging strategies on our results of operations;

· potential default under our secured obligations or material debt agreements;

· estimated quantities and quality of oil and gas reserves;

· declining local, national and worldwide economic conditions;

· fluctuations in the price of oil and natural gas;

· continued weather conditions that impact our abilities to efficiently manage our drilling and development activities;

· the inability of management to effectively implement our strategies and business plans;

· approval of certain parts of our operations by state regulators;

· inability to hire or retain sufficient qualified operating field personnel;

· increases in interest rates or our cost of borrowing;

· deterioration in general or regional (Colorado, Western Nebraska, Eastern Kansas and South Texas) economic conditions;

· adverse state or federal legislation or regulation that increases the costs of compliance, or adverse findings by a regulator with respect to existing operations;

· the occurrence of natural disasters, unforeseen weather conditions, or other events or circumstances that could impact our operations or could impact the operations of companies or contractors we depend upon in our operations;

· inability to acquire mineral leases at a favorable economic value that will allow us to expand our development efforts; and

· changes in U.S. GAAP or in the legal, regulatory and legislative environments in the markets in which we operate.

All references in this report to “we,” “us,” “our,” “company” and “EnerJex” refer to EnerJex Resources, Inc. and our wholly-owned operating subsidiaries, EnerJex Kansas, Inc., Black Sable Energy, LLC, Working Interest, LLC, and Black Raven Energy, Inc., unless the context requires otherwise. We report our financial information on the basis of a December 31^st fiscal year end. We have provided definitions for the oil and gas industry terms used in this report in the “Glossary” beginning on page 15 of this report.

AVAILABLE INFORMATION

We file annual, quarterly and other reports and other information with the SEC. You can read these SEC filings and reports over the Internet at the SEC’s website at www.sec.gov or on our website at www.enerjex.com. You can also obtain copies of the documents at prescribed rates by writing to the Public Reference Section of the SEC at 100 F Street, NE, Washington, DC 20549 on official business days between the hours of 10:00 am and 3:00 pm. Please call the SEC at (800) SEC-0330 for further information on the operations of the public reference facilities. We will provide a copy of our annual report to security holders, including audited financial statements, at no charge upon receipt to of a written request to us at EnerJex Resources, Inc., 4040 Broadway, Suite 508, San Antonio, Texas 78209.

INDUSTRY AND MARKET DATA

The market data and certain other statistical information used throughout this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources. In addition, some data are based on our good faith estimates.

3 

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES.

Company History

We were formerly known as Millennium Plastics Corporation and were incorporated in the State of Nevada on March 31, 1999. We abandoned a prior business plan focusing on the development of biodegradable plastic materials. In August 2006, we acquired Midwest Energy, Inc., a Nevada corporation pursuant to a reverse merger. After the merger, Midwest Energy became a wholly-owned subsidiary, and as a result of the merger the former Midwest Energy stockholders controlled approximately 98% of our outstanding shares of common stock. We changed our name to EnerJex Resources, Inc. in connection with the merger, and in November 2007 we changed the name of Midwest Energy (now our wholly-owned subsidiary) to EnerJex Kansas, Inc. All of our current operations are conducted through EnerJex Kansas, Inc., Black Sable Energy, LLC, and Black Raven Energy, Inc., and our leasehold interests are held in our wholly-owned subsidiaries Black Sable Energy, LLC, Working Interest, LLC, EnerJex Kansas, Inc., and Black Raven Energy, Inc.

Liquidity and Ability to Continue as a Going Concern

As discussed under “Item 9B — Other Information” the continued low oil and natural gas prices during 2015 and into 2016 have had a significant adverse impact on our business, and, as a result of our financial condition, substantial doubt exists that we will be able to continue as a going concern.

On April 1, 2016 we ceased making mandatory monthly borrowing base reduction payments on our credit facility. After discussions with our bank, we made our mandatory quarterly interest payment on April 6, 2016 and on April 7, 2016 entered into a Forbearance Agreement (dated as of April 4, 2016), whereby the bank agreed to not exercise remedies and rights afforded it under credit facility for thirty days. We are using this 30-day to pursue strategic alternatives

Please read “Item 9B — Other Information” for further discussion. Also, for additional discussion of factors that may affect our ability to continue as a going concern and the potential consequences of our failure to do so, please see “Item 1A—Risk Factors.”

Significant Developments in 2015

The following briefly describes our most significant corporate developments occurring in 2015:

On March 13, 2015, the Company issued in a registered offering 763,547 registered shares of its common stock together with 1,242.17099 shares of its newly designated Series B Convertible Preferred Stock (the “Preferred Stock”) convertible into 709,812 shares of common stock. We also issued in an unregistered offering, 521.62076 shares of Preferred Stock convertible into 298,069 shares of common stock, and warrants to purchase 1,771,428 shares of its common stock. The shareholder’s ability to convert a portion of the Preferred Stock and to exercise the warrant are restricted: (i) prior to the Company obtaining approval of the offering by its shareholders, which we expect to obtain before May 31, 2015, and (ii) pursuant to customary “blocker” provisions restricting the investor’s ownership to 9.99% of our outstanding common stock.

The Preferred Stock has a liquidation preference of $1,000 per share, and will be convertible at the option of the shareholder at a conversion ratio equal to approximately 571 shares of common stock for each one (1) share of Preferred Stock, subject to customary adjustments and anti-dilution price protection. Dividends are payable on the shares of Preferred Stock only if and to the extent that dividends are payable on the common stock into which the Preferred Stock is convertible. The Preferred Stock has no maturity date and can be redeemed by the Company beginning twelve months after the closing of the offering or upon a change of control. Each warrant will be exercisable for one share of common stock, for a period of five years beginning nine months after March 13, 2015, at a cash exercise price of $2.75 per share, and may be exercised on a cashless basis after that nine-month period if no effective registration statement covers the warrant shares by that time.

On May 13, 2015, the Company sold 183,433 shares of its 10% Series A Cumulative Redeemable Perpetual Preferred Stock at $12.50 per share for gross proceeds of approximately $2.3 million. The Company intends to use the net proceeds of this offering for general corporate purposes, including capital expenditures, working capital, preferred stock dividends, and repayment of outstanding borrowings under its senior credit facility.

The offering was made pursuant to a registration statement on Form S-3 (File No. 333-199030) previously filed and declared effective by the U.S. Securities and Exchange Commission (SEC). 

On July 21, 2015, the Company received a liquidating distribution from Oakridge Energy Inc. in the amount of $1,450,695 with respect to shares of Oakridge that are owned by the Company. The Company repaid $750,000 of long term debt. The remaining amount will be reinvested in Company projects. The liquidating distribution was funded from the proceeds of Oakridge’s sale of its La Plate County, Colorado property. The distribution is reflected in the September 30, 2015 Consolidated Balance sheet as part of accounts receivable.

On August 12, 2015, we entered into a Tenth Amendment to the Amended and Restated Credit Agreement. The Tenth Amendment reflects the following changes: (i) allow the Company to sell certain oil assets in Kansas, (ii) allow for approximately $1,300,000 of the proceeds from the sale to be reinvested in Company owned oil and gas projects and (iii) apply not less than $1,500,000 from the proceed of the sale to outstanding loan balances.

On August 12, 2015, EnerJex Resources, Inc., through its subsidiaries, EnerJex Kansas, Inc., and Working Interest, LLC, sold various oil and gas leases, equipment and wells in Kansas for approximately $2.8 million to Haas Petroleum, LLC, BAM Petroleum, LLC and MorMeg, LLC. The effective date of the sale was July 1, 2015.

On November 4, 2015 the Company suspended the monthly dividend for the month of November 2015 on its 10.00% Series A Cumulative Redeemable Perpetual Preferred Stock (“Series A Preferred Stock”) in order to preserve its cash resources. Payment of future dividends on the Series A Preferred Stock will be determined by the Company’s Board of Directors.

Under the terms of the Series A Preferred Stock, the dividend for the month of November 2015, and any future unpaid dividends, will accumulate. If the Company does not pay dividends on its Series A Preferred Stock for six monthly periods (whether consecutive or non-consecutive), the dividend rate will increase to 12.0% per annum and the holders of the Series A Preferred Stock will have the right, at the next meeting of stockholders, to elect two directors to serve on the Company’s Board of Directors along with other members of the Board, until all accumulated accrued and unpaid dividends are paid in full.

On November 13, 2015, the Company entered into a Eleventh Amendment to the Amended and Restated Credit Agreement (the “Eleventh Amendment”). The Eleventh Amendment reflects the following changes: (i) waived certain provisions of the Credit Agreement, (ii) suspend certain hedging requirements, and (iii) to make certain other amendments to the Credit Agreement.

4 

Our Business

Our principal strategy is to acquire, develop, explore and produce domestic onshore oil and natural gas properties. Our business activities are currently focused in Kansas, Colorado, Nebraska, and Texas.

Our total net proved oil and gas reserves as of December 31, 2015 were 2.6 million barrels of oil equivalents (BOE), of which 59.4% was oil. Of the 2.6million BOE of total proved reserves, approximately 39.0% are classified as proved developed producing, approximately 32.9% are classified as proved developed non-producing, and approximately 28.1% are classified as proved undeveloped.

The total PV10 (present value) of our proved reserves as of December 31, 2015 was approximately $8.8 million. “PV10” means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs after giving consideration of salvage value there were no material abandonment costs included in future development costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV10 is a non-GAAP financial measure and generally differs from the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Reserves” page 36, for a reconciliation to the comparable GAAP financial measure.

Except where noted, the discussion regarding our business in this Annual Report on Form 10-K is as of December 31, 2015.

Our Colorado Properties

The table below summarizes our current Colorado and Nebraska acreage by project name as of December 31, 2015.

Project Name	Developed Acreage (1)				Undeveloped Acreage				Total Acreage
	Gross		Net (2)		Gross		Net (2)		Gross		Net (2)
Adena		18,280		18,280		-		-		18,280		18,280
Hereford		-		-		3,400		3,400		3,400		3,400
Seven Cross		640		544		-		-		640		544
Niobrara - Colorado (3)		21,773		21,010		25,176		22,929		46,949		43,939
Niobrara - Nebraska		-		-		9,516		9,356		9,516		9,356
Total		40,693		39,834		38,092		35,685		78,785		75,519

(1) Developed acreage includes all acreage that was held by production as of December 31, 2015.

(2) Net acreage is based on our net working interest as of December 31, 2015.

(3) Developed acreage includes 8,372 net acres with rights limited to depths below the Niobrara formation.

5 

Adena Field Project

The Adena Field Project is located in the Denver-Julesburg (“D-J”) Basin in Morgan County, Colorado, where we owned a 100% working interest in 18,280 gross acres as of December 31, 2015. Our acreage position covers the majority of Adena Field, which is the third largest oil field ever discovered in Colorado behind Rangely Field and Wattenberg Field. Adena Field has cumulatively produced 75 million barrels of oil and 125 billion cubic feet of natural gas since its discovery in the early 1950s. Our acreage in this project is currently held-by-production (see “Glossary” on page 15 for definition of held-by-production). The majority of the producing wells in Adena Field were temporarily abandoned or shut-in during the mid-1980’s when oil prices collapsed, and a relatively small number of wells have been produced since that time.

Approximately 111 wells on our acreage are currently shut-in or temporarily abandoned. Our current understanding of the field indicates that most of the remaining 97 shut-in oil wells are candidates for reactivation, recompletion or use in a larger scale EOR project. The same is true for the remaining 14 shut-in injection wells.  We have a significant EOR project study under way at the present time and have begun field sampling and EOR flood modeling for each project. We intend to reactivate vintage secondary recovery injection wells simultaneously with the reactivation and/or recompletion of producer wells. Recompletions and reactivations are expected to cost approximately $200,000 to $250,000 per well and are expected to result in stabilized production rates of approximately 10 barrels of oil per day. We have also identified a number of wells on our acreage that are prospective for natural gas production from the J-Sand and D-Sand formations.

As of December 31, 2015, the Adena Field Project was producing approximately 100 gross barrels of oil per day from 20 J-Sand wells and 10 D-Sand wells at a depth of approximately 5,500 feet. One J sand gas producer was temporarily shut-in because of low natural gas prices and due to reservoir management practices.  Multiple wells are off production because they require maintenance work; however, we have delayed maintenance expenditures due to low commodity prices. We intend to pursue our reactivation and recompletion strategy once oil prices recover.

Our working interest in our Adena Field Project is subject to a 30% reversionary working interest that will be assigned to an unrelated third party after payout of all acquisition, operating, development, and financing costs including interest (approximately $33 million at December 31, 2015).

Niobrara – Colorado & Nebraska

Our Niobrara Project is located in the northeastern portion of the D-J Basin, where we owned a 100% working interest in approximately 56,465 gross acres as of December 31, 2015. Our acreage is located in Phillips and Sedgwick Counties, Colorado, and Perkins County, Nebraska.

Approximately 21,000 acres in this project are held by production and leases on approximately 17,500 acres expire after 2016. As of December 31, 2015, we owned a 100% working interest in 24 Niobrara gas wells and we owned approximately a 6% overriding royalty interest in 180 Niobrara gas wells that are operated by Atlas Resources, LLC. All of these wells are located in Amherst Field in Phillips and Sedgwick Counties, Colorado. As of December 31, 2015, we produced approximately 125 net mcf of natural gas per day from the Niobrara formation at a depth of approximately 2,500 feet.

Our existing Niobrara acreage was high-graded based on structural features identified through analysis of 114 miles of 2D and 165 square miles (105,000 acres) of 3D seismic data on our original position of 330,000 net acres. We have identified more than 150 highly-ranked Niobrara drilling locations on our acreage based on 3D seismic analysis, which has historically yielded success rates of approximately 90% in this play. Our acreage is well situated with direct access to the Cheyenne Hub market in immediate proximity to the 1,679-mile Rocky Mountain Express pipeline and the 436-mile Trailblazer pipeline.

In 2015, we consummated a joint venture with third party industry partners to drill exploration wells targeting deeper potential pay zones in our Niobrara project acreage. Per the terms of the joint venture agreement, our industry partners agreed to pay 100% of drilling and completion costs of the first four exploration wells drilled in the project area. We drilled the first two exploration wells during the fourth quarter 2015, and we elected to plug and abandon those wells. Future test wells are not planned at this time.

DJ Basin Resource Play Exposure

Other operators in the DJ basin have recently permitted, drilled and tested numerous wells on trend with our Niobrara Project acreage and our Adena Field Project acreage. These operators are targeting oil production from conventional reservoirs and unconventional resource plays in Permian and Pennsylvanian aged carbonates and shales. These plays are in the early stages of exploration and development, and widespread economic success has not yet been established. We continue to monitor these exploration efforts closely and we currently own and control all depths that are prospective for these plays under all of our current acreage position.

6 

Our Kansas Properties

The table below summarizes our current Kansas acreage by project name as of December 31, 2015.

Project Name	Developed Acreage (1)				Undeveloped Acreage				Total Acreage
	Gross		Net (2)		Gross		Net  (2)		Gross		Net (2)
Mississippian Project		3,880		3,492		-		-		3,880		3,880
Other		584		146		-		-		584		146
Total		4,464		3,638		-		-		4,464		3,638

(1) Developed acreage includes all acreage that was held by production as of December 31, 2015.

(2) Net acreage is based on our net working interest as of December 31, 2015.

Mississippian Project

Our Mississippian Project is located in Woodson and Greenwood Counties in Southeast Kansas, where we owned a 90% working interest in 3,880 gross acres. Approximately 73.5% of the gross leased acres in this project are currently held-by-production.

As of December 31, 2015, our Mississippian Project was producing approximately 125 gross barrels of oil per day from the Mississippian formation at a depth of approximately 1,700 feet.

Cherokee Project

Our Cherokee Project is located in Miami and Franklin Counties in Eastern Kansas, where we owned an average working interest of 86% in 10,252 gross acres as of December 31, 2014.

On August 12, 2015, EnerJex Resources, Inc., through its subsidiaries, EnerJex Kansas, Inc., and Working Interest, LLC, sold the Cherokee Project for approximately $2.8 million to Haas Petroleum, LLC, BAM Petroleum, LLC and MorMeg, LLC. The effective date of the sale was July 1, 2015.

7 

Our Texas Properties

The table below summarizes our current Texas acreage by project name as of December 31, 2015.

Project Name	Developed Acreage (1)				Undeveloped Acreage				Total Acreage
	Gross		Net (2)		Gross		Net (2)		Gross		Net (2)
El Toro Project		458		275		-		-		458		275
Total		458		275		-		-		458		275

(1)	Developed acreage includes all acreage that was held by production as of December 31, 2015.
(2)	Net acreage is based on our net working interest as of December 31, 2015.

El Toro Project

Our El Toro Project is located in Atascosa and Frio Counties in South Texas. As of December 31, 2015, we owned a 60% working interest in 458 gross acres. As of December 31, 2015, this project was producing approximately 10 gross barrels of oil per day from the Olmos formation at a depth of approximately 4,500 feet.

8 

Our Business Strategy

Our principal strategy focuses on the acquisition and development of oil and gas properties that have low production decline rates and offer drilling opportunities with low risk profiles. Our oil and gas operations are in Kansas, Colorado, Nebraska, and Texas. The principal elements of our business strategy are:

· Develop Our Existing Properties.   Creating production, cash flow, and reserve growth by developing our inventory of hundreds of drilling locations that we have identified on our existing properties.

· Maximize Operational Control.   We seek to operate and maintain a substantial working interest in the majority of our properties. We believe the ability to control our drilling inventory will provide us with the opportunity to more efficiently allocate capital, manage resources, control operating and development costs, and utilize our experience and knowledge of oil and gas field technologies.

· Pursue Selective Acquisitions and Joint Ventures.   We believe our local presence in Kansas, Colorado, Nebraska, and Texas makes us well-positioned to pursue selected acquisitions and joint venture arrangements.

· Reduce Unit Costs Through Economies of Scale and Efficient Operations.   As we increase our oil and gas production and develop our existing properties, we expect that our unit cost structure will benefit from economies of scale. In particular, we anticipate reducing unit costs by greater utilization of our existing infrastructure over a larger number of wells.

Our future financial results will continue to depend on:

· the market price for oil, gas and natural gas liquids;

· our ability to preserve sufficient working capital and maintain access to capital resources;

· our ability to cost effectively manage our operations;

· our ability to source and evaluate potential projects;

· our ability to discover and exploit commercial quantities of oil and gas;

· our ability to implement our exploration and development program.

We cannot guarantee that we will succeed in any of these respects. Further, we cannot know if the price of crude oil and natural gas prevailing at the time of production will be at a level allowing for profitable production, or that we will be able to obtain additional funding at terms favorable to us to increase our capital resources. A detailed description of these and other risks that could materially impact our actual results is in “Risk Factors” under ITEM 1A.

Drilling Activity

The following table sets forth the results of our drilling activities, including both oil and gas production wells and water injection wells that were drilled and completed during the year ended December 31, 2015 and the year ended December 31, 2014.

Drilling Activity
	Gross Wells						Net Wells (1)
Fiscal Year	Total		Successful		Dry		Total		Successful		Dry
2015 - Development		-		-		-		-		-		-
2015 - Exploratory		2		-		2		1.0		-		1.0
2014 - Development		52		51		1		41.0		40.1		0.9
2015 - Recompletion		-		-		-		-		-		-
2014 - Recompletion		19		19		-		19		19		-

⁽¹⁾ Net wells are based on our net working interest at the end of each respective year.

9 

Net Production, Average Sales Price and Average Production and Lifting Costs

The table below sets forth our net oil and gas production (net of all royalties, overriding royalties and production due to others) for the years ended December 31, 2015 and 2014, the average sales prices, average production costs and direct lifting costs per unit of production.

	Year ended December 31,
	2015		2014
Net Production
Crude oil (bbl)		96,244		150,469
Natural gas liquids (bbl)		6,045		6,619
Natural gas (mcf)		188,408		318,226
Average Sales Prices
Crude oil (per bbl)	$	46.76		86.76
Natural gas liquids (per bbl)	$	4.01		30.65
Natural gas (per mcf)	$	1.88		3.25
Average Production Cost (1)  per BOE	$	48.78		48.78
Average Lifting Costs (2) per BOE	$	31.99		31.99

(1)	Production costs include all operating expenses, depreciation, depletion and amortization, lease operating expenses (including price differentials) and all associated taxes. Impairment of oil and gas properties is not included in production costs.
(2)	Direct lifting costs do not include impairment expense or depreciation, depletion and amortization, but do include transportation costs, which are paid to our purchasers as a price differential.

Results of Oil and Gas Producing Activities

The following table shows the results of operations from our oil and gas producing activities from the years ended December 31, 2015 and 2014. Results of operations from these activities have been determined using historical revenues, production costs, depreciation, depletion and amortization of the capitalized costs subject to amortization. General and administrative expenses and interest expense have been excluded from this determination.

	Year Ended			Year Ended
	December 31,			December 31,
	2015			2014
Production revenues	$	4,878,722		$	14,293,368
Production costs		(4,501,940	)		(6,762,248	)
Depreciation, depletion and amortization		(1,311,446	)		(3,259,442	)
Results of operations for producing activities	$	(934,664	)	$	4,271,678

Active Wells

The following table sets forth the number of wells in which we owned a working interest that were actively producing oil and gas or actively injecting water as of December 31, 2015.

	Active
Project	Gross		Net (1)
Crude Oil
El Toro Project		12		7.2
Mississippian Project		231		207.9
Adena Field Project		51		51.0
Other		40		35.2
Total Oil		334		301.3
Natural Gas
Niobrara Project		21		21.0
Other		36		3.2
Total Gas		57		24.2

(1) Net wells are based on our net working interest as of December 31, 2015.

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Reserves

Proved Reserves

The estimated total PV10 (present value) of our proved reserves as of December 31, 2015 was $8.8million, compared to $64.3 million as of December 31, 2014. Our total net proved oil and gas reserves as of December 31, 2015 were 2.6 million BOE (59% oil), compared to 4.4 million BOE (69% oil) as of December 31, 2014. Of the 2.6 million net BOE of total proved reserves at December 31, 2015, approximately 39.0% are classified as proved developed producing, approximately 32.9% are classified as proved developed non-producing, and approximately 28.1% are classified as proved undeveloped. See “Glossary” on page 17 for our definition of PV10.

The estimated PV10 of the 2.6 million BOE is set forth in the following table. The PV10 is calculated using an average net oil price of $50.28 per barrel, an average net natural gas price of $2.58 per mcf and an average natural gas liquids price of $9.80 per barrel, and by applying an annual discount rate of 10% to the forecasted future net cash flow.

In 2015 the Company invested approximately $250,000 in its oil and gas properties. These reduced expenditures were primarily in response to extremely low commodity prices. The Company has $7.4 million of current asset on hand, approximately $3.7 million of unrealized hedge gains and important infrastructure in Colorado completed which will facilitate the exploitation and development of proved undeveloped reserves over the next five years. At year end the Company’s review of proved undeveloped reserves revealed no instances of reserves that have not been developed within five years of their initial recording as a proved undeveloped reserve. In addition it believes it has the financial wherewithal to develop all it’s proved undeveloped reserves within the five year time frames required; utilizing its balance sheet, it borrowed $.5 million from its bank in January 2015 and has the ability to joint venture any of its assets.

Summary of Proved Oil and Gas Reserves

December 31, 2015

	Gross								Net
			Natural Gas				Oil				Natural Gas				Oil
	Crude Oil		Liquids		Natural Gas		Equivalents		Crude Oil		Liquids		Natural Gas		Equivalents		PV 10(2)
Proved Reserves Category	BBL’s		BBL’s		MCF’s		BOE’s		BBL’s		BBL’s		MCF’s		BOE’s(1)		(before tax)
Proved, Developed		1,739,160		62,080		5,292,310		2,683,290		1,329,140		48,930		2,842,970		1,851,900		7,027,000
Proved, Undeveloped		196,860		-		4,176,000		892,860		152,610		-		3,422,170		722,970		1,743,000
Total Proved		1,936,020		62,080		9,468,310		3,576,150		1,481,740		48,930		6,265,140		2,574,860		8,770,000

(1)	Net BOE is based upon our net revenue interest
(2)	See “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Reserves” page 34 for a reconciliation to the comparable GAAP financial measure.

Oil and Gas Reserves Reported to Other Agencies

We did not file any estimates of total proved net oil and gas reserves with, or include such information in reports to any federal authority or agency, other than the SEC, during the year ended December 31, 2015.

Title to Properties

We believe that we have satisfactory title to or rights in all of our producing properties. As is customary in the oil and gas industry, minimal investigation of title is made at the time of acquisition of undeveloped properties. In most cases, we investigate title and obtain title opinions from counsel or have title reviewed by professional landmen only when we acquire producing properties or before we begin drilling operations. However, any acquisition of producing properties without obtaining title opinions is subject to a greater risk of title defects.

Our properties are subject to customary royalty interests, liens under indebtedness, liens incident to operating agreements and liens for current taxes and other burdens, including mineral encumbrances and restrictions. Further, our debt is secured by liens substantially on all of our assets. These burdens have not materially interfered with the use of our properties in the operation of our business to date, though there can be no assurance that such burdens will not materially impact our operations in the future

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Sale of Oil and Gas

We do not intend to refine our oil production. We expect to sell all or most of our production to a small number of purchasers in a manner consistent with industry practices at prevailing rates by means of long-term and short-term sales contracts, some of which may have fixed price components. In 2015, we sold oil to ARM Energy Management LLC, Coffeyville Resources, Inc., Plains Marketing LP, MV Purchasing, and Sunoco Logistics, Inc. on a month-to-month basis (i.e., without a long-term contract). We sold our natural gas to United Energy Trading on a month-to-month basis and Western Operating Company under a long-term contract. Under current conditions, we should be able to find other purchasers, if needed. All of our produced oil is held in tank batteries. Each respective purchaser picks up the oil from our tank batteries and transports it by truck to refineries. In addition, our Board of Directors has implemented a crude oil and gas hedging strategy that will allow management to hedge the majority of our net production in an effort to mitigate our exposure to changing oil and natural gas prices in the intermediate term. We have an ISDA master agreement and a deferred premium put options with BP through December 31, 2016. 

Secondary Recovery and Other Production Enhancement Strategies

When an oil field is first produced, the oil typically is recovered as a result of natural pressure within the producing formation, often assisted by pumps of various types. The only natural force present to move the crude oil to the wellbore is the pressure differential between the higher pressure in the formation and the lower pressure in the wellbore. At the same time, there are many factors that act to impede the flow of crude oil, depending on the nature of the formation and fluid properties, such as pressure, permeability, viscosity and water saturation. This stage of production is referred to as “primary production”, which typically only recovers 5% to 15% of the crude oil originally in place in a producing formation.

Production from oil fields can often be enhanced through the implementation of “secondary recovery”, also known as water flooding, which is a method in which water is injected into the reservoir through injector wells in order to maintain or increase reservoir pressure and push oil to the adjacent producing wellbores. We utilize water flooding as a secondary recovery technique for the majority of our oil properties in Kansas, even in the early stages of production and we use a secondary recovery technique in parts of the Adena Field Project in Colorado.

As a water flood matures over time, the fluid produced contains increasing amounts of water and decreasing amounts of oil. Surface equipment is used to separate the produced oil from water, with the oil going to holding tanks for sale and the water being re-injected into the oil reservoir.

In addition, we may utilize 3D seismic analysis, horizontal drilling, and other technologies and production techniques to improve drilling results and oil recovery, and to ultimately enhance our production and returns. We also believe use of such technologies and production techniques in exploring for, developing, and exploiting oil properties will help us reduce drilling risks, lower finding costs and provide for more efficient production of oil from our properties.

Markets and Marketing

The oil and gas industry has experienced dramatic price volatility in recent years. As a commodity, global oil prices respond to macro-economic factors affecting supply and demand. In particular, world oil prices have risen and fallen in response to political unrest and supply uncertainty in the Middle East, and changing demand for energy in rapidly emerging market economies, notably India and China. North American prospects became more attractive as oil prices rose worldwide. Escalating conflicts in the Middle East and the ability of OPEC to control supply and pricing are some of the factors impacting the availability of global supply. As a commodity, natural gas prices respond mainly to regional supply and demand imbalances. Factors that affect the supply side include production of natural gas, levels of natural gas imports and fluctuations in underground storage. Factors that affect the demand side include peak demand brought on by winter heating and summer cooling requirements and increasing demand from the petrochemical industry for their produced products such as plastics, fertilizers, paints, soaps etc. The costs of steel and other products used to construct drilling rigs and pipeline infrastructure, as well as, drilling and well-servicing rig rates, are impacted by the commodity price volatility.

Our market is affected by many factors beyond our control, such as the availability of other domestic production, commodity prices, the proximity and capacity of oil and gas pipelines, and general fluctuations of global and domestic supply and demand. In 2015 had month-to-month sales contracts with ARM Energy Management LLC, Coffeyville Resources, Inc., Plains Marketing LP, MV Purchasing, Sunoco Logistics, Inc., United Energy Trading and Western Operating Company and we do not anticipate difficulty in finding additional sales opportunities, as and when needed.

Oil and gas sales prices are negotiated based on factors such as the spot price or posted price for oil and gas, price regulations, regional price variations, hydrocarbon quality, distances from wells to pipelines, well pressure, and estimated reserves. Many of these factors are outside our control. Oil and gas prices have historically experienced high volatility, related in part to ever-changing perceptions within the industry of future supply and demand.

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Competition

The oil and gas industry is intensely competitive and we must compete against larger companies that may have greater financial and technical resources than we do and substantially more experience in our industry. These competitive advantages may better enable our competitors to sustain the impact of higher exploration and production costs, oil and gas price volatility, productivity variances between properties, overall industry cycles and other factors related to our industry. Their advantage may also negatively impact our ability to acquire prospective properties, develop reserves, attract and retain quality personnel and raise capital.

Research and Development Activities

We have not spent a material amount of time or money on research and development activities in the last two years.

Governmental Regulations

Our oil and gas exploration, production and related operations, when developed, are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies that impose requirements relating to the exploration and production of oil and natural gas. For example, laws and regulations often address conservation matters, including provisions for the unitization or pooling of oil and gas properties, the spacing, plugging and abandonment of wells, rates of production, water discharge, prevention of waste, and other matters. Prior to drilling, we are often required to obtain permits for drilling operations, drilling bonds and file reports concerning operations. Failure to comply with any such rules and regulations can result in substantial penalties. Moreover, laws and regulations may place burdens from previous operations on current lease owners that can be significant.

The public attention on the production of oil and gas will most likely increase the regulatory burden on our industry and increase the cost of doing business, which may affect our profitability. Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations.

The price we may receive from the sale of oil and gas will be affected by the cost of transporting products to markets. Effective January 1, 1995, FERC implemented regulations establishing an indexing system for transportation rates for oil and gas pipelines, which, generally, would index such rates to inflation, subject to certain conditions and limitations. We are not able to predict with certainty the effect, if any, of these regulations on our intended operations. However, the regulations may increase transportation costs or reduce well head prices for oil and natural gas.

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Environmental Matters

Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue.

These laws and regulations may:

· require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities;

· limit or prohibit construction, drilling and other activities on certain lands; and

· impose substantial liabilities for pollution resulting from its operations, or due to previous operations conducted on any leased lands.

The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us, as well as the oil and gas industry in general.

The Comprehensive Environmental, Response, Compensation, and Liability Act, as amended (“CERCLA”), and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for the neighboring land owners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil and gas field wastes as “non-hazardous”, such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements.

The Federal Water Pollution Control Act of 1972, as amended (“Clean Water Act”), and analogous state laws impose restrictions and controls on the discharge of pollutants into federal and state waters. These laws also regulate the discharge of storm water in process areas. Pursuant to these laws and regulations, we are required to obtain and maintain approvals or permits for the discharge of wastewater and storm water and develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans”, in connection with on-site storage of greater than threshold quantities of oil and gas. The EPA issued revised SPCC rules in July 2002 whereby SPCC plans are subject to more rigorous review and certification procedures. We believe that our operations are in substantial compliance with applicable Clean Water Act and analogous state requirements, including those relating to wastewater and storm water discharges and SPCC plans.

The Endangered Species Act, as amended (“ESA”), seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify the critical habitat of such species. Under ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. ESA provides for criminal penalties for willful violations of the Act. Other statutes that provide protection to animal and plant species and that may apply to our operations include, but are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. Although we believe that our operations will be in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject us to significant expenses to modify our operations or could force us to discontinue certain operations altogether.

Personnel

We currently have 16 full-time employees, including field personnel. As production and drilling activities increase or decrease, we may have to continue to adjust our technical, operational and administrative personnel as appropriate. We are using and will continue to use independent consultants and contractors to perform various professional services, particularly in the area of land services, reservoir engineering, geology, drilling, water hauling, pipeline construction, well design, well-site monitoring and surveillance, permitting and environmental assessment. We believe that this use of third-party service providers may enhance our ability to contain operating and general expenses, and capital costs.

Facilities

Executive offices are maintained at 4040 Broadway, Suite 508, San Antonio, Texas 78209 under a lease expiring November 2017.  We also have a field office located at 165 South Union Blvd, Suite 410, Lakewood Colorado 80228, under a lease which expires October 2019.

14 

GLOSSARY

Term	Definition
Barrel (Bbl)	The standard unit of measurement of liquids in the petroleum industry, it contains 42 U.S. standard gallons. Abbreviated to “bbl”.
Basin	A depression in the crust of the Earth, caused by plate tectonic activity and subsidence, in which sediments accumulate. Sedimentary basins vary from bowl-shaped to elongated troughs. Basins can be bounded by faults. Rift basins are commonly symmetrical; basins along continental margins tend to be asymmetrical. If rich hydrocarbon source rocks occur in combination with appropriate depth and duration of burial, then a petroleum system can develop within the basin.
BOE	Abbreviation for a barrel of oil equivalent and is a term used to summarize the amount of energy that is equivalent to the amount of energy found in a barrel of crude oil. On a BTU basis 6,000 cubic feet of natural gas is the energy equivalent to one barrel of crude oil. A conversion ratio of 6:1 is used to convert natural gas measured in thousands of cubic feet into an equivalent barrel of oil.
BOPD	Abbreviation for barrels of oil per day, a common unit of measurement for volume of crude oil. The volume of a barrel is equivalent to 42 U.S. standard gallons.
Carried Working Interest	The owner of this type of working interest in the drilling of a well incurs no capital contribution requirement for drilling or completion costs associated with a well and, if specified in the particular contract, may not incur capital contribution requirements beyond the completion of the well.
Completion/Completing	The activities and methods of preparing a well for the production of oil and gas or for other purposes such as injection.
Development	The phase in which a proven oil or natural gas field is brought into production by drilling development wells.
Development Drilling	Wells drilled during the Development phase.
Division Order	A directive signed by all owners verifying to the purchaser or operator of a well the decimal interest of production owned by the royalty owner and other working interest owners. The Division Order generally includes the decimal interest, a legal description of the property, the operator’s name, and several legal agreements associated with the process. Completion of this step generally precedes placing the royalty owner or working interest owner on pay status to begin receiving revenue payments.
Drilling	Act of boring a hole through which oil and natural gas may be produced.
Dry Wells	A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Exploration	The phase of operations which covers the search for oil and gas generally in unproven or semi-proven territory.

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Exploratory Drilling	Drilling of a relatively high percentage of properties which are unproven.
Farm Out	An arrangement whereby the owner of a lease assigns all or some portion of the lease or licenses to another company for undertaking exploration or development activity.
Fixed Price Swap	A derivative instrument that exchanges or “swaps” the “floating” or daily price of a specified volume of oil or natural gas over a specified period, for a fixed price for the specified volume over the same period (typically three months or longer).
Gross Acre	The number of acres in which the Company owns any working interest.
Gross Producing Well	A well in which a working interest is owned and is producing oil or gas. The number of gross producing wells is the total number of wells producing oil or gas in which a working interest is owned.
Gross Well	A well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.
Held-By-Production (HBP)	Refers to an oil and gas property under lease, in which the lease continues to be in force, because of production from the property.
Horizontal drilling	A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then turned and drilled horizontally. Horizontal drilling allows the wellbore to follow the desired formation.
In-Fill Wells	In-fill wells refers to wells drilled between established producing wells; a drilling program to reduce the spacing between wells in order to increase production and recovery of in-place hydrocarbons.
Oil and Gas Lease	A legal instrument executed by a mineral owner granting the right to another to explore, drill, and produce subsurface oil and gas. An oil and gas lease embodies the legal rights, privileges and duties pertaining to the lessor and lessee.
Lifting Costs	The expenses of producing oil and gas from a well. Lifting costs are the operating costs of the wells including the gathering and separating equipment. Lifting costs do not include the costs of drilling and completing the wells or transporting the oil and gas.
MCF	An abbreviation for one thousand cubic feet of natural gas.
Net Acres	Determined by multiplying gross acres by the working interest that the Company owns in such acres.
Net Producing Wells	The number of producing wells multiplied by the working interest in such wells.
Net Revenue Interest	A share of production revenues after all royalties, overriding royalties and other non-operating interests have been taken out of production for a well(s).
Operator	A person, acting for itself, or as an agent for others, designated to conduct the operations on its or the joint interest owners’ behalf.

16 

Overriding Royalty	Ownership in a percentage of production or production revenues, free of the cost of production, created by the lessee, company and/or working interest owner and paid by the lessee, company and/or working interest owner out of revenue from the well.
Probable Reserves	Probable reserves are additional reserves that are less certain to be recovered than proved reserves but which, together with Proved reserves, are as likely as not to be recovered.
Proved Developed Reserves	Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. This definition of proved developed reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a) (2-4) of Regulation S-X.
Proved Developed Non-Producing	Proved developed reserves expected to be recovered from zones behind casings in existing wells or from future production increases resulting from the effects of water flood operations.
Proved Reserves	Proved reserves are estimated quantities of crude oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Proved Undeveloped Reserves	Proved undeveloped reserves are the portion of proved reserves which can be expected to be recovered from new wells on undrilled proved acreage, or from existing wells where a relatively major expenditure is required for completion. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a) (2-4) of Regulation S-X.
PV10	PV10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV10 is a non-GAAP financial measure.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Reserves” on page 33 for a reconciliation to the comparable GAAP financial measure.
Reactivation	After the initial completion of a well, the action and techniques of reentering the well and redoing or repairing the original completion to restore the well’s productivity.
Recompletion	Completion of an existing well for production from one formation or reservoir to another formation or reservoir that exists behind casing of the same well.
Reservoir	The underground rock formation where oil and gas has accumulated. It consists of a porous rock to hold the oil and gas, and a cap rock that prevents its escape.

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Secondary Recovery	The stage of hydrocarbon production during which an external fluid such as water or natural gas is injected into the reservoir through injection wells located in rock that has fluid communication with production wells. The purpose of secondary recovery is to maintain reservoir pressure and to displace hydrocarbons toward the wellbore.  The most common secondary recovery techniques are natural gas injection and water flooding. Normally, natural gas is injected into the natural gas cap and water is injected into the production zone to sweep oil and gas from the reservoir.  A pressure-maintenance program can begin during the primary recovery stage, but it is a form of enhanced recovery.
Stock Tank Barrel or STB	A stock tank barrel of oil and gas is the equivalent of 42 U.S. Gallons at 60 degrees Fahrenheit.
Undeveloped Acreage	Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.
Unitize, Unitization	When owners of oil and gas reservoir pool their individual interests in return for an interest in the overall unit.
Water flood	The injection of water into an oil and gas reservoir to “push” additional oil and gas out of the reservoir rock and into the wellbores of producing wells. Typically a secondary recovery process.
Water Injection Wells	A well in which fluids are injected rather than produced, the primary objective typically being to maintain or increase reservoir pressure, often pursuant to a water flood.
Water Supply Wells	A well in which fluids are being produced for use in a water injection well.
Wellbore	A borehole; the hole drilled by the bit. A wellbore may have casing in it or it may be open (uncased); or part of it may be cased, and part of it may be open. Also called a borehole or hole.
Working Interest	An interest in an oil and gas lease entitling the owner to receive a specified percentage of the proceeds of the sale of oil and gas production or a percentage of the production, but requiring the owner of the working interest to bear the cost to explore for, develop and produce such oil and gas.

18 

ITEM 1A. RISK FACTORS.

In the course of conducting our business operations, we are exposed to a variety of risks that are inherent to the oil and gas industry. The following discusses some of the key inherent risk factors that could affect our business and operations. Other factors besides those discussed below or elsewhere in this report also could adversely affect our business and operations, and these risk factors should not be considered a complete list of potential risks that may affect us.

Risks Related to Recent Developments

Our 2015 oil and gas reserve report shows a material decline in our estimated reserves, which will have adverse implications to our business.

Our 2015 oil and gas reserve report shows a material decline in our estimated reserves. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. For example, estimates of quantities of proved reserves and their PV10 value are affected by changes in crude oil and gas prices, because estimates are based on prevailing prices at the time of their determination. Further, reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in any exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary from one another.

The reduction in our reserve estimates is likely to change the schedule of future production and development drilling that was contemplated in our 2014 and 2013 reserve reports. Reserve estimates are generally different, and often materially so, from the quantities of oil and natural gas that are ultimately recovered. Furthermore, estimates of quantities of proved reserves and their PV10 value may be affected by changes in crude oil and gas prices because the Company’s estimates are based on prevailing prices at the time of their determination.

Due to our substantial liquidity concerns, we may be unable to continue as a going concern.

The report of our independent registered public accounting firm that accompanies our audited consolidated financial statements for the year ended December 31, 2015 contains an explanatory paragraph regarding the substantial doubt about our ability to continue as a going concern. 

Our existing and future debt agreements could create issues as principal and interest payments become due and the debt matures that will threaten our ability to continue as a going concern.  On April 1, 2016 we informed our lender that we would cease making our mandatory monthly borrowing base reduction payments, and we did not make the required April 1, 2016 payment, putting us in default. On April 6, 2016, we made our mandatory quarterly interest payment, and on April 7, 2016 we entered into a Forbearance Agreement whereby our lender agreed to not exercise remedies and rights afforded it under our credit agreement for 30 days. If after such 30-day period we fail to satisfy our obligations with respect to our indebtedness or fail to comply with the financial and other restrictive covenants contained in the credit agreement governing our indebtedness, an event of default could result, which would permit acceleration of such debt and which could result in an event of default under and an acceleration of our other debt and would permit our lender to foreclose on any of our assets securing such debt. Any accelerated debt would become immediately due and payable. There is no assurance that our search for strategic alternatives or any particular actions with respect to refinancing existing indebtedness, extending the maturity of existing indebtedness or curing potential defaults in our existing and future debt agreements will be sufficient. The uncertainty associated with our ability to repay our outstanding debt obligations as they become due raises substantial doubt about our ability to continue as a going concern.

Our substantial indebtedness and liquidity issues may impact our business, financial condition and operations.

Due to our substantial indebtedness, liquidity issues and the potential for restructuring transactions, there is risk that, among other things:

· it may become more difficult to retain, attract or replace key employees;

· employees could be distracted from performance of their duties or attracted to other career opportunities; and

· our suppliers, hedge counterparties, vendors and service providers could renegotiate the terms of our arrangements, terminate their relationship with us or require financial assurances from us

The occurrence of certain of these events has already negatively affected our business and may continue to have a material adverse effect on our business, results of operations and financial condition.

Our maximum borrowings under our credit facility are subject to reduction based upon a borrowing base calculation, which is re-determined using updated reserve reports. Because our 2015 reserve report shows a material reduction in reserves as discussed above, our borrowing base will likely be similarly reduced. Such a reduction would increase the amount we are overdrawn on our credit facility and could negatively impact waivers granted us for non-compliance with the financial covenants previously granted by our lenders.

Lenders may impose a plan requiring that we reduce the amount of that overdraft. Any such plan may include an adjustment in the interest rate on our secured credit facilities and a requirement increased amortizing payments. Any such plan would likely require, among other things, that we apply our net cash flow to repayment of the principal of our secured credit facilities, limit our ability to pay our ordinary operating expenses as they become due and limit our new production activities. All of those factors will adversely affect the results of our operations and our stock price.

Current volatile market conditions and significant fluctuations in energy prices may continue indefinitely, negatively affecting our business prospects and viability.

The oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. Further declines in the price of oil and natural gas will have a material adverse effect on our planned operations and financial condition. Additionally, the amount of any royalty payment we receive from the production of oil and gas from our oil and gas interests will depend on numerous factors beyond our control.

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We may continue to incur substantial write-downs of the carrying value of our oil and gas properties, which would adversely impact our earnings.

We review the carrying value of our oil and gas properties under the full cost method of accounting. Under the full cost method of accounting, the net book value of oil and gas properties, less deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is (a) the present value of future net revenues computed by applying current prices of oil & gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil & gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of 10 percent and assuming continuation of existing economic conditions plus (b) the cost of properties not being amortized plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized less (d) income tax effects related to differences between book and tax basis of properties. Future cash outflows associated with settling accrued retirement obligations are excluded from the calculation. Estimated future cash flows are calculated using end-of-period costs and an un-weighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months held flat for the life of the production, except where prices are defined by contractual arrangements. 

Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the statement of operations. The ceiling calculation is performed quarterly. For the year ended December 31, 2015 impairments of $16,401,376, $11,421,613, $9,720,983 and $11,386,115 were record in the first, second, third and fourth quarters respectively. For the year ended December 31, 2014 there were no impairments resulting from the quarterly ceiling tests.

Our stock price has recently declined below $1.00 per share. If the average closing price of our common stock is less than $1.00 per share for a period of over 30 consecutive trading days, the NYSE could delist our common stock.

The NYSE requires that the average closing price of a listed company’s common stock not be less than $1.00 per share for a period of over 30 consecutive trading dates. Under NYSE rules, a company can avoid delisting, if, during the six month period following receipt of the NYSE notice and on the last trading day of any calendar month, a company’s common stock price per share and 30 trading-day average share price is at least $1.00. During this six month period, a company’s common stock will continue to be traded on the NYSE, subject to compliance with other continued listing requirements.

In the future, if our common stock ultimately were to be delisted for any reason, it could negatively impact us by (i) reducing the liquidity and market price of our common stock; (ii) reducing the number of investors willing to hold or acquire our common stock, which could negatively impact our ability to raise equity financing; (iii) limiting our ability to use a registration statement to offer and sell freely tradeable securities, thereby preventing us from accessing the public capital markets; and (iv) impairing our ability to provide equity incentives to our employees.

Risks Associated with our Debt Financing

Significant and prolonged declines in commodity prices have negatively impacted our borrowing base and our ability to borrow overall.

Our borrowing base, which is based on our oil and gas reserves, is subject to review and adjustment on a semi-annual basis and other interim adjustments. In March our borrowing base was reduced resulting in a “loan excess”. The “loan excess” was required to be eliminated through payment of a portion of the loan via monthly reductions. Cash collateralization of Letters of Credit obligations; or adding properties to the borrowing base sufficient to offset the “loan excess” may be required in the future.  A reduction in our borrowing base or the ability to borrow under our Credit Facility, combined with a reduction in cash flow from operations resulting from a decline in oil and gas prices, would likely require us to further reduce our capital expenditures and our operating activities.

20 

Until we repay the full amount of our outstanding Credit Facility, we may continue to have substantial indebtedness, which is secured by substantially all of our assets.

On December 31, 2015, we had $18,600,000 of bank loans outstanding. If we defaulted on our obligations with respect to the secured debt, the lenders may enforce their rights as secured parties and we may lose all or a portion of our assets or be forced to materially reduce our business activities.

Our substantial indebtedness could make it more difficult for us to fulfill our obligations under our Credit Facility and, therefore, adversely affect our business.

On November 13, 2015, the Company entered into a Eleventh Amendment to Amended and Restated Credit Agreement (the “Eleventh Amendment”) with Texas Capital Bank. In the Eleventh Amendment, the Bank (i) waived certain provisions of the Credit Agreement, (ii) suspend certain hedging requirements, and (iii) to made certain other amendments to the Credit Agreement.

As of December 31, 2015, we had total indebtedness of $18,600,000 under the Credit Facility and our borrowing base was $18,600,000.  Our substantial indebtedness, and the related interest expense, could have important consequences to us, including:

· our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, execution of our business strategy, or other general corporate purposes;

· being forced to use cash flow to reduce our outstanding balance as a result of an unfavorable borrowing base redetermination;

· our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service our indebtedness;

· increasing our vulnerability to general adverse economic and industry conditions;

· placing us at a competitive disadvantage as compared to our competitors that have less leverage;

· our ability to capitalize on business opportunities and to react to competitive pressures and changes in government regulation;

· our ability to, or increasing the cost of, refinancing our indebtedness; and

· our ability to enter into marketing, hedging, optimization and trading transactions by reducing the number of counterparties with whom we can enter into such transactions as well as the volume of those transactions.

The covenants in our Credit Facility impose significant operating and financial restrictions on us.

The Credit Facility imposes significant operating and financial restrictions on us. These restrictions limit our ability and the ability of our subsidiaries, among other things, to:

· incur additional indebtedness and provide additional guarantees;

· pay dividends and make other restricted payments;

· create or permit certain liens;

· use the proceeds from the sales of our oil and gas properties;

· use the proceeds from the unwinding of certain financial hedges;

· engage in certain transactions with affiliates; and

· consolidate, merge, sell or transfer all or substantially all of our assets or the assets of our subsidiaries.

The Credit Facility also contains various affirmative covenants with which we are required to comply.  With the signing of the “Eleventh Amendment” on November 13, 2015 certain covenants were waived until December 31, 2016. With these covenants waived, we were incompliance with the affirmative covenant provisions of the Credit Facility. We may be unable to comply with some or all of these covenants in the future. If we do not comply with these covenants and are unable to obtain waivers from our lenders, we would be unable to make additional borrowings under these facilities; our indebtedness under these agreements would be in default and repayment of debt could be accelerated by our lenders.   If our indebtedness is accelerated, we may not be able to repay our indebtedness or borrow sufficient funds to refinance it. In addition, if we incur additional indebtedness in the future, we may be subject to additional covenants, which may be more restrictive than those to which we are currently subject.

21 

Risks Associated with our Industry

Oil and gas prices are volatile. Future price volatility may negatively impact cash flows which could result in an inability to cover our operating and/or capital expenditures.

Our future revenues, profitability, future growth and the carrying value of our properties depend substantially on the prices we realize for our oil and gas production. Our realized prices may also affect the amount of cash flow available for operating and/or capital expenditures and our ability to borrow and raise additional capital.

Oil and gas prices are subject to wide fluctuations in response to relatively minor changes in or perceptions regarding supply and demand. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile in the future. Among the factors that can cause this volatility are:

· commodities speculators;

· local, national and worldwide economic conditions;

· worldwide or regional demand for energy, which is affected by economic conditions;

· the domestic and foreign supply of oil and gas;

· weather conditions;

· natural disasters;

· acts of terrorism and war;

· domestic and foreign governmental regulations and taxation;

· political and economic conditions in oil and gas producing countries, including those in the Middle East and South America;

· impact of the U.S. dollar exchange rates on oil and gas prices;

· the availability of refining capacity;

· actions of the Organization of Petroleum Exporting Countries, or OPEC, and other state controlled oil and gas companies relating to oil and gas price and production controls; and

· the price and availability of other fuels.

It is impossible to predict oil and gas price movements with certainty. A drop in oil and gas prices may not only decrease our future revenues on a per unit basis but also may reduce the amount of oil and gas that we can produce economically. A substantial or extended decline in oil and gas prices would materially and adversely affect our future business enough to potentially force us to cease our business operations. In addition, our reserves, financial condition, results of operations, liquidity and ability to finance and execute planned capital expenditures will also suffer in such a price decline.

Declining economic conditions and worsening geopolitical conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions. Markets in the United States and elsewhere have been experiencing volatility and disruption for more than 5 years, due in part to the financial stresses affecting the liquidity of the banking system and the financial markets generally. The consequences of a potential or prolonged recession may include a lower level of economic activity, decreasing demand for petroleum products and uncertainty regarding energy prices and the capital and commodity markets.

In addition, actual and attempted terrorist attacks in the United States, Middle East, Southeast Asia and Europe, and war or armed hostilities in the Middle East, the Persian Gulf, North Africa, Iran, North Korea or elsewhere, or the fear of such events, could further exacerbate the volatility and disruption to the financial markets and economies.

While the ultimate outcome and impact of the current economic conditions cannot be predicted, a lower level of economic activity might result in a decline in energy consumption, which may materially adversely affect the price of oil and gas, our revenues, liquidity and future growth.  Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital.

22 

The oil and natural gas business involves numerous uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

Our development, exploitation and exploration activities may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a well does not ensure a profit on investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their cost, unsuccessful wells can hurt our efforts to replace reserves.

The oil and natural gas business involves a variety of operating risks, including:

· unexpected operational events and/or conditions;

· reductions in oil and natural gas prices;

· limitations in the market for oil and natural gas;

· adverse weather conditions;

· facility or equipment malfunctions;

· title problems;

· oil and gas quality issues;

· pipe, casing, cement or pipeline failures;

· natural disasters;

· fires, explosions, blowouts, surface cratering, pollution and other risks or accidents;

· environmental hazards, such as oil spills, pipeline ruptures and discharges of toxic gases;

· compliance with environmental and other governmental requirements; and

· uncontrollable flows of oil or natural gas or well fluids.

If we experience any of these problems, it could affect well bores, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses as a result of:

· injury or loss of life;

· severe damage to and destruction of property, natural resources and equipment;

· pollution and other environmental damage;

· clean-up responsibilities;

· regulatory investigation and penalties;

· suspension of our operations; and

· repairs to resume operations.

Because we use third-party drilling contractors to drill our wells, we may not realize the full benefit of worker compensation laws in dealing with their employees. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could impact our operations enough to force us to cease our operations.

Approximately 28% of our total proved reserves as of December 31, 2015 consist of undeveloped reserves, and those reserves may not ultimately be developed or produced.

Our estimated total proved PV10 (present value) before tax of reserves as of December 31, 2015 was $8.8 million, versus $64.3 million as of December 31, 2014.  Of the 2.6 million BOE of total proved reserves, approximately 39.0% are classified as proved developed producing, approximately 32.9% are classified as proved developed non-producing, and approximately 28.1% are classified as proved undeveloped.

Assuming we can obtain adequate capital resources, we plan to develop and produce all of our proved reserves, but ultimately some of these reserves may not be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be produced in the time periods we have planned, at the costs we have budgeted, or at all.

23 

Because we face uncertainties in estimating proved recoverable reserves, you should not place undue reliance on such reserve information.

Our reserve estimates and the future net cash flows attributable to those reserves at December 31, 2015 were prepared by Cobb & Associates, Inc., an independent petroleum consultant.  There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our control and the control of these independent consultants and engineers. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that can be economically extracted, which cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to these reserves, is a function of the available data, assumptions regarding future oil and gas prices, expenditures for future development and exploitation activities, and engineering and geological interpretation and judgment. Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities and oil and gas prices. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from the assumptions and estimates in our reserve reports. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and gas attributable to any particular group of properties, the classification of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same available data. The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves included in this report were prepared by Cobb & Associates, Inc. in accordance with rules of the Securities and Exchange Commission, or SEC, and are not intended to represent the fair market value of such reserves.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs. However, actual future net cash flows from our oil and gas properties also will be affected by factors such as:

· geological conditions;

· assumptions governing future oil and gas prices;

· amount and timing of actual production;

· availability of funds;

· future operating and development costs;

· actual prices we receive for oil and gas;

· changes in government regulations and taxation; and

· capital costs of drilling new wells

The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our business or the oil and gas industry in general.

The differential between the New York Mercantile Exchange, or NYMEX, or other benchmark price of oil and gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial condition and cash flows.

The prices that we receive for our oil production in Texas, Colorado and Kansas are typically based on a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The prices we receive for our natural gas production in Colorado is based upon local market conditions but generally we receive a discount to Henry Hub. The difference between the benchmark price and the price we receive is called a differential.  We cannot accurately predict oil and gas differentials. In recent years for example, production increases from competing North American producers, in conjunction with limited refining and pipeline capacity have widened this differential. Recent economic conditions, including volatility in the price of oil and gas, have resulted in both increases and decreases in the differential between the benchmark price for oil and gas and the wellhead price we receive.  These fluctuations could have a material adverse effect on our results of operations, financial condition and cash flows by decreasing the proceeds we receive for our oil and gas production in comparison to what we would receive if not for the differential.

The oil and gas business involves numerous uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

Our development, exploitation and exploration activities may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of an oil and gas well does not ensure a profit on investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their cost, unsuccessful wells can hurt our efforts to replace reserves.

The oil and gas business involves a variety of operating risks, including:

· unexpected operational events and/or conditions;

· reductions in oil and gas prices;

· limitations in the market for oil and gas;

· adverse weather conditions;

· facility or equipment malfunctions;

· title problems;

· oil and gas quality issues;

· pipe, casing, cement or pipeline failures;

· natural disasters;

· fires, explosions, blowouts, surface cratering, pollution and other risks or accidents;

· environmental hazards, such as oil spills, pipeline ruptures and discharges of toxic gases;

· compliance with environmental and other governmental requirements; and

· uncontrollable flows of oil and gas or well fluids

If we experience any of these problems, it could affect well bores, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses as a result of:

· injury or loss of life;

· severe damage to and destruction of property, natural resources and equipment;

· pollution and other environmental damage;

· clean-up responsibilities;

· regulatory investigation and penalties;

· suspension of our operations; and

· repairs to resume operations

24 

Because we use third-party drilling contractors to drill our wells, we may not realize the full benefit of worker compensation laws in dealing with their employees. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could impact our operations enough to force us to cease our operations.

Drilling wells is speculative, and any material inaccuracies in our forecasted drilling costs, estimates or underlying assumptions will materially affect our business.

Developing and exploring for oil and gas involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oil and gas field equipment and related services. Drilling may be unsuccessful for many reasons, including geological conditions, weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of an oil and gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economic. Our initial drilling and development sites, and any potential additional sites that may be developed, require significant additional exploration and development, regulatory approval and commitments of resources prior to commercial development. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and would be forced to modify our plan of operation.

Development of our reserves, when established, may not occur as scheduled and the actual results may not be as anticipated. Drilling activity and lack of access to economically acceptable capital may result in downward adjustments in reserves or higher than anticipated costs. Our estimates will be based on various assumptions, including assumptions over which we have control and assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. We have control over our operations that affect, among other things, acquisitions and dispositions of properties, availability of funds, use of applicable technologies, hydrocarbon recovery efficiency, drainage volume and production decline rates that are part of these estimates and assumptions and any variance in our operations that affects these items within our control may have a material effect on reserves.  The process of estimating our oil and gas reserves is extremely complex, and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Our estimates may not be reliable enough to allow us to be successful in our intended business operations. Our actual production, revenues, taxes, development expenditures and operating expenses will likely vary from those anticipated. These variances may be material. In 2015 we had a carried interest in the drilling of two exploratory wells and we drilled no developmental wells.

Unless we replace our oil and gas reserves, our reserves and production will decline, which would adversely affect our cash flows and income.

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and gas production, and, therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may be unable to make such acquisitions because we are:

· unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

· unable to obtain financing for these acquisitions on economically acceptable terms; or

· outbid by competitors.

If we are unable to develop, exploit, find or acquire additional reserves to replace our current and future production, our cash flow and income will decline as production declines, until our existing properties would be incapable of sustaining commercial production.

In order to exploit successfully our current oil and gas leases and others that we acquire in the future, we will need to generate significant amounts of capital.

The oil and gas exploration, development and production business is a capital-intensive undertaking. In order for us to be successful in acquiring, investigating, developing, and producing oil and gas from our current mineral leases and other leases that we may acquire in the future, we will need to generate an amount of capital in excess of that generated from our results of operations. In order to generate that additional capital, we may need to obtain an expanded debt facility and issue additional shares of our equity securities. There can be no assurance that we will be successful in either obtaining that expanded debt facility or issuing additional shares of our equity securities, and our inability to generate the needed additional capital may have a material adverse effect on our prospects and financial results of operations. If we are able to issue additional equity securities in order to generate such additional capital, then those issuances may occur at prices that represent discounts to our trading price, and will dilute the percentage ownership interest of those persons holding our shares prior to such issuances. Unless we are able to generate additional enterprise value with the proceeds of the sale of our equity securities, those issuances may adversely affect the value of our shares that are outstanding prior to those issuances.

25 

A significant portion of our potential future reserves and our business plan depend upon secondary recovery techniques to establish production. There are significant risks associated with such techniques.

We anticipate that a significant portion of our future reserves and our business plan will be associated with secondary recovery projects that are either in the early stage of implementation or are scheduled for implementation subject to availability of capital. We anticipate that secondary recovery will affect our reserves and our business plan, and the exact project initiation dates and, by the very nature of water flood operations, the exact completion dates of such projects are uncertain. In addition, the reserves and our business plan associated with these secondary recovery projects, as with any reserves, are estimates only, as the success of any development project, including these water flood projects, cannot be ascertained in advance. If we are not successful in developing a significant portion of our reserves associated with secondary recovery methods, then the project may be uneconomic or generate less cash flow and reserves than we had estimated prior to investing the capital. Risks associated with secondary recovery techniques include, but are not limited to, the following:

· higher than projected operating costs;

· lower-than-expected production;

· longer response times;

· higher costs associated with obtaining capital;

· unusual or unexpected geological formations;

· fluctuations in oil and gas prices;

· regulatory changes;

· shortages of equipment; and

· lack of technical expertise.

If any of these risks occur, it could adversely affect our financial condition or results of operations.

Any acquisitions we complete are subject to considerable risk.

Even when we make acquisitions that we believe are good for our business, all acquisitions involve potential risks, including, among other things:

· the validity of our assumptions about reserves, future production, revenues and costs, including synergies;

· an inability to integrate successfully the businesses we acquire;

· a decrease in our liquidity by using our available cash or borrowing capacity to finance acquisitions;

· a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

· the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;

· the diversion of management’s attention from other business concerns;

· an inability to hire, train or retain qualified personnel to manage the acquired properties or assets;

· the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges;

· unforeseen difficulties encountered in operating in new geographic or geological areas; and

· customer or key employee losses at the acquired businesses.

26 

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often incomplete or inconclusive.

Our reviews of acquired properties can be inherently incomplete because it is not always feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, plugging or orphaned well liability are not necessarily observable even when an inspection is undertaken.

We must obtain governmental permits and approvals for drilling operations, which can result in delays in our operations, be a costly and time consuming process, and result in restrictions on our operations.

Regulatory authorities exercise considerable discretion in the timing and scope of permit issuances in the regions in which we operate. Compliance with the requirements imposed by these authorities can be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations and/or fines. Regulatory or legal actions in the future may materially interfere with our operations or otherwise have a material adverse effect on us. In addition, we are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed project may have on the environment, threatened and endangered species, and cultural and archaeological artifacts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitably.

Due to our lack of geographic diversification, adverse developments in our operating areas would materially affect our business.

We currently only lease and operate oil and gas properties located in Colorado, Nebraska, Kansas and Texas. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these properties caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disasters, adverse weather conditions or other events which impact this area.

We depend on a small number of customers for all, or a substantial amount of our sales. If these customers reduce the volumes of oil and gas they purchase from us, our revenue and cash flow will decline to the extent we are not able to find new customers for our production.

In Kansas, we sold oil to three purchasers: Coffeyville Resources, MV Purchasing and Plains Marketing, LP. There are approximately five potential purchasers of oil in Kansas. If a key purchaser were to reduce the volume of oil it purchases from us, our revenue and cash available for operations will decline to the extent we are not able to find new customers to purchase our production at equivalent prices.

We currently sell oil to Sunoco Logistics, Inc. in Texas. There are numerous purchasers in Texas, but increased production volumes from extensive shale drilling activity in the area could result in reduced purchases by several of our purchasers.

In Colorado we sold oil to two purchasers: ARM Energy Management LLC and Plains Marketing, LP. There are a number of potential purchasers of our oil in Colorado but increased production volumes from the DJ basin could result in reduced purchases by our purchasers. If a key purchaser were to reduce the volume of oil it purchases from us, our revenue and cash available for operations will decline to the extent we are not able to find new customers to purchase our production at equivalent prices.

We sell natural gas to United Energy Trading and Western Operating Company in Colorado. There are other purchasers for our natural gas in Colorado. If a key purchaser were to reduce the volume of gas it purchases from us, our revenue and cash available for operations will decline to the extent we are not able to find new customers to purchase our production at equivalent prices.

27 

We are not the operator of some of our properties and we have limited control over the activities on those properties.

We are not the operator of our Mississippian Project, and our dependence on the operator of this project limits our ability to influence or control the operation or future development of this project. Such limitations could materially adversely affect the realization of our targeted returns on capital related to exploration, drilling or production activities and lead to unexpected future costs.

We may suffer losses or incur liability for events for which we or the operator of a property have chosen not to obtain insurance.

Our operations are subject to hazards and risks inherent in producing and transporting oil and gas, such as fires, natural disasters, explosions, pipeline ruptures, spills, and acts of terrorism, all of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our and others’ properties. As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. In addition, pollution and environmental risks generally are not fully insurable. As a result of market conditions, existing insurance policies may not be renewed and other desirable insurance may not be available on commercially reasonable terms, if at all. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on our business, financial condition and results of operations.

Our hedging activities could result in financial losses or could reduce our available funds or income and therefore adversely affect our financial position.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and gas, we have entered into derivative contracts through December 31, 2016 for approximately 84,000 barrels of crude oil.  The settlement of and the mark to market of these contracts could result in both realized and unrealized hedging losses. For the year ended December 31, 2015, we incurred net realized and unrealized gains of approximately $2,500,000. The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. For example, the derivative instruments we may utilize may be based on posted market prices, which may differ significantly from the actual crude oil prices we realize in our operations.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, while we believe our existing derivative activities are with creditworthy counterparties, deterioration in the credit markets may cause a counterparty not to perform its obligation under the applicable derivative instrument or impact their willingness to enter into future transactions with us. If that occurred, then any hedging arrangement with such counterparty would not provide any effective hedge against changes in market conditions.

Our business depends in part on processing facilities owned by others. Any limitation in the availability of those facilities could interfere with our ability to market our oil and gas production and could harm our business.

The marketability of our oil and gas production will depend in part on the availability, proximity and capacity of pipelines and oil and gas processing facilities. The amount of oil and gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we will be provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in pipeline capacity or the capacity of processing facilities could significantly reduce our ability to market our oil and gas production and could materially harm our business.

28 

Cost and availability of drilling rigs, equipment, supplies, personnel and other services could adversely affect our ability to execute on a timely basis our development, exploitation and exploration plans.

Shortages or an increase in cost of drilling rigs, equipment, supplies or personnel could delay or interrupt our operations, which could impact our financial condition and results of operations. Drilling activity in the geographic areas in which we conduct drilling activities may increase, which would lead to increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. Increased drilling activity in these areas may also decrease the availability of rigs. We do not have any contracts for drilling rigs and drilling rigs may not be readily available when we need them. Drilling and other costs may increase further and necessary equipment and services may not be available to us at economical prices.

Our exposure to possible leasehold defects and potential title failure could materially adversely impact our ability to conduct drilling operations.

We obtain the right and access to properties for drilling by obtaining oil and gas leases either directly from the hydrocarbon owner, or through a third party that owns the lease. The leases may be taken or assigned to us without title insurance. There is a risk of title failure with respect to such leases, and such title failures could materially adversely impact our business by causing us to be unable to access properties to conduct drilling operations.

Our reserves are subject to the risk of depletion because many of our leases are in mature fields that have produced large quantities of oil and gas to date.

A significant portion of our operations are located in or near established fields in Colorado, Nebraska, Kansas and Texas. As a result, many of our leases are in, or directly offset, areas that have produced large quantities of oil and gas to date.  As such, our reserves may be negatively impacted by offsetting wells or previously drilled wells, which could significantly harm our business.

Our lease ownership may be diluted due to financing strategies we may employ in the future.

To accelerate our development efforts we may take on working interest partners who will contribute to the costs of drilling and completion operations and then share in any cash flow derived from production. In addition, we may in the future, due to a lack of capital or other strategic reasons, establish joint venture partnerships or farm out all or part of our development efforts. These economic strategies may have a dilutive effect on our lease ownership and could significantly reduce our operating revenues.

We may face lease expirations on leases that are not currently held-by-production.

We have numerous leases that are not currently held-by-production, some of which have near term lease expirations and are likely to expire. Although we believe that we can maintain our most desirable leases by conducting drilling operations or by negotiating lease extensions, we can make no guarantee that we can maintain these leases.

We are subject to complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.

Development, production and sale of oil and gas in the United States are subject to extensive laws and regulations, including environmental laws and regulations. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include, but are not limited to:

· location and density of wells;

· the handling of drilling fluids and obtaining discharge permits for drilling operations;

· accounting for and payment of royalties on production from state, federal and Indian lands;

· bonds for ownership, development and production of oil and gas properties;

· transportation of oil and gas by pipelines;

· operation of wells and reports concerning operations; and

· taxation.

Under these laws and regulations, we could be liable for personal injuries, property damage, oil and gas spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that substantially increase our costs. Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations enough to possibly force us to cease our business operations.

29 

Our operations may expose us to significant costs and liabilities with respect to environmental, operational safety and other matters.

We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil and gas production activities. We may also be exposed to the risk of costs associated with Kansas Corporation Commission, the Texas Railroad Commission and the State of Colorado Oil and Gas Conservation Commission requirements to plug orphaned and abandoned wells on our oil and gas leases from wells previously drilled by third parties. In addition, we may indemnify sellers or lessors of oil and gas properties for environmental liabilities they or their predecessors may have created. These costs and liabilities could arise under a wide range of federal, state and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs, liens and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations.

Strict, joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to operate effectively could be adversely affected.

We operate in a highly competitive environment and our competitors may have greater resources than do we.

The oil and gas industry is intensely competitive and we compete with other companies, many of which are larger and have greater financial, technological, human and other resources. Many of these companies not only explore for and produce crude oil and gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. Such companies may be able to pay more for productive oil and gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may have a greater ability to continue exploration activities during periods of low oil and gas market prices. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. If we are unable to compete, our operating results and financial position may be adversely affected.

Risks Associated with our Stock

We have ceased paying dividends on our Series A preferred stock, causing the trading price of the preferred stock to dramatically decline

On November 4, 2015, we announced that we would not be declaring the monthly dividend for the month of November 2015 on our 10.00% Series A Cumulative Redeemable Perpetual Preferred Stock in order to preserve our cash resources. We have not declared the monthly dividend since, and do not expect to do so in the near future. The failure to declare and pay monthly dividends on our preferred stock caused its trading price to decline substantially.

We do not expect to pay dividends to holders of our common stock because of the terms of our debt facility, and our need to reinvest cash flow from operations in our business.

It is unlikely that we will pay any dividends to the holders of our common stock in the foreseeable future. The terms of our debt facility require that the lender approve any such distributions, and the lender is unlikely to provide that consent so long as we have significant unpaid indebtedness outstanding.

Ownership of our common stock is highly concentrated, and such concentration may prevent other stockholders from influencing significant corporate decisions and may result in conflicts of interest that could cause our stock price to decline.  

Our directors, officers and principal stockholders (stockholders owning 10% or more of our common stock) and their affiliates beneficially owned approximately 4,367,140 shares or 54.1% of the outstanding shares of common stock, stock options, and derivatives that could have been converted to common stock at December 31, 2015, and 54.2% of the outstanding shares of common stock, options and derivatives that could have been converted to common stock as of the filing of this Annual Report on Form 10-K. Such stockholders will have significant influence over the outcome of all matters submitted to our stockholders for approval, including the election of directors and other corporate actions.

Two of our Directors, Ryan A. Lowe and Lance W. Helfert, serve on the investment committee of West Coast Asset Management, Inc. West Coast Asset Management is the managing member of West Coast Opportunity Fund, LLC, a private investment vehicle formed for the purpose of investing in a wide variety of securities and financial instruments. West Coast Asset Management’s principals also manage Montecito Venture Partners, LLC. West Coast Opportunity Fund was dissolved in 2015 and EnerJex common and preferred shares were distributed to the owners of West Coast Opportunity Fund, LLC. Montecito Venture Partners, LLC beneficially owned 7% of our common stock and .7% of our Series A preferred stock at December 31, 2015. Currently they own 7% of our common stock and .7% of our Series A preferred stock.

In addition, we engage from time to time in transactions with certain of these significant stockholders.

As stated above, Montecito Venture Partners affiliates of our directors Mr. Lowe and Mr. Helfert, beneficially own, as of December 31, 2015, 7% of our common stock and .7% of our Series A preferred stock. The interests of Montecito Venture Partners, and their affiliates, may differ from those of our other stockholders.  Montecito Venture Partners, and their affiliates are in the business of making investments in companies and maximizing the return on those investments. They currently have, and may from time to time in the future acquire, interests in businesses that directly or indirectly compete with certain aspects of our business or our suppliers’ or customers’ businesses.

Montecito Venture Partners was a party to an irrevocable voting and proxy agreement, by which Montecito Venture Partners granted to West Coast Asset Management, Inc. a proxy to vote Montecito Venture Partners shares with regard to the election of our board of directors. On March 23, 2015, the irrevocable voting and proxy agreement was terminated pursuant to written agreement.

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We have derivative securities currently outstanding and we may issue derivative securities in the future. Exercise of the derivatives will cause dilution to existing and new stockholders.

The exercise of our outstanding options and warrants, will cause additional shares of common stock to be issued, resulting in dilution to our existing and future common stockholders

We have the ability to issue additional shares of our common stock and preferred stock without asking for stockholder approval, which could cause your investment to be diluted.

Our amended and restated articles of incorporation authorize the board of directors to issue up to 250,000,000 shares of common stock and 25,000,000 shares of preferred stock.   The power of the board of directors to issue shares of common stock, preferred stock or warrants or options to purchase shares of common stock or preferred stock is generally not subject to shareholder approval.  Accordingly, any additional issuance of our common stock, or preferred stock that may be convertible into common stock, or debt instruments that may be convertible into common or preferred stock, may have the effect of diluting one’s investment.

Although our common stock and Series A preferred stock are traded on the NYSE MKT, daily trading volumes are small making it difficult for investors to sell their shares.

Our common stock and our Series A preferred stock trade on the NYSE MKT under the symbol “ENRJ,” and “ENRJ.P,” respectively but trading volume has been minimal. Therefore, the market for our common stock is limited. The trading price of our stock could be subject to wide fluctuations. Investors may not be able to purchase additional shares or sell their shares within the time frame or at a price they desire.

The price of our common stock and Series A preferred stock may be volatile and you may not be able to resell your shares at a favorable price.

Regardless of whether an active trading market for our stock develops, the market price of our stock may be volatile and you may not be able to resell your shares at or above the price you paid for such shares. Many factors beyond our control, including but not limited to the following factors could affect our stock price:

· our operating and financial performance and prospects;

· quarterly variations in the rate of growth of our financial indicators, such as net income or loss per share, net income or loss and revenues;

· changes in revenue or earnings estimates or publication of research reports by analysts about us or the exploration and production industry;

· potentially limited liquidity;

· actual or anticipated variations in our reserve estimates and quarterly operating results;

· changes in oil and gas prices;

· sales of our common stock by significant stockholders and future issuances of our common stock;

· increases in our cost of capital;

· changes in applicable laws or regulations, court rulings and enforcement and legal actions;

· commencement of or involvement in litigation;

· changes in market valuations of similar companies;

· additions or departures of key management personnel;

· general market conditions, including fluctuations in and the occurrence of events or trends affecting the price of oil and gas; and

· domestic and international economic, legal and regulatory factors unrelated to our performance.

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Our amended and restated articles of incorporation, restated bylaws and Nevada Law contain provisions that could discourage an acquisition or change of control of us.

Our amended and restated articles of incorporation authorize our board of directors to issue preferred stock and common stock without stockholder approval. The election by our board of directors to issue Series A preferred stock, and any future election to issue more preferred stock, could make it more difficult for a third party to acquire control of us. In addition, provisions of the articles of incorporation and bylaws could also make it more difficult for a third party to acquire control of us. In addition, Nevada’s “Combination with Interested Stockholders’ Statute” and its “Control Share Acquisition Statute” may have the effect in the future of delaying or making it more difficult to effect a change in control of us.

These statutory anti-takeover measures may have certain negative consequences, including an effect on the ability of our stockholders or other individuals to (i) change the composition of the incumbent board of directors; (ii) benefit from certain transactions which are opposed by the incumbent board of directors; and (iii) make a tender offer or attempt to gain control of us, even if such attempt were beneficial to us and our stockholders. Since such measures may also discourage the accumulations of large blocks of our common stock by purchasers whose objective is to seek control of us or have such common stock repurchased by us or other persons at a premium, these measures could also depress the market price of our common stock. Accordingly, our stockholders may be deprived of certain opportunities to realize the “control premium” associated with take-over attempts.

We have no plans to pay dividends on our common stock. You may not receive funds without selling your stock.

We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy with regard to our common stock is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements, investment opportunities and restrictions contained in current or future financing instruments, including the consent of debt holders and holders of Series A Shares, if applicable at such time, and other factors our Board of Directors deems relevant.

Additional Risks and Uncertainties

We are an oil and gas acquisition, exploration and development company. If any of the risks that we face actually occur, irrespective of whether those risks are described in this section or elsewhere in this report, our business, financial condition and operating results could be materially adversely affected.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

Not applicable.

ITEM 3. LEGAL PROCEEDINGS.

None

ITEM 4. MINE SAFETY DISCLOSURE

None

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Market Information for Common Stock

Our common stock trades on the NYSE MKT under the symbol “ENRJ.” The following table lists the quotations for the high and low sales prices of our common stock for the years ended December 31, 2014 and December 31, 2015. The market price of our common stock has been volatile. For an additional discussion, see “Item 1A: Risk Factors” of this Annual Report on Form 10-K.  

	High		Low
Year Ended December 31, 2014
Quarter ended March 31, 2014	$	8.55	$	7.05
Quarter ended June 30, 2014	$	9.10	$	6.75
Quarter ended September 30, 2014	$	7.70	$	5.91
Quarter ended December 31, 2014	$	6.22	$	2.00
Year Ended December 31, 2015
Quarter ended March 31, 2015	$	3.44	$	1.21
Quarter ended June 30, 2015	$	2.19	$	1.25
Quarter ended September 30, 2015	$	1.53	$	.49
Quarter ended December 31, 2015	$	.93	$	.30

Holders

As of March 30, 2016, there were 357 holders of record of our common stock, and 12 holders of record of our Series A preferred stock.

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Dividends

We have never paid or declared any cash dividends on our common stock. Through October 2015, we paid a monthly dividend of $.20833 per share or $2.50 annual dividend per share on the Company’s non-convertible 10.0% Series A Cumulative Redeemable Perpetual Preferred Stock. On November 4, 2015 the Company suspended the monthly dividend for the month of November 2015 on its 10.00% Series A Cumulative Redeemable Perpetual Preferred Stock (“Series A Preferred Stock”) in order to preserve its cash resources. Payment of future dividends on the Series A Preferred Stock will be determined by the Company’s Board of Directors.

Under the terms of the Series A Preferred Stock, the dividend for the month of November 2015, and any future unpaid dividends, will accumulate. If the Company does not pay dividends on its Series A Preferred Stock for six monthly periods (whether consecutive or non-consecutive), the dividend rate will increase to 12.0% per annum and the holders of the Series A Preferred Stock will have the right, at the next meeting of stockholders, to elect two directors to serve on the Company’s Board of Directors along with other members of the Board, until all accumulated accrued and unpaid dividends are paid in full.

We do not expect to pay any cash dividends on our common stock in the foreseeable future. Additionally, we are contractually prohibited by the terms of our outstanding debt from paying cash dividends on our common stock. Payment of future dividends on common stock, if any, will be at the discretion of our Board of Directors and will depend on our financial condition, results of operations, capital requirements, restrictions contained in current or future financing instruments, including the consent of debt holders and holders of Series A Shares, if applicable at such time, and other factors our Board of Directors deems relevant.

Securities Authorized for Issuance under Equity Compensation Plans

The following table sets forth information as of fiscal year ended December 31, 2015, regarding outstanding options granted under our stock option plans and options reserved for future grant under the plans.

					Number of shares
	Number				remaining available for
	of shares to be issued				future issuance under
	upon exercise of		Weighted-average		equity compensation
	outstanding options,		exercise price of		plans (excluding shares
	warrants and rights		outstanding options,		reflected in column (a)
Plan Category	(a)		warrants and rights (b)		(c)
Equity compensation plans approved by stockholders		288,331	$	10.17		427,157

Recent Sales of Unregistered Securities

None.

Issuer Purchases of Equity Securities

None.

ITEM 6. SELECTED FINANCIAL DATA.

Not applicable.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

This Management’s Discussion and Analysis of Financial Condition and Results of Operations section should read in conjunction with the other sections of this Annual Report on Form 10-K, including “Items 1 and 2. Business and Properties” and “Item 8: Financial Statements and Supplementary Data”. This section includes forward-looking statements within the meaning of Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements such as “will”, “believe,” “are projected to be” and similar expressions are statements regarding future events or our future performance, and include statements regarding projected operating results. These forward-looking statements are based on current expectations, beliefs, intentions, strategies, forecasts and assumptions and involve a number of risks and uncertainties that could cause actual results to differ materially from those anticipated by these forward-looking statements. These risks include, but are not limited to: our ability to deploy capital in a manner that maximizes stockholder value; the ability to identify suitable acquisition candidates or business and investments opportunities; the ability to reduce our operating costs; general economic conditions and our expected liquidity in future periods. These forward-looking statements are based on our current expectations and could be affected by the uncertainties and risk factors described throughout this filing and particularly in the “Risk Factors” set forth in Part I, Item 1A of this Annual Report on Form 10-K. As a result, our actual results may differ materially from those anticipated in these forward-looking statements.

Overview

Our principal strategy is to develop, acquire, explore and produce domestic onshore oil and gas properties. Our business activities are currently focused in Kansas, Colorado, Nebraska, and Texas.

Results of Operations

The following table presents selected information regarding our operating results from continuing operations.

	Year Ended		Year Ended
	December 31,		December 31,
	2015		2014		Difference
Oil & gas revenues (1)
Crude oil revenues	$	4,525,089	$	13,257,608	$	(8,732,519	)
Average price per Bbl		44.24		84.40		(40.16	)
Natural gas revenues		353,633		1,035,759		(682,126	)
Average price per Mcf		1.88		3.18		(1.30	)
Expenses:
Lease operating expenses (2)		4,501,940		6,762,248		(2,260,308	)
Depreciation, depletion and amortization (3)		1,108,039		3,259,442		(2,151,403	)
Impairment of oil and gas properties		48,930,087		-		48,930,087
Total production expenses		54,540,066		10,021,690		44,518,376
Professional fees (4)		680,860		987,229		(306,369	)
Salaries (5)		1,927,552		1,479,688		447,864
Depreciation - other fixed assets		203,407		289,803		(86,396	)
Administrative expenses (6)		636,459		790,572		(154,113	)
Total expenses	$	57,988,344	$	13,568,982	$	44,419,362

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⁽¹⁾ 2015 crude oil revenues decreased $8.7 million or 66% to 4.5 million from $13.3 million in fiscal 2014.  The decrease was due primarily to the dramatic decline in crude oil prices. Realized oil prices dropped $40.16 or 48% during 2015 from an average of $84.40 per bbl in 2014 to an average of $44.24 per bbl in 2015. Declining prices accounted for $6.3 million of the $8.7 million drop in crude oil revenues. A decrease in production volumes in 2015 accounted for the remaining $2.4 million of the $8.7 million decrease in revenues. Volumes decreased by approximately 54,800 bbls or 35% to 102,289 bbls in 2015 compared to production of 157,089 bbls in 2014.  Approximately 66 % of the drop in production was related to the sale of our Cherokee project asset in 2015. 2015 natural gas revenues decreased $.7 million to $354 thousand from $1.0 million in 2014. The decrease was due to primarily to lower natural gas prices in 2015. Natural gas prices decreased $1.30 per mcf or 41% from an average price of $3.18 in 2014 to an average price of $1.88 in 2015. The drop in prices contributed $400 thousand of the overall $.7 million decrease in revenues and a decrease in production volumes accounted for the remaining $300 thousand decrease in revenues. Natural gas volumes decreased approximately 137,500 mcf or 42% in 2015 from 326,000 mcf in 2014 to 188,500 mcf in 2015.

⁽²⁾ 2015 lease operating expenses decreased $2.3 million or 33% to $4.5 million from $6.8 million in 2014. However, lease operating expenses per boe increased 5% or $1.69 to $33.67 in 2015 from $31.99 per boe in 2014.  

⁽³⁾ The depletion expense decrease is due primarily to the impairment of oil and gas properties necessitated by SEC quarterly ceiling tests. The Company reviews the carrying value of oil and gas properties under the full cost method of accounting which dictates that the net book value of oil and gas properties, less deferred income taxes, may not exceed a calculated “ceiling.” Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected in the statement of operations. For the year ended December 31, 2015 impairments of $16,401,376, $11,421,613, $9,720,983 and $11,386,115 were record in the first, second, third and fourth quarters respectively. As a result of these write downs 2015 depletion expense decreased approximately $2.2 million to $1.1 million.

⁽⁴⁾ Professional fees decreased 31% or $306 thousand from $987 thousand in 2014 to $681 thousand in 2015. Investor relation expenditures decreased $202 thousand and legal fees were cut by $197 thousand. These decreases were partially offset by increases in audit and third party engineering costs.

⁽⁵⁾ Salaries increase 30% or $448 thousand. The increase was due primarily to the inclusion of full year salaries of new employees in 2015 not include in 2014 due to hiring’s in the fourth quarter of 2014, termination and severance pay to Kansas based employees and an increase in the Company’s accrual of PTO due to decreased vacations and personal time off taken in 2015 compared to 2014.

⁽⁶⁾ Administrative expenses decreased $154 thousand or 20%. The decrease was due primarily to decreased spending on insurance, $112 thousand, IT, telecommunication and software, $85 thousand and office supplies, meals, travel and entertainment $46 thousand. These decreases were partially offset by an increase in public company compliance fees paid to the SEC of approximately $88 thousand.

Reserves

	Year Ended		Year Ended
	December 31,		December 31,
Proved Reserves	2015		2014
Total proved PV10 (present value) of reserves	$	8,769,970	$	64,318,700
Total proved reserves (BOE)	$	2,574,860	$	4,400,180
Average Price (per bbl)	$	50.28	$	85.27
Average Price (per mcf)	$	2.58	$	3.52

Of the 2.6 million BOE of total proved reserves, approximately 39.0% are classified as proved developed producing, approximately 32.9% are classified as proved developed non-producing, and approximately 28.1% are classified as proved undeveloped.

The following table presents summary information regarding our estimated net proved reserves as of December 31, 2015. All calculations of estimated net proved reserves have been made in accordance with the rules and regulations of the SEC, and, except as otherwise indicated, give no effect to federal or state income taxes. The estimates of net proved reserves are based on the reserve reports prepared by Cobb & Associates Inc., our independent petroleum consultants. For additional information regarding our reserves, please see Note 13 to our audited financial statements for the fiscal year ended December 31, 2015.

Summary of Proved Oil and Gas Reserves

December 31, 2015

	Gross								Net
			Natural Gas				Oil				Natural Gas				Oil
	Crude Oil		Liquids		Natural Gas		Equivalents		Crude Oil		Liquids		Natural Gas		Equivalents		PV 10(1)
Proved Reserves Category	BBL’s		BBL’s		MCF’s		BOE’s		BBL’s		BBL’s		MCF’s		BOE’s		(before tax)
Proved, Developed		1,739,160		62,080		5,292,310		2,683,290		1,329,140		48,930		2,842,970		1,851,900		7,027,000
Proved, Undeveloped		196,860		-		4,176,000		892,860		152,610		-		3,422,170		722,970		1,743,000
Total Proved		1,936,020		62,080		9,468,310		3,576,150		1,481,740		48,930		6,265,140		2,574,860		8,770,000

In 2015 the Company invested approximately $250,000 in its oil and gas properties. These reduced expenditures were primarily in response to extremely low commodity prices. The Company has $7.4 million of current asset on hand, approximately $3.7 million of unrealized hedge gains and important infrastructure in Colorado completed which will facilitate the exploitation and development of proved undeveloped reserves over the next five years. At year end the Company’s review of proved undeveloped reserves revealed no instances of reserves that have not been developed within five years of their initial recording as a proved undeveloped reserve. In addition it believes it has the financial wherewithal to develop all it’s proved undeveloped reserves within the five year time frames required; utilizing its balance sheet, it borrowed $.5 million from its bank in January 2015 and has the ability to joint venture any of its assets.

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⁽¹⁾ The following table shows our reconciliation of our PV10 to our standardized measure of discounted future net cash flows (the most direct comparable measure calculated and presented in accordance with GAAP). PV10 is our estimate of the present value of future net revenues from estimated proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” We believe PV10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. We believe that most other companies in the oil and gas industry calculate PV10 on the same basis. PV10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.

	As of December 31,		As of December 31,
	2015		2014
PV10 (before tax)	$	8,769,970	$	64,318,782
Future income taxes, net of 10% discount	$	-	$	(1,614,931	)
Standardized measure of discounted future net cash flows	$	8,769,970	$	62,703,851

Liquidity and Capital Resources

Liquidity is a measure of a company’s ability to meet potential cash requirements. We have historically met our capital requirements through debt financing, revenues from operations, asset sales and the issuance of equity securities. Due to the dramatic deterioration of oil prices, the resulting decline in our reserves as reflected in our reserve report which caused a corresponding reduction in our borrowing base, and the recent issuances of equity securities from our “shelf” registration, it will be more difficult in 2016 to use our historical means of meeting our capital requirements to provide us with adequate liquidity to fund our operations and capital programs. Accordingly, the Company has chosen to preserve liquidity by not devoting capital to its oil and gas properties, while minimizing expenditures for operating, general and administrative expenses. With positive working capital, we will be positioned to capitalize on increases in commodity pricing when such changes occur.

The following table summarizes total current assets, total current liabilities and working capital at year ended December 31, 2015 compared to the year ended December 31, 2014.

	Year Ended		Year Ended
	December 31, 2015		December 31, 2014		Difference
Current Assets	$	7,213,213	$	7,411,168	$	(197,955	)
Current Liabilities	$	4,260,559	$	4,139,356	$	(121,202	)
Working Capital (deficit)	$	2,952,654	$	3,271,812	$	(319,157	)

Senior Secured Credit Facility

On October 3, 2011, the Company, DD Energy, Inc., EnerJex Kansas, Inc., Black Sable Energy, LLC and Working Interest, LLC (“Borrowers”) entered into an Amended and Restated Credit Agreement with Texas Capital Bank, N.A. (“Bank”) and other financial institutions and banks that may become a party to the Credit Agreement from time to time. The facilities provided under the Amended and Restated Credit Agreement were to be used to refinance Borrowers prior outstanding revolving loan facility with Bank, dated July 3, 2008, and for working capital and general corporate purposes.

At our option, loans under the facility will bear stated interest based on the Base Rate plus Base Rate Margin, or Floating Rate plus Floating Rate Margin (as those terms are defined in the Credit Agreement). The Base Rate will be, for any day, a fluctuating rate per annum equal to the higher of (a) the Federal Funds Rate plus 0.50% and (b) the Bank’s prime rate. The Floating Rate shall mean, at Borrower’s option, a per annum interest rate equal to (i) the Eurodollar Rate plus Eurodollar Margin, or (ii) the Base Rate plus Base Rate Margin (as those terms are defined in the Amended and Restated Credit Agreement). Eurodollar borrowings may be for one, two, three, or six months, as selected by the Borrowers. The margins for all loans are based on a pricing grid ranging from 0.00% to 0.75% for the Base Rate Margin and 2.25% to 3.00% for the Floating Rate Margin based on the Company’s Borrowing Base Utilization Percentage (as defined in the Amended and Restated Credit Agreement).

On December 15, 2011, we entered into a First Amendment to Amended and Restated Credit Agreement and Second Amended and Restated Promissory Note in the amount of $50,000,000 with the Bank. The Amendment reflects the addition of Rantoul Partners, as an additional Borrower and adds as additional security for the loans the assets held by Rantoul Partners.

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On August 31, 2012, we entered into a Second Amendment to Amended and Restated Credit Agreement with the Bank. The Second Amendment: (i) increased the borrowing base to $7,000,000   (ii) reduced the minimum interest rate to 3.75% and (iii) added additional new leases as collateral for the loan.

On November 2, 2012, we entered into a Third Amendment to Amended and Restated Credit Agreement with the Bank. The Third Amendment (i) increased the borrowing base to $12,150,000 and (ii) clarified certain continuing covenants and provided a limited waiver of compliance with one of the covenants so clarified for the fiscal quarter ended December 31, 2011.

On January 24, 2013, we entered into a Fourth Amendment to Amended and Restated Credit Agreement, which was made effective as of December 31, 2012 with the Bank. The Fourth Amendment reflects the following changes: (i) the Bank consented to the restructuring transactions related to the dissolution of Rantoul Partners, and (ii) the Bank terminated a Limited Guaranty, as defined in the Credit Agreement, executed by Rantoul Partners in favor of the Bank

On April 16, 2013, the Bank increased our borrowing base to $19.5 million.

On September 30, 2013, we entered into a Fifth Amendment to the Amended and Restated Credit Agreement.  The Fifth Amendment reflects the following changes:   (i) expanded principal commitment amount of the Bank to $100,000,000; (ii) increased the Borrowing Base to $38,000,000; (iii) added Black Raven Energy, Inc. to the Credit Agreement as borrower parties; (iv) added certain collateral and security interests in favor of the Bank; and (v) reduced the Company’s current interest rate to 3.30%.

On November 19, 2013, we entered into a Sixth Amendment to the Amended and Restated Credit Agreement. The Sixth Amendment reflects the following changes: (i) the addition of Iberia Bank as a participant in our credit facility, and (ii) a technical correction to our covenant calculations.

On May 22, 2014, we entered into a Seventh Amendment to the Amended and Restated Credit Agreement. The Seventh Amendment reflects the Bank’s consent to our issuance of up to 850,000 shares of our 10% Series A Cumulative Redeemable Perpetual Preferred Stock.

On August 15, 2014, we entered into an Eighth Amendment to the Amended and Restated Credit Agreement. The Eighth Amendment reflects the following changes: (i) the borrowing base was increased from $38 million to $40 million, and (ii) the maturity of the facility was extended by three years to October 3, 2018.

On April 29, 2015, we entered into a Ninth Amendment to the Amended and Restated Credit Agreement. In the Ninth Amendment, the Banks (i) re-determined the Borrowing Base based upon the recent Reserve Report dated January 1, 2015, (ii) imposed affirmative obligations on the Company to use a portion of proceeds received with regard to future sales of securities or certain assets to repay the loan, (iii) consented to non-compliance by the Company with certain terms of the Credit Agreement, (iv) waived certain provisions of the Credit Agreement, and (v) agreed to certain other amendments to the Credit Agreement.

On May 1, 2015, the Borrowers and the Banks entered into a Letter Agreement to clarify that up to $1,000,000 in proceeds from any potential future securities offering will be unencumbered by the Banks’ Liens as described in the Credit Agreement through November 1, 2015, and that, until November 1, 2015, such proceeds shall not be subject to certain provisions in the Credit Agreement prohibiting the Company from declaring and paying dividends that may be due and payable to holders of securities issued in such potential offerings or issued prior to the Letter Agreement.

On August 12, 2015, we entered into a Tenth Amendment to the Amended and Restated Credit Agreement. The Tenth Amendment reflects the following changes: (i) allow the Company to sell certain oil assets in Kansas, (ii) allow for approximately $1,300,000 of the proceeds from the sale to be reinvested in Company owned oil and gas projects and (iii) apply not less than $1,500,000 from the proceed of the sale to outstanding loan balances.

On November 13, 2015, the Company entered into a Eleventh Amendment to the Amended and Restated Credit Agreement. The Eleventh Amendment reflects the following changes: (i) waived certain provisions of the Credit Agreement, (ii) suspend certain hedging requirements, and (iii) to make certain other amendments to the Credit Agreement.

Our current borrowing base is $18,600,000, of which we had borrowed $18,600,000 as of December 31, 2015. The interest rate on amounts borrowed under our credit facility during 2015 was approximately 4.3% and for the year ended December 31, 2014, the interest rate on amounts borrowed was approximately 3.3%. This facility expires on October 3, 2018. 

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Satisfaction of our cash obligations for the next 12 months

We intend to meet our near term cash obligations through the monetization of derivative contracts, assets sales and cash flow generated from operations. Due to the declines in oil prices, the resulting decline in our reserves caused a corresponding reduction to our borrowing base, and recent issuances of equity securities from our “shelf” registration, it will be more difficult in 2016 to use our historical means to meet our cash obligations in the next twelve months.

Summary of product research and development that we will perform for the term of our plan

We do not anticipate performing any significant product research and development under our plan of operation.

Expected purchase or sale of any significant equipment

We anticipate that we will purchase the necessary production and field service equipment required to produce oil and gas during our normal course of operations over the next 12 months.

Significant changes in the number of employees

We currently have 16 full-time employees including field personnel. As production and drilling activities increase or decrease, we will adjust our technical, operational and administrative personnel as appropriate. We use and will continue to use independent consultants and contractors to perform various professional services, particularly in the area of land services, reservoir engineering, geology, drilling, water hauling, pipeline construction, well design, well-site monitoring and surveillance, permitting and environmental assessment. We believe that this use of third-party service providers may enhance our ability to contain operating and general expenses, and capital costs.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

Critical Accounting Policies and Estimates

Our accounting policies and estimates that are critical to our business operations and understanding of our results of operations include those relating to our oil and gas properties, asset retirement obligations and the value of share-based payments. This is not a comprehensive list of all of the accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by U.S. GAAP, with no need for our judgment in the application. There are also areas in which our judgment in selecting any available alternative would not produce a materially different result. However, certain of our accounting policies are particularly important to the portrayal of our financial position and results of operations and we may use significant judgment in the application; as a result, they are subject to an inherent degree of uncertainty. In applying those policies, we use our judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry, and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see Note 1, Summary of Significant Accounting Policies, to our consolidated financial statements included in this report.

Oil and Gas Properties

We follow the full-cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities.

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Proved properties are amortized using the units of production method (UOP). Currently we only have operations in the Unites States of America. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the cost of these reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (DD&A), estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs, less related salvage value.

The cost of unproved properties are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed into service. Geological and geophysical costs not associated with specific properties are recorded as proved property immediately. Unproved properties are reviewed for impairment quarterly.

Under the full cost method of accounting, the net book value of oil and gas properties, less deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is (a) the present value of future net revenues computed by applying current prices of oil & gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil & gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of 10 percent and assuming continuation of existing economic conditions plus (b) the cost of properties not being amortized plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized less (d) income tax effects related to differences between book and tax basis of properties. Future cash outflows associated with settling accrued retirement obligations are excluded from the calculation. Estimated future cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months held flat for the life of the production, except where prices are defined by contractual arrangements.

Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the statement of operations. The ceiling calculation is performed quarterly. For the year ended December 31, 2015 impairments of $16,401,376, $11,421,613, $9,720,983 and $11,386,115 were record in the first, second, third and fourth quarters respectively. For the year ended December 31, 2014 there were no impairments resulting from the quarterly ceiling tests. 

Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25%) of our reserve quantities are sold, in which case a gain or loss is recognized in income. In 2015 the Company sold its Cherokee project assets located in Kansas for net proceeds of $2,867,305. At the time of the sale the reserve quantities made up approximately 6.7% of total reserve quantities. Accordingly, the net proceeds reduced the carrying value of our oil and gas properties.

Asset Retirement Obligations

The asset retirement obligation relates to the plug and abandonment costs when our wells are no longer useful. We determine the value of the liability by obtaining quotes for this service and estimate the increase we will face in the future. We then discount the future value based on an intrinsic interest rate that is appropriate for us. If costs rise more than what we have expected there could be additional charges in the future however we monitor the costs of the abandoned wells and we will adjust this liability if necessary.

Share-Based Payments

The value we assign to the options and warrants that we issue is based on the fair market value as calculated by the Black-Scholes pricing model. To perform a calculation of the value of our options and warrants, we determine an estimate of the volatility of our stock.  We need to estimate volatility because there has not been enough trading of our stock to determine an appropriate measure of volatility. We believe our estimate of volatility is reasonable, and we review the assumptions used to determine this whenever we issue a new equity instruments.  If we have a material error in our estimate of the volatility of our stock, our expenses could be understated or overstated.

Recent Issued Accounting Standards

See Note 1, Summary of Significant Accounting Policies - Recent Issued Accounting Standards, to our consolidated financial statements included in this report.

Effects of Inflation and Pricing

The oil and gas industry is very cyclical and the demand for goods and services of oil and gas field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry. Material changes in prices impact revenue stream, estimates of future reserves, borrowing base calculations of bank loans and value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel. We anticipate business costs and the demand for services related to production and exploration will fluctuate while the commodity price for oil and gas remains volatile.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Not applicable.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Management Responsibility for Financial Information

We are responsible for the preparation, integrity and fair presentation of our financial statements and the other information that appears in this Annual Report on Form 10-K. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States and include estimates based on our best judgment.

We maintain a comprehensive system of internal controls and procedures designed to provide reasonable assurance, at an appropriate cost-benefit relationship, that our financial information is accurate and reliable, our assets are safeguarded and our transactions are executed in accordance with established procedures.

RBSM LLP, an independent registered public accounting firm, is retained to audit our consolidated financial statements. Its accompanying report is based on audits conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States).

Our consolidated financial statements and notes thereto, and other information required by this Item 8 are included in this report beginning on page F-1.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

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ITEM 9A. CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer, Robert G. Watson, Jr., and our Chief Financial Officer, Douglas M. Wright, evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended) as of the end of the period covered by this Report pursuant to Exchange Act Rule 13a-15(b). Based on the evaluation, Mr. Watson and Mr. Wright concluded that our disclosure controls and procedures are effective.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as is defined in the Securities Exchange Act of 1934. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance, with respect to reporting financial information.

Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework and criteria established in Internal Control - Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2013.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION.

On October 3, 2011, we entered into an Amended and Restated Credit Agreement with Texas Capital Bank, and other financial institutions and banks (“Bank”) that may become a party to the Credit Agreement from time to time. The facilities provided under the Amended and Restated Credit Agreement was to be used to refinance a prior outstanding revolving loan facility with TCB dated July 3, 2008, and for working capital and general corporate purposes. On August 15, 2014 we entered into an Eighth Amendment to the Amended and Restated Credit Agreement. Among other things the Eighth Amendment extended the maturity of the Agreement by three years to October 3, 2018. On August 12, 2015, we entered into a Tenth Amendment to the Amended and Restated Credit Agreement. Among other things the Tenth Amendment established the requirement of monthly borrowing base reductions commencing September 1, 2015 and continuing on the first of each month thereafter.

On April 1, 2016 we informed the Bank that it would cease making the mandatory monthly borrowing base reduction payments and did not make the required April 1, 2016 payment.

We made our mandatory quarterly interest payment on April 6, 2016 and on April 7, 2016 entered into a Forbearance Agreement (dated as of April 4, 2016), whereby the Bank agreed to not exercise remedies and rights afforded it under the Amended and Restated Credit Agreement for thirty days. We are using this 30-day to pursue strategic alternatives and discuss terms with the Bank.

The description of the Forbearance Agreement is qualified in its entirety, and the terms are incorporated herein, by reference to the Forbearance Agreement, the form of which is filed as Exhibit 10.28 hereto.

We access a number of data bases and utilizes several consultants to monthly prepare commodity price projections used in our cash forecasting models. The models indicate we will have sufficient cash to satisfy obligations as they become due through the end of the first quarter of 2017 if we cease to make the principle reduction called for by the Tenth Amendment to the Credit Agreement. If we do not obtain a waiver of this requirement during the 30-day forbearance period, we will be in default under the Credit Agreement and the Bank may accelerate the repayment of our debt. 

In addition, if actual commodity prices are less than our forecast we would not have enough cash to meet obligations as they become due. If this occurs we may suspend quarterly interest payments, restructure, amend or refinance existing debt through private options or seek a protected reorganization under chapter 11 of the U.S. federal bankruptcy code.

If we are unable to find strategic alternatives to our debt structure or restructure our current obligations under our existing outstanding debt and preferred stock instruments, and address near-term liquidity needs, we may need to seek relief under the U.S. Bankruptcy Code. This relief may include: (i) seeking bankruptcy court approval for the sale or sales of some, most or substantially all of our assets pursuant to section 363(b) of the U.S. Bankruptcy Code and a subsequent liquidation of the remaining assets in the bankruptcy case; (ii) pursuing a plan of reorganization (where votes for the plan may be solicited from certain classes of creditors prior to a bankruptcy filing) that we would seek to confirm (or “cram down”) despite any classes of creditors who reject or are deemed to have rejected such plan; or (iii) seeking another form of bankruptcy relief, all of which involve uncertainties, potential delays and litigation risks.

Under certain circumstances, it is also possible that our creditors may file an involuntary petition for bankruptcy against us.

All these factors raise substantial doubt about our ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

The following table sets forth certain information regarding our current directors and executive officers. Our executive officers serve one-year terms.

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Name	Age	Position	Board Committee(s)(1)
Robert G. Watson, Jr.	39	President, Chief Executive Officer, and Director	None
Ryan A. Lowe	35	Director, Senior Vice President of Corporate Development	Audit
James G. Miller	67	Director	Audit (Chairman)
Richard E. Menchaca	49	Director	GCNC (Chairman); Audit
Lance W. Helfert	42	Director	GCNC
Douglas M. Wright	63	Chief Financial Officer	None
David L. Kunovic	64	Executive Vice President	None
Kent A. Roach	50	Executive Vice President	None

⁽¹⁾ “Executive” means the Executive Committee of the Board of Directors. “GCNC” means the Governance, Compensation Nominating Committee of the Board of Directors. “Audit” means the Audit Committee of the Board of Directors.

Robert G. Watson, Jr.  Mr. Watson has served as President, Chief Executive Officer, and Secretary since December 31, 2010. Prior to joining EnerJex, he co-founded Black Sable Energy, LLC, approximately 5 years ago and served as its Chief Executive Officer. During his tenure at Black Sable, Mr. Watson was responsible for the company’s acquisition and development of two grassroots oil projects in South Texas, both of which were partnered with larger oil and gas companies on a promoted basis. Prior to founding Black Sable, he was a Senior Associate at American Capital, Ltd. (NASDAQ: ACAS), a publicly traded private equity firm and global asset manager with more than $100 billion of total assets under management. Mr. Watson began his career in the Energy Investment Banking Group at CIBC World Markets and subsequently founded and served as the Managing Partner of Centerra Energy Partners, LLC. Mr. Watson’s experience in acquiring and developing oil projects, his knowledge of financial markets, and his managerial and leadership abilities that he has demonstrated while serving as the Company’s President and Chief Executive Officer and as chief executive officer for Black Sable Energy, LLC, led to the board’s conclusion that he should serve as a director.

Ryan A. Lowe. Mr. Lowe served as Senior Vice President of Corporate Development since 2011, resigning this position on August 15, 2015. He has served as a Director since December 31, 2010. Mr. Lowe is the Chief Investment Officer of West Coast Asset Management, Inc., a registered investment advisor that has invested more than $200 million in the oil and gas industry on behalf of its principals and clients since 2000. He formerly served as a director and chairman of the audit committee for Black Raven Energy, Inc., before we acquired Black Raven in September 2013. Mr. Lowe is a CFA charterholder. His experience in business and finance and his experience as a director and chairman of the audit committee of a company in the oil and gas industry led to the board’s conclusion that he should serve as a director.

James G. Miller. Mr. Miller has served as a Director since December 31, 2010. Mr. Miller retired in 2002 after serving as the Chief Executive Officer of Utilicorp United, Inc.’s business unit responsible for the company’s electricity generation and electric and natural gas transmission and distribution businesses, which served 1.3 million customers in seven mid-continent states. Utilicorp traded on the New York Stock Exchange, and the company was renamed Aquila in 2002. In 2007, Utilicorp’s electricity assets in northwest Missouri were acquired by Great Plains Energy Incorporated (NYSE: GXP) for $1.7 billion, and its natural gas properties and other assets were acquired by Black Hills Corporation (NYSE: BKH) for $940 million. Mr. Miller joined Utilicorp in 1989 through its acquisition of Michigan Gas Utilities, for which he served as the president from 1983 to 1991. Mr. Miller also is a member of the board of directors of Guardian 8 Holdings. He currently serves as Chairman of The Nature Conservancy, Missouri Chapter, for which he has been a Trustee for the past 12 years. Mr. Miller’s experience as a chief executive officer and president, as well as his experience from serving as a board member, led to the board’s conclusion that he should serve as a director.

Lance W. Helfert. Mr. Helfert has served as a Director since December 31, 2010. Mr. Helfert is the President and a co-founder of West Coast Asset Management, Inc. (WCAM), a registered investment advisor located in Montecito, California. Prior to co-founding WCAM, he managed a portfolio at Wilshire Associates and was involved in a full range of financial strategies at M.L. Stern & Co. Mr. Helfert is a co-author of The Entrepreneurial Investor: The Art, Science and Business of Value Investing, a book published by John Wiley & Sons. He has been featured in Kiplinger’s Personal Finance, Forbes, Barron’s, Fortune Magazine, and the Market Watch for his unique market prospective. In addition, Mr. Helfert has been a frequent guest commentator on CNBC and the Fox Business networks. Mr. Helfert has also served on the board of directors for Junior Achievement of Southern California and the Tri-Counties Make-A-Wish Foundation. Mr. Helfert’s knowledge of the capital markets, coupled with his knowledge and understanding of finance and financial reporting led the board to conclude that he should serve as a director.

Richard E. Menchaca.  Mr. Menchaca has been a Director since June 6, 2013. Mr. Menchaca attended the University of Texas at Arlington where he received a BBA in Finance and pursued a MBA in Finance, and received a Graduate Degree from the SMU Southwestern School of Banking. Mr. Menchaca spent 18 years in the corporate banking industry with First Republic Bank (n.k.a. Bank of America), Bank One in Fort Worth and Fuji Bank, and Guaranty Bank in Houston. While at Guaranty Bank, Mr. Menchaca was one of the founding members of the Oil and Gas Banking Group, and within 18 months of its formation became the most profitable lending group within the bank with over $900,000,000 of loans to oil and gas industry. Mr. Menchaca was the principal and founder of Petras Energy, LLC, an oil and gas production company based in Midland, Texas. The company was successfully sold in January 2006. Mr. Menchaca has been the founder and principal of several privately owned oil and gas companies with operations in Texas, Oklahoma and Louisiana. Since May 2010, Mr. Menchaca currently presides as President and Chief Executive Officer of Petroflow Energy Corporation, a Tulsa-based exploration and production company, as well as a member of its board of directors since June 2009. Mr. Menchaca also serves as a director on the board of Fortis Plastics and a non-profit organization based in Houston, Texas.

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Douglas M. Wright. Mr. Wright has been Chief Financial Officer since August 2012. Mr. Wright served as Corporate Controller and Chief Accounting Officer of Nations Petroleum Company Ltd. from 2006 to August 2012. Prior to Nations, he served as a Manager of Financial Reporting for Noble Energy (contract). In 1996, he founded Fashion Investments Inc. and served as its Chief Executive Officer until 2005. Fashion Investments owned and operated the largest independent commercial laundry facility in Colorado Springs. From 1986 to 1996, Mr. Wright worked for Oryx Energy Company in various capacities including, Manager, Financial Reporting, Manager, Strategic Planning and General Auditor. From 1977 to 1986, he served as a Senior Manager with Deloitte & Touche. Mr. Wright is a Certified Public Accountant and earned his B.A. from the University of Pittsburgh and his MBA from the University of North Texas.

David L. Kunovic.  Mr. Kunovic joined Black Raven Energy, Inc. on October 1, 2010 as Vice President of Exploration managing all phases of geologic and geophysical exploration and development activity for the company. Mr. Kunovic has over 34 years of experience as an exploration geologist, including 11 years as President of Kachina Energy, Inc., managing geologic and geophysical projects for several independent oil companies. He has also held positions as Vice President of Exploration for Canyon Energy, Inc. from 1994 – 2000 managing all exploration activities for the Rocky Mountain region; Petroleum Incorporated from 1991 – 1994 as Exploration Manager for all US exploration; Newport Exploration from 1984 – 1991 as Exploration Manager Rocky Mountain region; Apache Corporation from 1980 – 1984 as Senior Geologist working the Powder River and Denver Basins and Union Texas Petroleum from 1978-1980 as geologist — Rocky Mountain Basins. Mr. Kunovic holds a Bachelor’s degree in Geology from the University of Colorado and also completed Masters level course work in Environmental Engineering and Groundwater at the University of Colorado.

Kent A. Roach.   Mr. Roach joined EnerJex in October 2014 as Executive Vice President of Engineering. In this role, Mr. Roach will focus on designing and executing a broad range of IOR and reservoir management related opportunities for both existing and future oil and gas assets. Additionally, he will provide technical guidance and oversight for multiple engineering and operational functions from an executive level. Prior to joining EnerJex, he worked primarily in reservoir engineering roles at Occidental, Exxon Mobil, and various other North American E&P companies. He has diverse subsurface experiences in reservoir simulation, geologic modeling, formation evaluation, pressure transient analysis, acquisitions and divestments, and reserve studies. His worldwide experience includes large-scale Middle East carbonate development planning, tight oil & gas deliverability and appraisal, unconventional shale plays, and exploration phase portfolio analysis. Mr. Roach holds a Bachelor of Science in Petroleum Engineering degree from the University of Missouri-Rolla.

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ITEM 11. EXECUTIVE COMPENSATION.

The following table sets forth summary compensation information for the fiscal year ended December 31, 2015, and the year ended December 31, 2014, for our chief executive officer, chief financial officer and other highly compensated executive officers. We refer to these persons as our named executive officers elsewhere in this report.

	Fiscal	Salary		Bonus		Stock Awards		Option Awards		All Other Compensation		Total
Name and Principal Position	Year	($)		($)		($)		($)		($)		($)
Robert G. Watson, Jr.
President, Chief Executive Officer	2015	$	225,000	$	—	$	—	$	—	$	—	$	225,000
	2014	$	225,000	$	—	$	—	$	76,900	$	—	$	301,900
Douglas M. Wright
Chief Financial Officer	2015	$	185,000	$	—	$	—	$	63,900	$	—	$	248,900
	2014	$	168,000	$	—	$	—	$	95,800	$	—	$	263,800
David L. Kunovic
Executive Vice President	2015	$	220,000	$	—	$	—	$	94,700	$	—	$	314,700
	2014	$	168,000	$	—	$	—	$	94,700	$	—	$	262,700
Kent A. Roach
Executive Vice President	2015	$	220,000	$	—	$	—		68,600	$	—		288,600
	2014	$	45,127	$	—	$	—	$	—	$	—		45,127
Ryan A. Lowe
Senior Vice President	2015	$	50,000	$	—	$	—	$	—	$	—	$	50,000
	2014	$	80,000	$	—	$	—	$	—	$	—	$	80,000

Equity Compensation Plans

We currently have three equity compensation plans, each of which has been approved by our stockholders. Any outstanding stock options issued under our prior equity compensation plans remain effective in accordance with their terms. Officers (including officers who are members of the board of directors), directors, employees and consultants are eligible to receive options under our stock option plans.

These plans are intended to encourage directors, officers, employees and consultants to acquire ownership of common stock. The opportunity so provided is intended to foster in participants a strong incentive to put forth maximum effort for our continued success and growth, to aid in retaining individuals who put forth such effort, and to assist in attracting the best available individuals in the future.

2000/2001 Stock Option Plan

The Board of Directors approved our 2000/2001 Stock Option Plan on September 25, 2000, and our stockholders ratified the plan.

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Summary of the 2000/2001 Stock Option Plan

Administration of Plan; Board Authority to Select Grantees and Determine Awards .  The Plan shall be administered by our board of directors. The Board shall have the power and authority to grant awards consistent with the terms of the Plan. The board may delegate this authority to a compensation committee of the board.

Stock Issuable Under the Plan; Mergers; Substitutions .  The total number of options that can be granted under the plan is 13,333 shares and all such shares were previously granted to the former chief executive officer, C. Stephen Cochennet. On August 3, 2009, we exchanged these outstanding options for 13,333 shares of restricted common stock. Therefore, all 13,333 shares reserved for issuance under this plan are available again for issuance.

Eligibility ..  Grantees under the Plan will be such officers, directors, full or part-time employees, and other key persons (including consultants and prospective employees) of us and our subsidiaries, if any, as are selected from time to time by the board in its sole discretion.

Stock Options.   Any stock option granted under the Plan shall be in such form as the board may from time to time approve. Stock options granted under the Plan may be non-qualified stock options or incentive stock options. Incentive stock options may be granted only to employees of us or any subsidiary that is a “subsidiary corporation” within the meaning of Section 424(f) of the Code.

Exercise Price .  Non-qualified stock options will be granted by the board of directors with an option price not less than 85% of the fair market value of the shares of common stock to which the non-qualified stock option relates on the date of grant. In no event may the option price with respect to an incentive stock option granted under the stock option plan be less than the fair market value of such common stock. However the price shall not be less than 110% of the fair market value per share on the date of the grant in the case of an individual then owning more than 10% of the total combined voting power of all classes of stock of the corporation.

Option Term .  Each option granted under the stock option plan will be assigned a time period for exercising not to exceed ten years after the date of the grant. Certain other restrictions will apply in connection with this plan when some awards may be exercised. Generally, all options under this plan terminate 90 days after a change of control if the option holder is terminated other than for cause.

Amendments and Termination .  The board may, at any time, amend or discontinue the Plan. We must obtain stockholder approval of any Plan amendment to the extent necessary and desirable to comply with Section 422 of the Internal Revenue Code or other applicable law, including the requirements of any exchange or quotation system on which our common stock is listed or quoted. Such plan amendments are subject to approval by our stockholders entitled to vote at a meeting of stockholders. We may not amend, alter, suspend, or terminate the Plan if doing so would impair the rights of any holder, unless both the holder and the Plan’s administrator agree in writing and sign the writing. The 2000 – 2001 Plan terminated on September 25, 2010, and no further options will be granted under this plan after that date.

The 2002 – 2003 Stock Option Plan/Stock Incentive Plan

The Board of Directors approved the EnerJex Resources, Inc. Stock Option Plan on August 1, 2002 (the “2002 – 2003 Stock Option Plan”). We had previously granted 15,900 options under this plan. On August 3, 2009, we exchanged all 15,900 outstanding options for 3,980 shares of our restricted common stock. In addition, we granted 10,116 shares of restricted common stock under the Stock Incentive Plan to employees for fiscal 2009 bonuses and 3,953 shares to our officers and directors for the prior rescission of stock options in fiscal 2008.

Summary of the 2002/2003 Stock Option Plan

Administration of Plan; Board Authority to Select Grantees and Determine Awards .  The Plan shall be administered by our board of directors. The Board shall have the power and authority to grant awards consistent with the terms of the Plan.

Stock Issuable Under the Plan .  Originally, the total number of options that could be granted under the 2002 – 2003 Stock Option Plan was not to exceed 26,666 shares. In September 2007, our stockholders approved a proposal to amend and restate the 2002 – 2003 Stock Option Plan to increase the number of shares issuable to 66,666. On October 14, 2008, our stockholders approved a proposal to amend and restate the 2002 – 2003 Stock Option Plan to (i) rename it the EnerJex Resources, Inc. Stock Incentive Plan (the “Stock Incentive Plan”), (ii) increase the maximum number of shares of our common stock that may be issued under the Stock Incentive Plan from 66,666 to 83,333, and (iii) add restricted stock as an eligible award that can be granted under the Stock Incentive Plan.

Eligibility ..  Grantees under the Plan will be such officers, directors, full or part-time employees, and other key persons (including consultants and prospective employees) of us and our subsidiaries, if any, as are selected from time to time by the board in its sole discretion.

Stock Options .  Any stock option granted under the Plan shall be in such form as the board may from time to time approve. Stock options granted under the Plan may be non-qualified stock options or incentive stock options. Incentive stock options may be granted only to employees of us or any subsidiary that is a “subsidiary corporation” within the meaning of Section 424(f) of the Code.

Exercise Price .  Non-qualified stock options will be granted by the committee with an option price equal to the fair market value of the shares of common stock to which the non-qualified stock option relates on the date of grant. The governance, compensation and nominating committee may, in its discretion, determine to price the non-qualified option at a different price. In no event may the option price with respect to an incentive stock option granted under the plans be less than the fair market value of such common stock to which the incentive stock option relates on the date the incentive stock option is granted. However the price of an incentive stock option will not be less than 110% of the fair market value per share on the date of the grant in the case of an individual then owning more than 10% of the total combined voting power of all of our classes of stock.

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Option Term .  Each option granted under the stock option plan will be assigned a time period for exercising not to exceed ten years after the date of the grant. Certain other restrictions will apply in connection with this plan when some awards may be exercised. Generally, all options under this plan terminate 90 days after a change of control if the option holder is terminated other than for cause.

Restricted Stock .  Restricted stock will have full dividend, voting and other ownership rights, unless otherwise indicated in the applicable award agreement pursuant to which it is granted. If any dividends or distributions are paid in shares of common stock during the restricted period, the applicable award agreement may provide that such shares will be subject to the same restrictions as the restricted stock with respect to which they were paid.

Amendments and Termination .  The board may, at any time, amend or discontinue the Plan. We must obtain stockholder approval of any Plan amendment to the extent necessary and desirable to comply with Section 422 of the Internal Revenue Code or other applicable law, including the requirements of any exchange or quotation system on which our common stock is listed or quoted. Such plan amendments are subject to approval by our stockholders entitled to vote at a meeting of stockholders. We may not amend, alter, suspend, or terminate the Plan if doing so would impair the rights of any holder, unless both the holder and the Plan’s administrator agree in writing and sign the writing. As amended, the 2002 – 2003 plan terminated on August 1, 2012, and no options will be granted under this plan after that date.

The 2013 Stock Incentive Plan

Our board of directors and stockholders have approved and adopted the EnerJex Resources, Inc., 2013 Stock Incentive Plan, which we refer to herein as the “Plan.”

Summary of the Plan

The following is a summary of certain principal features of the Plan.

Administration of Plan; Board Authority to Select Grantees and Determine Awards .  The Plan shall be administered by our board of directors. The Board shall have the power and authority to grant awards consistent with the terms of the Plan. The board may delegate this authority to a compensation committee of the board.

Stock Issuable Under the Plan; Mergers; Substitutions .  The number of shares of stock initially reserved and available for issuance under the Plan shall be 333,300 shares, subject to adjustment as provided in Section 3.1(b) of the Plan. Pursuant to Section 3.1(b), we will increase the number of shares reserved and set aside specially on each January 1 ^st by the lowest of the following: (i) five percent (5.0%) of the number of shares of stock issued and outstanding on the immediately preceding December 31 st , (ii) 33,333 shares, or (iii) such lesser number of shares as is determined by the board. For purposes of this limitation, the shares of stock underlying any awards that are forfeited, canceled, held back upon exercise of an option or settlement of an award to cover the exercise price or tax withholding, reacquired by us prior to vesting, satisfied without the issuance of stock or otherwise terminated (other than by exercise) shall be added back to the shares of stock available for issuance under the Plan. Subject to such overall limitations, shares of stock may be issued up to such maximum number pursuant to any type or types of award. The shares available for issuance under the Plan may be authorized but unissued shares of stock or shares of stock reacquired by us.

Eligibility ..  Grantees under the Plan will be such officers, directors, full or part-time employees, and other key persons (including consultants and prospective employees) of us and our subsidiaries, if any, as are selected from time to time by the board in its sole discretion.

Stock Options .  Any stock option granted under the Plan shall be in such form as the board may from time to time approve. Stock options granted under the Plan may be non-qualified stock options or incentive stock options. Incentive stock options may be granted only to employees of us or any subsidiary that is a “subsidiary corporation” within the meaning of Section 424(f) of the Code.

Exercise Price .  The exercise price per share for the stock covered by a stock option shall be determined by the board at the time of grant but shall not be less than 100% of the fair market value on the date of grant. In the case of an incentive stock option that is granted to a 10% owner, the option price of such Incentive stock option shall be not less than 110% of the fair market value on the grant date.

Option Term .  The term of each stock option shall be fixed by the board, but no stock option shall be exercisable more than 10 years after the date the stock option is granted. In the case of an incentive stock option that is granted to a 10% owner, the term of such stock option shall be no more than 5 years from the date of grant.

Unrestricted and Restricted Stock Awards .  The board may, in its sole discretion, grant (or sell at par value or such higher purchase price determined by the board) an unrestricted stock Award or restricted stock award under the Plan. Unrestricted stock awards and restricted stock awards may be granted in respect of past services or other valid consideration, or in lieu of cash compensation due to such grantee.

Amendments and Termination .  The board may, at any time, amend or discontinue the Plan. We must obtain stockholder approval of any Plan amendment to the extent necessary and desirable to comply with Section 422 of the Internal Revenue Code or other applicable law, including the requirements of any exchange or quotation system on which our common stock is listed or quoted. Such plan amendments are subject to approval by our stockholders entitled to vote at a meeting of stockholders. We may not amend, alter, suspend, or terminate the Plan if doing so would impair the rights of any holder, unless both the holder and the Plan’s administrator agree in writing and sign the writing. The 2013 plan terminates on June 6, 2023, and no options will be granted under this plan after that date.

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Employment Agreements

Robert G. Watson, Jr. — Chief Executive Officer

On December 31, 2014, the Company entered into a second amended and restated employment agreement with Robert G. Watson, Jr. as Chief Executive Officer of the Company for a three-year period commencing December 31, 2014. The employment agreement provides (i) an annual base salary of $225,000 for 2015, $285,000 for 2016 and $300,000 for 2017, (ii) a target bonus of up to 40% of the annual base salary. Due to low commodity prices, Mr. Watson deferred payment of a portion of his 2016 salary of $285,000 until such time as current economic conditions and world commodity prices improve. His 2016 remuneration has continued at the 2015 level. The difference between $285,000 and his 2015 salary of $225,000 will be accrued by the Company as a liability.

Douglas M. Wright — Chief Financial Officer

On August 15, 2012, EnerJex and Douglas M. Wright, entered into an Employment Agreement pursuant to which we will employ Mr. Wright as our chief financial officer, (ii) we will pay to Mr. Wright base compensation of $140,000 plus such discretionary cash bonus as our chief executive officer determines to be appropriate, and (iii) if we terminate Mr. Wright’s employment without “Cause” (as defined in the Employment Agreement), then we will pay to Mr. Wright $35,000 as severance pay after six (6) months of employment.

Termination Under the Equity Plans

Under our 2000/2001 Stock Option Plan, if the person receiving the option (the optionee) ceases to be employed by us for any reason other than for disability or cause, the optionee’s options will expire not later than 3 months afterwards. During this 3 month period and prior to the time the option expires under the terms of the option, the optionee may exercise any option that we have granted to him, but only to the extent that the options were exercisable on the date of termination of his employment. Unless exercised during this period, these options will expire at the end of the 3 month period unless the options are to terminate sooner under the terms and conditions of the option. The decision as to whether a termination for a reason other than disability, cause or death has occurred is made by the board of directors, whose decision shall be final and conclusive. If an optionee ceases to be employed by us for reason of disability, the optionee’s options will expire not later than 1 year after the date that he or she is terminated. During this 1 year period and prior to the expiration of the option under its terms, the optionee may exercise any option granted to him, but only to the extent that the options were exercisable on the date of termination of his employment because of his or her disability. Except as so exercised, optionee’s options will expire at the end of the 1 year period unless the options are to terminate sooner under the terms and conditions of the option. The decision as to whether a termination by reason of disability has occurred is determined by the board.

Under our Amended and Restated 2002 – 2003 Stock Option Plan, if an optionee ceases to be employed by, or ceases to have a relationship with us for any reason other than for disability or cause, the optionee’s options will expire not later than three 3 months thereafter. During the three month period and prior to the expiration of the option by its terms, the optionee may exercise any option granted to him, but only to the extent such options were exercisable on the date of termination of his employment or relationship and except as so exercised, such options shall expire at the end of such three month period unless such options by their terms expire before such date. The decision as to whether a termination for a reason other than disability, cause or death has occurred are made by the governance, compensation and nominating committee, whose decision shall be final and conclusive, except that employment shall not be considered terminated in the case of sick leave or other bona fide leave of absence approved by us.

Under our 2013 Plan, if the optionee ceases to be employed by us for any reason other than for death, disability or cause, the optionee’s options will expire not later than 3 months afterwards. During this 3 month period and prior to the time the option expires under the terms of the option, the optionee may exercise any option that we have granted to him, but only to the extent that the options were exercisable on the date of termination of his employment. Unless exercised during this period, these options will expire at the end of the 3 month period unless the options are to terminate sooner under the terms and conditions of the option. The decision as to whether a termination for a reason other than disability, cause or death has occurred is made by the board of directors, whose decision shall be final and conclusive. If an optionee ceases to be employed by us for reason of death or disability, the optionee’s options will expire not later than 180 days after the date that he or she is terminated. During this 180 day period and prior to the expiration of the option under its terms, the optionee may exercise any option granted to him, but only to the extent that the options were exercisable on the date of termination of his employment because of his or her disability. Except as so exercised, optionee’s options will expire at the end of the 180 day period unless the options are to terminate sooner under the terms and conditions of the option. The decision as to whether a termination by reason of disability has occurred is determined by the board.

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Termination Under the Employment Agreements

Termination Without Cause or Disability, Including a Change in Control

Under Mr. Watson’s employment agreement, if Mr. Watson is terminated not for cause or disability, we will pay (A) if the termination occurred before a change of control as described in the Employment Agreement, the continuation of his base compensation for 12 months, and (B) if that termination occurs after a change of control, the continuation of the base compensation for 24 months.

Under Mr. Wright’s employment agreement, if Mr. Wright is terminated not for cause or disability, we will pay Mr. Wright all accrued and unpaid wages, including for accrued and unused vacation time and any special bonus accrued through the date of termination. If Mr. Wright is terminated after February 15, 2014, he will also receive an additional sum of $35,000.

Termination Because of Disability

Under Mr. Watson’s and Mr. Wright’s employment agreements, if the employee is terminated because of disability, he is entitled to receive all accrued and unpaid wages, including for accrued and unused vacation time and any special bonus accrued through the date of termination.

Option Exercises for Fiscal 2015 and 2014

There were no options exercised by our Named Executive Officers in fiscal year 2015 and 2014.

 Outstanding Equity Awards at 2015 Fiscal Year-End

The following table lists the outstanding equity incentive awards held by our named executive officers as of the fiscal year ended December 31, 2015.

	Option Awards
		Number of		Number of		Number of
		Securities		Securities		Securities
		Underlying		Underlying		Underlying
		Unexercised		Unexercised		Unexercised		Option
		Options		Options		Unearned		Exercise		Option
	Fiscal	Exercisable		Un-exercisable		Options		Price		Expiration
	Year	(#)		(#)		(#)		($)		Date
Robert G. Watson, Jr.	2011		60,000		—		60,000	$	6.00	12/31/2015
Douglas M. Wright	2012		50,000		—		50,000	$	10.50	12/31/2022
David L. Kunovic	2013		37,500		12,500		50,000	$	10.50	12/31/2023
Kent A. Roach	2014		27,083		22,917		50,000	$	10.50	12/31/2019

Option Exercises for fiscal 2015

There were no options exercised by our named executive officers in 2015. See “Securities Authorized for Issuance under Equity Compensation Plans” for a description of our outstanding equity compensation plans.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

 The following table presents information, to the best of our knowledge, about the ownership of our common stock on December 31, 2015 relating to those persons known to beneficially own more than 5% of our capital stock and by our directors and executive officers. The percentage of beneficial ownership for the following table is based on 8,423,936 shares of outstanding common stock.

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Beneficial ownership is determined in accordance with the rules of the Securities and Exchange Commission and does not necessarily indicate beneficial ownership for any other purpose. Under these rules, beneficial ownership includes those shares of common stock over which the stockholder has sole or shared voting or investment power. It also includes shares of common stock that the stockholder has a right to acquire within 60 days after December 31, 2015 pursuant to options, warrants, conversion privileges or other right. The percentage ownership of the outstanding common stock, however, is based on the assumption, expressly required by the rules of the Securities and Exchange Commission, that only the person or entity whose ownership is being reported has converted options or warrants into shares of EnerJex’s common stock.

			Percent of Outstanding
Name and Address of Beneficial Owner   (1)	Number of Shares		Shares of Common Stock  (2)
Robert G. Watson, Jr., CEO/President and Director (3)		326,667		3.9	%
Ryan A. Lowe, Director (4)(5)		142,626		1.7	%
Lance W. Helfert, Director (4)(5)		317,606		3.8	%
James G. Miller, Director		154,956		1.8	%
Richard E. Menchaca, Director		10,032		0.1	%
Montecito Venture Partners, LLC (4)
1205 Coast Village Road
Montecito, California 93108		128,925		7.0	%
Douglas M. Wright, Chief Financial Officer		70,000		0.8	%
David L. Kunovic, Executive Vice President		45,911		0.5	%
Kent A. Roach, Executive Vice President		29,164		0.3	%
Alpha Capital Anstalt (6)
Pradafant 7, Furstentums 9490
Vaduz, Liechtenstein		832,259		9.9	%
Natalie Orfalea		981,191		11.6	%
Paul Orfalea		981,191		11.6	%
Newman Family Trust		536,118		6.4	%
Directors, Officers and Beneficial Owners as a Group				54.1	%

(1)	As used in this table, “beneficial ownership” means the sole or shared power to vote, or to direct the voting of, security, or the sole or shared investment power with respect to a security (i.e., the power to dispose of, or to direct the disposition of, a security).  The address of each person is care of the Registrant, 4040 Broadway, Suite 508, San Antonio, Texas 78209.
(2)	Figures are rounded to the nearest tenth of a percent.
(3)	Includes 266,667 shares held by RGW Energy, LLC, of which Mr. Watson is the sole member, and 60,000 shares under an option granted to Mr. Watson to purchase 60,000 shares of common stock at $6.00 per share.
(4)	Montecito Venture Partners, LLC is a controlled affiliate of West Coast Asset Management, Inc. Includes 6,745 shares of Series A Preferred Stock that is convertible into 6,745 shares of the Registrant’s common stock. Ryan A. Lowe and Lance W. Helfert are the Managers of Montecito Venture Partners, LLC, which directly owns all of the shares listed opposite its name in the table above. Each Reporting Person disclaims beneficial ownership of all securities reported herein, except to the extent of their pecuniary interest therein, if any, and this report shall not be deemed an admission that such Reporting Person is the beneficial owner of the shares for purposes of Section 16 of the Securities and Exchange Act of 1934 or for any other purposes.
(5)	Includes 128,925 owned by Montecito Venture Partners, LLC.
(6)	Includes 68,712 shares of our common stock issuable upon the exercise of warrants that are exercisable within 60 days held by Alpha Capital Anstalt (“ACA”). Does not include (a) 939,169 shares of our common stock issuable upon the exercise of warrants held by ACA, which warrants contain a customary 9.9% blocker provision and, thus, are not exercisable within 60 days, and (b) 1,701,716 shares of our common stock issuable upon the conversion of 1,242.17099 shares of our Series B Preferred Stock held by ACA, which preferred shares also contain a 9.9% blocker and, thus, are not convertible within 60 days. Based solely on a Schedule 13G filed with the SEC by ACA on March 16, 2015, ACA has sole voting power with respect to this common stock. Konrad Ackerman is the managing member of ACA and as such has voting and investment power over the securities owned by selling stockholder. Mr. Ackerman disclaims beneficial ownership over these shares.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

We describe below transactions and series of similar transactions that have occurred during this fiscal year ended December 31, 2015 to which we were a party or will be a party in which:

· The amounts involved exceeds the lesser of $120,000 or one percent of the average of our total assets at year end for the last two completed fiscal years ($535,000); and

· A director, executive officer, holder of more than 5% of our common stock or any member of their immediate family had or will have a direct or indirect material interest.

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Director Independence

Under the corporate governance requirements of companies whose shares are listed for trading on the NYSE MKT, at least a majority of the members of the board of directors of each listed company must be “independent.” The EnerJex board of directors has determined that three of the five current directors — James G. Miller, Richard Menchaca, and Lance W. Helfert — are “independent directors” under the NYSE MKT listing requirements. The NYSE MKT listing requirements provide a non-exclusive list of persons who are not considered independent. For example, under these rules, a director who is, or during the past three years was, employed by the Company or by any parent or subsidiary of the company, other than prior employment as an interim chairman or chief executive officer, would not be considered independent. No director qualifies as independent unless the EnerJex board of directors affirmatively determines that the director does not have a material relationship with the company that would interfere with the exercise of independent judgment. In making an affirmative determination that a director is an “independent director,” the EnerJex board of directors reviewed and discussed information provided by these individuals and by EnerJex with regard to each of their business and personal activities as they may relate to EnerJex and its management.

Board of Directors’ Meetings, Committees, Directors’ Compensation and Nominations

The EnerJex board of directors held 6 meetings during 2015. All of EnerJex’s directors attended 75% or more of the aggregate meetings of the EnerJex board of directors and all committees on which they served during 2015. Directors are encouraged, but not required, to attend the annual meetings of EnerJex’s stockholders.

Audit Committee and Financial Expert

The primary responsibilities of the audit committee include:

• overseeing the combined company’s accounting and financial reporting processes, systems of internal control over financial reporting and disclosure controls and procedures on behalf of the board of directors and reporting the results or findings of its oversight activities to the board;

• having sole authority to appoint, retain and oversee the work of our independent registered public accounting firm and establishing the compensation to be paid to the independent registered public accounting firm;

• establishing procedures for the receipt, retention and treatment of complaints regarding accounting, internal accounting controls and/or or auditing matters and for the confidential, anonymous submission by employees of concerns regarding questionable accounting or auditing matters;

• reviewing and pre-approving all audit services and permissible non-audit services to be performed for the Company by its independent registered public accounting firm as provided under the federal securities laws and rules and regulations of the SEC; and

• overseeing our system to monitor and manage risk, and legal and ethical compliance programs, including the establishment and administration (including the grant of any waiver from) a written code of ethics applicable to each of the combined company’s principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions.

The audit committee will have the authority to engage the services of outside experts and advisors as it deems necessary or appropriate to carry out its duties and responsibilities.

Our audit committee consists of Mr. Miller, and Mr. Menchaca. The board of directors has determined that each member of the audit committee qualifies as “independent” for purposes of membership on audit committees pursuant to the NYSE MKT listing requirements and the rules and regulations of the SEC and is able to read and understand Fundamental Financial Statements as required by the NYSE MKT listing requirements. In addition, the board of directors has determined that Mr. Miller qualifies as an “audit committee financial expert” as defined by the rules and regulations of the SEC.

The audit committee met five times during the fiscal year ended December 31, 2015.

A copy of the audit committee charter is available on EnerJex’s website www.enerjex.com.

Governance, Compensation and Nominating Committee

The primary responsibilities of the Governance, Compensation and Nominating Committee include:

· recommending to the board of directors for its determination the special salaries, incentive compensation, long-term incentive compensation, special or supplemental benefits or perquisites and any and all other compensation applicable to our chief executive officer and other executive officers;

· reviewing and making recommendations to the board of directors regarding any revisions to corporate goals and objectives with respect to compensation for the company’s chief executive officer and other executive officers and establishing and leading a process for the full board of directors to evaluate the performance of our chief executive officer and other executive officers in light of those goals and objectives;

· administering our equity-based compensation plans applicable to any employee of the Company and recommending to the board of directors specific grants of options and other awards for all executive officers and determining specific grants of options and other awards for all other employees, under the company’s equity-based compensation plans;

· reviewing and discussing with the chief executive officer and reporting periodically to the board of directors plans for executive officer development and corporate succession plans for the chief executive officer and other key executive officers and employees;

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· specially reviewing and discussing with management the “Executive Compensation” and “Director Compensation” sections of our proxy statement in connection with our annual meeting of stockholders and based on such review and discussions making a recommendation to the board of directors as to whether the “Executive Compensation” and “Director  Compensation” sections should be included in our proxy statement in accordance with applicable rules and regulations of the SEC and any other applicable regulatory bodies;

· identifying individuals qualified to become board members;

· recommending director nominees for each annual meeting of the stockholders and director nominees to fill any vacancies that may occur between meetings of stockholders;

· being aware of the best practices in corporate governance and developing and recommending to the board of directors a set of corporate governance standards to govern the board of directors, its committees, the company and its employees in the conduct of the business and affairs of the company;

· developing and overseeing the special board and board committee evaluation process; and

· establishing and leading a process for determination of the compensation applicable to the non-employee directors on the board.

The governance, compensation and nominating committee has the authority to engage the services of outside experts and advisors as it deems necessary or appropriate to carry out its duties and responsibilities.

The governance, compensation and nominating committee consists of Mr. Menchaca, Mr. Miller and Mr. Helfert.

Stockholder Communications with the Board of Directors

Stockholders who wish to communicate with the board or a particular director may send a letter to the secretary of EnerJex at: 4040 Broadway, Suite 508, San Antonio, Texas 78209. The mailing envelope must contain a clear notation indicating that the enclosed letter is a “Stockholder-Board Communication” or “Stockholder-Director Communication.” All such letters must identify the author as a stockholder and clearly state whether the intended recipients are all members of the board or just certain specified individual directors. The secretary will make copies of all such letters and circulate them to the appropriate director or directors.

Board Leadership Structure and Role in Risk Oversight

The board of directors does not have a separate risk oversight body. Instead, the EnerJex board has overall responsibility for risk oversight, including, as part of regular board and committee meetings, general oversight of executives’ management of risks relevant to us. In overseeing risks, the board seeks to understand the material risks, including financial, competitive, and operational risks, we face and the steps management is taking to manage those risks. It also has the responsibility for understanding what level of risk is appropriate. The board of directors reviews our business strategy and determines what constitutes an appropriate level of risk for EnerJex.

While the full EnerJex board has overall responsibility for risk oversight, the board has delegated oversight responsibility related to certain risks to its two committees. The audit committee, under its charter, has been delegated the responsibility of reviewing and discussing with management our major financial risk exposures and the steps that management has taken to monitor and control such exposures (including management’s risk assessment and risk management policies). EnerJex’s governance, compensation and nominating committee is responsible for considering risks within its areas of responsibility. The board does not believe that our compensation policies encourage excessive risk-taking, as the compensation plans are designed to align our employees with short- and long-term corporate strategy. Generally, our equity awards vest over several years, which the board has determined encourages our employees to act with regard to the long term interest of EnerJex and to focus on sustained stock price appreciation.

The board’s role in risk oversight has not had any effect on the board’s leadership structure.

Code of Ethics

EnerJex has adopted a code of business conduct and ethics that applies to all of its directors, officers and employees, as well as to directors, officers and employees of each subsidiary of EnerJex. A copy of the code of business conduct and ethics is available on EnerJex’s website at www.enerjex.com . If any substantive amendments are made to the code of business conduct and ethics or if EnerJex’s grants any waiver, including any implicit waiver, from a provision of the code to any of its officers and directors, EnerJex will satisfy any disclosure requirements of Form 8-K by disclosing the nature of such amendment or waiver on its website at www.enerjex.com ..

Limitation of Liability of Directors

Pursuant to the Nevada General Corporation Law, EnerJex’s amended and restated articles of incorporation exclude personal liability for its directors for monetary damages based upon any violation of their fiduciary duties as directors, except as to liability for any breach of the duty of loyalty, acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, or any transaction from which a director receives an improper personal benefit. This exclusion of liability does not limit any right which a director may have to be indemnified and does not affect any director’s liability under federal or applicable state securities laws. EnerJex has agreed to indemnify its directors against expenses, judgments, and amounts paid in settlement in connection with any claim against a director if he acted in good faith and in a manner he believed to be in EnerJex’s best interests.

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Director Compensation

The following table sets forth summary compensation information for the fiscal year ended December 31, 2015 for each of our non-employee directors.

	Fees Earned		Stock		Option		All Other
	or Paid in Cash		Awards		Awards  (2)		Compensation		Total
Name	$		$		$		$		$
James G. Miller	$	-	$	-	$	6,800	$	-	$	6,800
Lance W. Helfert	$	-	$	-	$	-	$	-	$	-
Richard E. Menchaca	$	-	$	-	$	6,800	$	-	$	6,800

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

RBSM, LLP served as our principal independent public accountants for fiscal 2015 and 2014. Aggregate fees billed to us for the fiscal years ended December 31, 2015 and 2014 were as follows:

	Year Ended December 31, 2015		Year Ended December 31, 2014
Audit Fees (1)	$	91,800	$	140,512
Audit-Related Fees (2)	$	20,500	$	—
Tax fees (3)	$	—	$	—
All Other Fees	$	—	$	—
Total fees of our principal accountant	$	112,300	$	140,512

(1) Audit Fees include fees billed and expected to be billed for services performed to comply with Generally Accepted Auditing Standards (GAAS), including the reviews of the quarterly financial statements included in the Quarterly Reports on Form 10-Q filed with the Securities and Exchange Commission. This category also includes fees for audits provided in connection with statutory filings or procedures related to audit of income tax provisions and related reserves, consents and assistance with and review of documents filed with the SEC.

(2) Audit-Related Fees include fees for services associated with assurance and reasonably related to the performance of the audit or review of our financial statements. This category includes fees related to assistance in financial due diligence related to mergers and acquisitions, consultations regarding Generally Accepted Accounting Principles, reviews and evaluations of the impact of new regulatory pronouncements, general assistance with implementation of Sarbanes-Oxley Act of 2002 requirements and audit services not required by statute or regulation.

(3) Tax fees consist of fees related to the preparation and review of our federal and state income tax returns.

Audit Committee Policies and Procedures

Our Board of Directors pre-approves all services to be provided to us by our independent auditor. This process involves obtaining (i) a written description of the proposed services, (ii) the confirmation of our Principal Financial Officer that the services are compatible with maintaining specific principles relating to independence, and (iii) confirmation from our securities counsel that the services are not among those that our independent auditors have been prohibited from performing under SEC rules. After engaging in this process, the members of the Board of Directors determined to approve or disapprove the engagement of the auditors for the proposed services. In fiscal 2015 and 2014, all fees paid to RBSM, LLP were unanimously pre-approved in accordance with this procedure.

Report of the Audit Committee

Our Audit Committee submits the following report:

The Audit Committee retains and oversees the Company’s independent registered public accountants, discusses and reviews with management accounting policies and financial statements, evaluates external and internal audit performance, investigates complaints and other allegations of fraud or misconduct by the Company’s management and employees and evaluates policies and procedures. The Audit Committee operates under a written charter adopted by the Board. The remainder of this report relates to certain actions taken by the Audit Committee in fulfilling its roles as they relate to ascertaining the independence of our registered public accountants and recommending the inclusion of the Company’s financial statements in its special report.

During fiscal 2015 and 2014, the Audit Committee discussed with the Company’s independent registered public accounting firm the overall scope and plans for their audit. The Audit Committee also met periodically with the independent registered public accounting firm to discuss the results of their examinations, the overall quality of the Company’s financial reporting and their evaluations of its internal controls.

The Audit Committee of the Board has received from the Company’s independent registered public accounting firm, written disclosures and the letter required by the Independence Standards Board’s Standard No. 1, “Independence Discussions with Audit Committees,” that discloses all relationships between the Company and RBSM, LLP that may be thought to bear on the independence of RBSM, LLP from the Company. The Audit Committee has discussed with the firm the contents of the written disclosure and letter as well as the matters required to be discussed by Statement on Auditing Standards No. 114. The Audit Committee has reviewed and discussed the audited financial statements of the Company for the years ended December 31, 2015 and 2014, with the Company’s management, which has primary responsibility for the financial statements.

52 

In addition, the Audit Committee has received the written disclosures and the letter from RBSM, LLP required by relevant professional and regulatory standards and has discussed with the firm their independence from the Company and its management. In concluding that RBSM, LLP was independent for their respective audit periods, the Audit Committee considered, among other factors, whether the non-audit services provided by the firm were compatible with its independence.

Based on the reviews and discussions referred to above, we recommended to the Board of Directors that the Company’s audited financial statements be included in its report on Form 10-K for the fiscal year ended December 31, 2015 and 2014.

The foregoing report is furnished by the Audit Committee of the Board.

James G. Miller (Chairman)
Richard Menchaca

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

The following information required under this item is filed as part of this report:

1. Financial Statements

	Page
Management Responsibility for Financial Information	37
Management’s Report on Internal Control Over Financial Reporting	37
Index to Financial Statements	F-1
Report of Independent Registered Public Accounting Firms	F-2
Consolidated Balance Sheets	F-4
Consolidated Statements of Operations	F-5
Consolidated Statements of Stockholders Equity	F-6
Consolidated Statements of Cash Flows	F-7

2. Financial Statement Schedules

None.

3. Exhibit Index

Exhibit No.	Description
2.1	Agreement and Plan of Merger between Millennium Plastics Corporation and Midwest Energy, Inc. filed on August 16, 2006.
2.2	Agreement and Plan of Merger by and among Registrant, BRE Merger Sub, Inc., Black Raven Energy, Inc. and West Coast Opportunity Fund, LLC dated July 23, 2013 (incorporated herein by reference to Exhibit 10.4 on Form 8-K filed July 29, 2013).
3.1	Amended and Restated Articles of Incorporation, as currently in effect (incorporated by reference to Exhibit 3.1 to the Form 10-Q filed on August 14, 2008)

53 

3.2	Amended and Restated Bylaws, as currently in effect (incorporated by reference to Appendix C to Schedule 14A filed on June 6, 2013)
3.3	Certificate of Amendment of Articles of Incorporation as filed with the Nevada Secretary of State on  May 29, 2014 (incorporated herein by reference as Exhibit 3.1 on Current Report Form 8-K filed on May 29, 2014)
3.4	Certificate of Amendment of Articles of Incorporation (incorporated by reference as Exhibit 3.1 on Current Report Form 8-K filed on May 29, 2014)
3.5	Amended and Restated Certificate of Designation for Series A Preferred Stock (incorporated by reference to Exhibit 4.6 to the Form S-1/A filed on June 3, 2014)
3.6	Certificate of Designation of Preferences, Rights and Limitations of Series B Convertible Preferred Stock (incorporated herein by reference as Exhibit 4.1 on Current Report Form 8-K filed on March 11, 2015)
4.1	Specimen common stock certificate (incorporated by reference to Exhibit 4.3 to the Form S-1/A filed on May 27, 2008)
4.2	Specimen Series A Preferred Stock Certificate (incorporated by reference to Exhibit 4.4 to the Form S-1/A filed on June 3, 2014)
4.3	Specimen Series B Convertible Preferred Stock Certificate (incorporated herein by reference as Exhibit 4.2 on Current Report Form 8-K filed on March 11, 2015)
4.4	Certificate of Designation for Series A Preferred Stock (incorporated by reference to Exhibit 4.1 to the Form 8-K filed on January 6, 2011).
4.5	Form of Warrant to Purchase Common Stock (incorporated herein by reference as Exhibit 4.3 on Current Report Form 8-K filed on March 11, 2015)
4.6	Form of Placement Agent Warrant (incorporated herein by reference as Exhibit 4.4 on Current Report Form 8-K filed on March 11, 2015)
10.1	Form of Officer and Director Indemnification Agreement (incorporated by reference to Exhibit 10.2 to the Form 8-K filed on October 16, 2008)
10.2	Amendment 4 to Joint Exploration Agreement effective as of November 6, 2008 between MorMeg, LLC and EnerJex Resources, Inc.  (incorporated by reference to Exhibit 10.15 to the Form 10-K filed July 14, 2009)
10.3	Amendment 5 to Joint Exploration Agreement effective as of December 31, 2009 between MorMeg LLC and EnerJex Resources, Inc. (incorporated by reference to Exhibit 10.15 to the Form 10-Q filed on February 16, 2010)
10.4	Amendment 6 to Joint Exploration Agreement effective as of March 31, 2010 between MorMeg LLC and EnerJex Resources, Inc. (incorporated by reference to Exhibit 10.24 to the Form 10-K filed on July 15, 2010)
10.5	Amended and Restated EnerJex Resources, Inc. Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on October 16, 2008)
10.6	Joint Development Agreement between EnerJex Resources, Inc. and Haas Petroleum, LLC dated December 31, 2010 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on January 27, 2011).
10.7	Joint Operating Agreement between EnerJex Resources, Inc. and Haas Petroleum, LLC and MorMeg, LLC dated December 31, 2010 (incorporated by reference to Exhibit 10.2 to the Form 8-K filed on January 27, 2011).
10.8	Amended and Restated Credit Agreement dated October 3, 2011 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on October 6, 2011).
10.9	Option and Joint Development Agreement by and among Registrant and MorMeg, LLC dated August 2011 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on November 15, 2011).
10.10	First Amendment to Amended and Restated Credit Agreement dated December 14, 2011 (incorporated herein by reference to Exhibit 10.2 on Form 8-K filed on December 14, 2011).
10.11	Second Amendment to Amended and Restated Credit Agreement dated August 31, 2012 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on November 8, 2012).
10.12	Third Amendment to Amended and Restated Credit Agreement dated November 2, 2012 (incorporated herein by reference to Exhibit 10.2 on Form 8-K filed on November 8, 2012).
10.13	Amended and Restated Employment Agreement by and among Registrant and Robert G. Watson, Jr. dated December 31, 2012 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on January 4, 2013).
10.14	Fourth Amendment to Amended and Restated Credit Agreement by and among Registrant and Texas Capital Bank dated December 31, 2012 (incorporated herein by reference to Exhibit 10.2 on Form 8-K filed on January 30, 2013).
10.15	First Amendment to Amended & Restated Mortgage Security Agreement, Financing Statement and Assignment of Production by and among Working Interest, LLC and Texas Capital Bank dated December 31, 2012 (incorporated herein by reference to Exhibit 10.3 on Form 8-K filed on January 30, 2013).
10.16	Mortgage, Security Agreement, Financing Statement and Assignment of Production and Revenues by and among Working Interest, LLC and Texas Capital Bank dated December 31, 2012 (incorporated herein by reference to Exhibit 10.4 on Form 8-K filed on January 30, 2013).
10.17	2013 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.1 on Registration Statement on Form S-8 filed on June 12, 2013)
10.18	Fifth Amendment to Amended and Restated Credit Agreement by and among Registrant and Texas Capital Bank, N.A. dated September 30, 2013 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed October 1, 2013).
10.19	Sixth Amendment to Amended and Restated Credit Agreement by and among Registrant and Texas Capital Bank, N.A. dated November 19, 2013 (incorporated by reference to Exhibit 10.37 on Form 10-Q filed May 13, 2014).
10.20	Exchange Agreement between EnerJex Resources, Inc. and holders of Series A preferred stock (incorporated by reference to Exhibit 10.38 on Form S-1/A Amendment No. 2 filed June 3, 2014).

54 

10.21	Seventh Amendment to Amended and Restated Credit Agreement by and among Registrant and Texas Capital Bank, N.A. dated May 22, 2014 (incorporated by reference to Exhibit 10.1 to Form 8-K filed May 27, 2014).
10.22	Form of Securities Purchase Agreement dated as of March 11, 2015 (incorporated herein by reference as Exhibit 10.1 on Current Report Form 8-K filed on March 11, 2015)
10.23	Eighth Amendment to Amended and Restated Credit Agreement by and among Registrant and Texas Capital Bank, N.A. dated August 13, 2014 (incorporated by reference as Exhibit 10.23 on Form 10-K filed March 31, 2015).
10.24	Ninth Amendment to Amended and Restated Credit Agreement by and among Registrant and Texas Capital Bank, N.A. dated April 29, 2015 (incorporated by reference to Exhibit 10.1 to Form 8-K filed May 5, 2015).
10.25	Purchase Agreement by and among Registrant and Northland Securities, Inc. dated May 8, 2015 (incorporated by reference as Exhibit 1.1 of Form 8-K filed May 8, 2015.)
10.26	Tenth Amendment to the Amended and Restated Credit Agreement by and among Registrant and Texas Capital Bank, N.A. dated September 8, 2015 (incorporated by reference to Exhibit 10.26 of Form 10-Q filed November 16, 2015).
10.27	Eleventh Amendment to Amended and Restated Credit Agreement by and among Registrant and Texas Capital Bank, N.A. dated November 16, 2015 (incorporated by reference to Exhibit 10.1 to Form 8-K filed November 16, 2015).
10.28	Forbearance Agreement dated April 4, 2016*
21.1	Subsidiaries*
23.1	Consent of Cobb & Associates, Inc.*
23.2	Consent of MHA Petroleum Consultants, LLC*
23.3	Cobb & Associates Letter Report dated February 29, 2016*
23.4	MHA Petroleum Consultants Letter Report dated January 22, 2016*
24.1	Power of Attorney (included with signatures).*
31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002*
31.2	Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
32.1	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
32.2	Certificate of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
101.INS	XBRL Instance Document*
101.SCH	XBRL Taxonomy Extension Schema Document*
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document*
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document*
101.LAB	XBRL Taxonomy Extension Label Linkbase Document*
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document*

* Filed herewith.

55 

SIGNATURES

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

ENERJEX RESOURCES, INC.
By:	/s/ Robert G. Watson, Jr.
	Robert G. Watson, Jr., Chief Executive Officer
Date: April 11, 2016

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

Name	Title	Date
/s/ Robert G. Watson, Jr.	President, Chief Executive Officer,	April 11, 2016
Robert G. Watson, Jr.	(Principal Executive Officer), Secretary and Director
/s/ Douglas M. Wright	Chief Financial Officer (Principal Financial Officer)	April 11, 2016
Douglas M. Wright
/s/ Ryan A. Lowe	Director and Senior Vice President of Corporate Marketing	April 11, 2016
Ryan A. Lowe
/s/ Lance W. Helfert	Director	April 11, 2016
Lance Helfert
/s/ James G. Miller	Director	April 11, 2016
James G. Miller
/s/ Richard E. Menchaca	Director	April 11, 2016
Richard E. Menchaca

56 

Index to Financial Statements

	Page
Index to Financial Statements	F-1
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets at December 31, 2015 and December 31, 2014	F-3
Consolidated Statements of Operations for the Year Ended December 31, 2015 and December 31, 2014	F-4
Consolidated Statement of Stockholders’ (Deficit) Equity for the Year Ended December 31, 2015 and December 31, 2014	F-5
Consolidated Statement of Cash Flows for the Year Ended December 31, 2015 and December 31, 2014	F-6
Notes to Consolidated Financial Statements	F-7

F-1

 

Report of Independent Registered Public Accounting Firm

To The Board of Directors and Stockholders of

EnerJex Resources Inc.

We have audited the accompanying consolidated balance sheets of EnerJex Resources Inc. (“The Company”) as of December 31, 2015 and 2014, and the related consolidated statements of operations, stockholders’ deficiency, for the years ended December 31, 2015 and 2014. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatements. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included 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 on 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 financial statements, 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 financial statements referred to above present fairly, in all material respects, the financial position of EnerJex Resources Inc., as of December 31, 2015 and 2014 and the results of its operations, and its cash flows for the years ended December 31, 2015 and 2014 in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming that the Company is a going concern. As discussed in Note 2 of the financial statements, the Company failed to make the mandatory monthly borrowing base reduction payment on April 1, 2016. This factor raises substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to the matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

RBSM, LLP

New York, New York

April 11, 2016

Las Vegas, NV   Kansas City, MO   Houston, TX   New York, NY   Washington DC

Mumbai, India   Athens, Greece   San Francisco, CA   Beijing, China

Member ANTEA INTERNATIONAL with offices worldwide

F-2

EnerJex Resources, Inc. and Subsidiaries

Consolidated Balance Sheets

	December 31,
	2015			2014
Assets
Current Assets:
Cash	$	3,101,682		$	805,524
Accounts receivable		977,488			1,278,509
Derivative receivable		2,531,401			3,736,005
Inventory		144,327			248,218
Marketable securities		210,990			1,018,573
Deposits and prepaid expenses		247,325			324,339
Total current assets		7,213,213			7,411,168
Non-current assets:
Fixed assets, net of accumulated depreciation of $1,658,073 and $1,945,607		1,995,010			2,404,703
Oil & gas properties using full cost accounting, net of accumulated DD&A of $14,935,386 and $13,827,347		11,706,939			64,263,272
Derivative receivable		-			985,746
Other non-current assets		919,239			993,207
Total non-current assets		14,621,188			68,646,928
Total assets	$	21,834,401		$	76,058,096
Liabilities and Stockholders’ (Deficit) Equity
Current liabilities:
Accounts payable	$	1,142,842		$	3,042,835
Accrued liabilities		1,131,057			1,060,926
Current portion of long term debt		1,986,660			35,595
Total current liabilities		4,260,559			4,139,356
Non-Current Liabilities:
Asset retirement obligation		3,091,478			2,906,093
Long-term debt		16,625,000			23,011,660
Other long-term liabilities		390,937			-
Total non-current liabilities		20,107,415			25,917,753
Total liabilities		24,367,974			30,057,109
Commitments and Contingencies
Stockholders’ (Deficit) Equity:
10% Series A Cumulative Redeemable Perpetual Preferred Stock, $.001 par value, 25,000,000 shares authorized; shares issued and outstanding and 938,248 at December 31, 2015 and 751,815 at December 31, 2014		938			752
Series B Convertible Preferred stock, $.001 par value, 1,764 shares authorized, issued and outstanding at December 31, 2015		2			-
Common stock, $0.001 par value, 250,000,000 shares authorized; shares issued and outstanding – 8,423,936 at December 31, 2015 and 7,643,114 at December 31, 2014		8,424			7,643
Accumulated other comprehensive income		-			(552,589	)
Paid in capital		68,848,944			63,825,998
Accumulated deficit		(71,391,881	)		(17,280,817	)
Total stockholders’ (deficit) equity		(2,533,573	)		46,000,987
Total liabilities and stockholders’ (deficit) equity	$	21,834,401		$	76,058,096

See Notes to Consolidated Financial Statements.

F-3

EnerJex Resources, Inc. and Subsidiaries

Consolidated Statements of Operations

	Year Ended December 31,
	2015			2014
Crude oil revenues	$	4,525,089		$	13,257,608
Natural gas revenues		353,633			1,035,759
Total revenues		4,878,722			14,293,367
Expenses:
Direct operating costs		4,501,940			6,762,248
Depreciation, depletion and amortization		1,311,446			3,549,245
Impairment of oil and gas assets		48,930,087			-
Professional fees		680,860			987,229
Salaries		1,927,552			1,479,688
Administrative expense		636,459			790,572
Total expenses		57,988,344			13,568,982
Income from operations		(53,109,622	)		724,385
Other income (expense):
Interest expense		(1,293,407	)		(1,305,194	)
Gain (loss) on mark to market of derivative contracts		(2,194,679	)		6,073,960
Other income (loss)		4,675,854			(919,527	)
Total other income (expense)		1,187,768			3,849,239
(Loss) income before provision for income taxes		(51,921,854	)		4,573,624
Provision for income taxes		-			-
Net (loss) income	$	(51,921,854	)	$	4,573,624
Net (loss) income	$	(51,921,854	)	$	4,573,624
Preferred dividends		(1,798,274	)		(1,392,035	)
Net (loss) income attributable to common stockholders	$	(53,720,128	)	$	3,181,589
Net (loss) income per common share basic and diluted		(6.50	)		0.42
Weighted Average Shares		8,265,716			7,492,007

See Notes to Consolidated Financial Statements.

F-4

 EnerJex Resources, Inc. and Subsidiaries

Consolidated Statement of Stockholders’ Equity

																											Total
																			Accumulated								Stockholders’
																			Other								Equity EnerJex
	10% Series A Preferred Stock				Series B Preferred Stock				Preferred Stock						Common Stock				Comprehensive			Paid In		Retained			Resources
	Shares		Amount		Shares		Amount		Shares			Amount			Shares		Amount		Income			Capital		Deficit			Inc.
Balance, January 1, 2014			$				$			4,779,460		$	4,780			7,307,158	$	7,307	$	(552,589	)	$	49,913,509	$	(20,462,406	)	$	28,910,601
Stock issued for services																17,332		17					234,637					234,654
Stock based compensation																							326,579					326,579
Issuance of 10% series A cumulative preferred stock and retirement of legacy preferred stock		751,815		752						(4,779,460	)		(4,780	)		318,624		319					13,351,273					13,347,564
Payment of preferred stock dividends																									(1,392,035	)		(1,392,035	)
Net income for the year																									4,573,624			4,573,624
Balance, December 31, 2014		751,815		752						-			-			7,643,114		7,643		(552,589	)		63,825,998		(17,280,817	)		46,000,987
Dividend received from Oakridge Energy																				552,589								552,589
Stock issued for services		3000		3												17,500		18					23,979					24,000
Stock based compensation																							396,124					396,124
Sale of common stock																763,322		763					824,643					825,506
Sale of series A preferred stock		183,433		183																			2,014,410					2,014,593
Sale of series B preferred stock						1764		2															1,763,790					1,763,792
Preferred stock dividends																									(2,189,210	)		(2,189,210	)
Net loss for the year																									(51,921,854	)		(51,921,854	)
Balance, December 31, 2015		938,248	$	938		1,764	$	2		0		$	0			8,423,936	$	8,424	$	0		$	68,848,944	$	(71,391,881	)	$	(2,533,573	)

See Notes to Consolidated Financial Statements.

F-5

EnerJex Resources, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

	Year Ended December 31,
	2015			2014
Cash flows from operating activities
Net (loss) income	$	(51,921,854	)	$	4,573,624
Depreciation, depletion and amortization		1,311,446			3,549,245
Impairment of oil and gas assets		48,930,087			-
Stock, options and warrants issued for services		420,103			638,171
Accretion of asset retirement obligation		257,712			255,836
Settlement of asset retirement obligations		(2,244	)		(102,930	)
(Gain) loss on derivatives		2,190,350			(6,073,101	)
Loss on sale of fixed assets		13,661			9,738
Adjustments to reconcile net (loss) income (used in) provided by operating activities:
Accounts receivable		301,021			1,183,237
Inventory		103,891			(9,424	)
Deposits and prepaid expenses		77,014			(27,282	)
Accounts payable		(1,899,993	)		618,826
Accrued liabilities		70,131			(1,973,941	)
Cash flows (used in) provided by operating activities		(148,675	)		2,641,999
Cash flows from investing activities
Purchase of fixed assets		(7,876	)		(298,903	)
Oil and gas properties additions		(251,821	)		(7,095,865	)
Sale of oil and gas properties		2,867,305			987,939
Proceeds from sale of fixed assets		33,142			1,250
Dividend received from Oakridge Energy		1,360,172			-
Cash flows provided by (used in) investing activities		4,000,922			(6,405,579	)
Cash flows from financing activities
Proceeds from sale of stock		4,603,812			13,347,564
Repayments of long-term debt		(4,935,595	)		(14,035,595	)
Borrowings on long-term debt		500,000			5,500,000
Preferred stock dividends paid		(1,798,274	)		(1,392,035	)
Deferred financing costs		73,968			(159,026	)
Cash flows (used in) provided by financing activities		(1,556,089	)		3,260,908
Increase (decrease) in cash and cash equivalents		2,296,158			(502,672	)
Cash and cash equivalents, beginning		805,524			1,308,196
Cash and cash equivalents, end	$	3,101,682		$	805,524
Supplemental disclosures:
Interest paid	$	840,513		$	741,757
Income taxes paid	$	-		$	-
Non-cash investing and financing activities:
Share-based payments issued for services	$	420,103		$	638,171
Preferred dividends payable	$	390,936		$	-

See Notes to Consolidated Financial Statements.

F-6

EnerJex Resources, Inc.

Notes to Consolidated Financial Statements

Note 1 - Summary of Accounting Policies

Basis of Presentation

Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States. Our operations are considered to fall within a single industry segment, which are the acquisition, development, exploitation and production of crude oil and natural gas properties in the United States.  Our consolidated financial statements include our wholly owned subsidiaries.

All significant intercompany balances and transactions have been eliminated upon consolidation.  Certain reclassifications have been made to the prior year financial statements to conform to the current year presentation. 

Nature of Business

We are an independent energy company engaged in the business of producing and selling crude oil and natural gas. The crude oil and natural gas is obtained primarily by the acquisition and subsequent exploration and development of mineral leases.  Development and exploration may include drilling new exploratory or development wells on these leases. These operations are conducted primarily in Kansas, Colorado, Nebraska and Texas.

Use of Estimates in the Preparation of Financial Statements

The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.  Significant estimates included in the consolidated financial statements are: (1) oil and gas revenues and reserves; (2) depreciation, depletion and amortization; (3) valuation allowances associated with income taxes (4) accrued assets and liabilities; (5) stock-based compensation; (6) asset retirement obligations, (7) valuation of derivative instruments and (8) impairment of oil and gas assets.  Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates.  Actual results could differ from those estimates.

Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear any interest.  We regularly review receivables to insure that the amounts will be collected and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method.  Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.

Inventory

Inventories are comprised of crude oil held in storage and materials and supplies used in field operations. Crude oil inventories are valued at lower of cost or market, on a first-in, first out basis. Material and supplies are valued at lower of cost or market, based upon specific cost or by using a weighted average cost.

Share-Based Payments

The value we assign to the options and warrants that we issue is based on the fair market value as calculated by the Black-Scholes pricing model. To perform a calculation of the value of our options and warrants, we determine an estimate of the volatility of our stock.  We need to estimate volatility because there has not been enough trading of our stock to determine an appropriate measure of volatility. We believe our estimate of volatility is reasonable, and we review the assumptions used to determine this whenever we issue new equity instruments.

F-7

Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before the tax returns or when income items are recognized in the tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Deferred tax liabilities arise when income items are recognized in the financial statements before the tax returns or when expenses are recognized in the tax return prior to the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted.

We routinely assess the reliability of our deferred tax assets.  If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset is reduced by a valuation allowance.  In addition we routinely assess uncertain tax positions, and accrue for tax positions that are not more-likely-than-not to be sustained upon examination by taxing authorities.

Uncertain Tax Positions

We follow guidance in Topic 740 of the Codification for its accounting for uncertain tax positions. Topic 740 prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, we determine whether it is more-likely-than-not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based solely on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement.

We have no liability for unrecognized tax benefits recorded as of December 31, 2015 and 2014. Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the consolidated statement of operations or consolidated balance sheet as of December 31, 2015. In addition, we do not believe that there are any positions for which it is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase or decrease within the next twelve months. We recognize related interest and penalties as a component of income tax expense.

Tax years open for audit by federal tax authorities as of December 31, 2015 are the years ended December 31, 2012, 2013 and 2014. Tax years ending prior to 2012 are open for audit to the extent that net operating losses generated in those years are being carried forward or utilized in an open year.

Fair Value Measurements

Accounting guidance establishes a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and creates a fair value hierarchy that prioritizes the information used to develop those assumptions.  Additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy.  We incorporate a credit risk assumption into the measurement of certain assets and liabilities.

Cash and Cash Equivalents

We consider all highly liquid investment instruments purchased with original maturities of three months or less to be cash equivalents for purposes of the consolidated statements of cash flows and other statements. We maintain cash on deposit, which, can exceeds federally insured limits. We have not experienced any losses on such accounts and believe we are not exposed to any significant credit risk on cash and equivalents.

Revenue Recognition

Oil and gas revenues are recognized net of royalties when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collection of the revenue is probable. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met.

Fixed Assets

Property and equipment are recorded at cost. At December 31, 2015, Fixed Assets consisted of vehicles of $354,886, furniture and equipment of $552,288, building and leasehold improvements of $23,069 and gathering and compression systems of $2,722,839 as well as accumulated depreciation of vehicles $328,659, accumulated depreciation of furniture and fixtures of $478,578, accumulated depreciation of building and leasehold improvements of $13,342 and accumulated depreciation of gathering and compression systems of $837,494.

At December 31, 2014, Fixed Assets consisted of vehicles $967,483, furniture and equipment of $608,061, building and leasehold improvements of $23,069 and gathering and compression systems of $2,751,697, as well as accumulated depreciation of vehicles of $697,042, accumulated depreciation of furniture and fixtures of $494,333, accumulated depreciation of building and leasehold improvements of $9,386 and accumulated depreciation of gathering and compression systems of $744,846. 

Depreciation is determined by the use of the straight-line method of accounting using the estimated lives of the assets (3-15 years).  Expenditures for maintenance and repairs are charged to expense.

F-8

Debt issue costs

Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt utilizing the straight-line method of amortization over the estimated life of the debt.

Oil & Gas Properties and Long-Lived Assets

We follow the full cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities.

Proved properties are amortized using the units of production method (UOP). Currently we only have operations in the United States of America. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the cost of these reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (DD&A), estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs, less related salvage value. 

The cost of unproved properties are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed into service. Geological and geophysical costs not associated with specific properties are recorded as proved property immediately. Unproved properties are reviewed for impairment quarterly.

Impairment of long-lived assets is recorded when indications of impairment are present. Impairment is indicated when the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying value.  The carrying value of the assets is then reduced to their estimated fair value that is measured based on an estimate of future discounted cash flows.

Under the full-cost-method of accounting, the net book value of oil and gas properties, less deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is (a) the present value of future net revenues computed by applying current prices of oil & gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil & gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of 10 percent and assuming continuation of existing economic conditions plus (b) the cost of properties not being amortized plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized less (d) income tax effects related to differences between book and tax basis of properties. Future cash outflows associated with settling accrued retirement obligations are excluded from the calculation. Estimated future cash flows are calculated using end-of-period costs and an un-weighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months held flat for the life of the production, except where prices are defined by contractual arrangements.

Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the statement of operations. The ceiling calculation is performed quarterly. For the year ended December 31, 2015 impairments of $16,401,376, $11,421,613, $9,720,983 and $11,386,115 were record in the first, second, third and fourth quarters respectively. For the year ended December 31, 2014 there were no impairments resulting from the quarterly ceiling tests.

Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25%) of our reserve quantities are sold, in which case a gain or loss is recognized in income. In 2015 the Company sold its Cherokee project assets located in Eastern Kansas for net proceeds of $2,867,305. At the time of the sale the reserve quantities made up approximately 6.7% of total reserve quantities. Accordingly, the net proceeds reduced the carrying value of our oil and gas properties.

Asset Retirement Obligations

The asset retirement obligation relates to the plug and abandonment costs when our wells are no longer useful. We determine the value of the liability by obtaining quotes for this service and estimate the increase we will face in the future. We then discount the future value based on an intrinsic interest rate that is appropriate for us. If costs rise more than what we have expected there could be additional charges in the future, however, we monitor the costs of the abandoned wells and we will adjust this liability if necessary.

Major Purchasers

For the years ended December 31, 2015, and 2014 we sold our produced crude oil to ARM Energy Management, LLC, Coffeyville Resources Inc., Plains Marketing, L.P., MV Purchasing and Sunoco Logistics Inc. on a month-to-month basis and we sold our produced natural gas to United Energy Trading and Western Operating Company.

Marketable Securities Available for Sale

The Company classifies its marketable equity securities as available-for-sale and they are carried at fair market value, with the unrealized gains and losses included in accumulated other comprehensive income and reported in stockholders’ equity. The difference between historical cost and market totaled $552,589 for the year ended December 31, 2014. For the year ended December 31, 2015 the Company received a dividend of $1,360,172. This receipt of cash was first applied to the other comprehensive loss reported in stockholders’ equity and then to the carrying value of the security reported in current assets. This resulted in a new carrying value of $210,990 for this security. The Company expects future distributions and estimates that the sum of future distributions to be in excess of the remaining book value.

F-9

Net Income Per Common Share

Basic net income per share is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect, in periods in which they have a dilutive effect, the impact of common shares issuable upon exercise of stock options and warrants and conversion of convertible debt that are not deemed to be anti-dilutive. The dilutive effect of the outstanding stock options and warrants is computed using the treasury stock method.

For the year ended December 31, 2015, diluted net loss per share did not include the effect of 298,664 shares of common stock issuable upon the exercise of outstanding stock options as their effect would be anti-dilutive.

For the year ended December 31, 2014, diluted net income per share did not include the effect of 231,332 shares of common stock issuable upon the exercise of outstanding stock options as their exercise price was above market value.

Reclassifications

Certain reclassifications have been made to prior periods to conform to current presentations.

Recent Accounting Pronouncements Applicable to the Company

The Company does not believe there are any recently issued, but not yet effective; accounting standards that would have a significant impact on the Company’s financial position or results of operations.

Note 2 - Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern.

On October 3, 2011, the Company, entered into an Amended and Restated Credit Agreement with Texas Capital Bank, and other financial institutions and banks (“TCB” or “Bank”) that may become a party to the Credit Agreement from time to time. The facilities provided under the Amended and Restated Credit Agreement was to be used to refinance a prior outstanding revolving loan facility with TCB dated July 3, 2008, and for working capital and general corporate purposes. On August 15, 2014 the Company entered into an Eighth Amendment to the Amended and Restated Credit Agreement. Among other things the Eighth Amendment extended the maturity of the Agreement by three years to October 3, 2018. On August 12, 2015, the Company entered into a Tenth Amendment to the Amended and Restated Credit Agreement. Among other things the Tenth Amendment established the requirement of monthly borrowing base reductions commencing September 1, 2015 and continuing on the first of each month thereafter.

On April 1, 2016 the Company informed the Bank that it would cease making the mandatory monthly borrowing base reduction payments and did not make the required April 1, 2016 payment. The Company made its mandatory quarterly interest payment on April 6, 2016 and on April 7, 2016 entered into a Forbearance Agreement whereby the Bank agreed to not exercise remedies and rights afforded it under the Amended and Restated Credit Agreement for thirty days. The thirty day period will be used by the Company to pursue strategic alternatives.

The Company accesses a number of data bases and utilizes several consultants to monthly prepare commodity price projections used in its cash forecasting models. The models indicate it will have sufficient cash to satisfy obligation as they become due through the end of the first quarter of 2017, if it ceases to make the principle reduction called for by the Tenth Amendment entered into by the Company on August 12, 2015. If actual commodity prices are less than forecasted the Company would not have enough cash to meet obligations as they become due. Should this occur the Company could suspend quarterly interest payments, restructure, amend or refinance existing debt through private options or seek a protected reorganization under chapter 11 of the U.S. federal bankruptcy code.

This factor raises substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Note 3 - Equity Transactions

Stock transactions in fiscal year ended December 31, 2015

On March 13, 2015, the Company issued in a registered offering 763,547 registered shares of its common stock together with 1,242.17099 shares of its newly designated Series B Convertible Preferred Stock (the “Preferred Stock”) convertible into 709,812 shares of common stock. We also issued in an unregistered offering, 521.62076 shares of Preferred Stock convertible into 298,069 shares of common stock, and warrants to purchase 1,771,428 shares of its common stock. The shareholder’s ability to convert a portion of the Preferred Stock and to exercise the warrant are restricted: (i) prior to the Company obtaining approval of the offering by its shareholders, which we expect to obtain before May 31, 2015, and (ii) pursuant to customary “blocker” provisions restricting the investor’s ownership to 9.99% of our outstanding common stock.

The Preferred Stock has a liquidation preference of $1,000 per share, and will be convertible at the option of the shareholder at a conversion ratio equal to approximately 571 shares of common stock for each one (1) share of Preferred Stock, subject to customary adjustments and anti-dilution price protection. Dividends are payable on the shares of Preferred Stock only if and to the extent that dividends are payable on the common stock into which the Preferred Stock is convertible. The Preferred Stock has no maturity date and can be redeemed by the Company beginning twelve months after the closing of the offering or upon a change of control. Each warrant will be exercisable for one share of common stock, for a period of five years beginning nine months after March 13, 2015, at a cash exercise price of $2.75 per share, and may be exercised on a cashless basis after that nine-month period if no effective registration statement covers the warrant shares by that time.

On May 13, 2015, the Company sold 183,433 shares of its 10% Series A Cumulative Redeemable Perpetual Preferred Stock at $12.50 per share for gross proceeds of approximately $2.3 million. The Company intends to use the net proceeds of this offering for general corporate purposes, including capital expenditures, working capital, preferred stock dividends, and repayment of outstanding borrowings under its senior credit facility.

The offering was made pursuant to a registration statement on Form S-3 (File No. 333-199030) previously filed and declared effective by the U.S. Securities and Exchange Commission (SEC). 

Stock transactions in fiscal year ended December 31, 2014

In 2014, 7,707 shares were issued to employees of the Company as compensation. The value of those shares was $59,298. Also in 2014, 9,625 shares were issued and 17,500 shares are owed (but not issued) for professional services rendered on behalf of the Company. The value of those share was $175,356.

Effective after the close of trading in EnerJex common stock on May 30, 2014, the Company affected a 1-for-15 reverse stock split, by which each share of EnerJex common stock was reclassified, and changed into 1/15^th of a fully paid and non-assessable share of common stock. In lieu of fractions of a share, the Company paid to holders of fractions of a share cash equal to $11.25 per share, which was the minimum value designated in the amended and restated certificate of designations affecting the reverse stock split.

On June 16, 2014, we adopted the Amended and Restated Certificate of Designation modifying the terms of our then-existing Series A preferred stock. Concurrently with filing of that Amended and Restated Certificate of Designation, the holders of our existing Series A preferred stock exchanged each outstanding share of such existing Series A preferred stock for (i) a number of shares of our common stock into which such Series A preferred stock was then convertible immediately prior to the exchange (318,630 shares in the aggregate), and (ii) 112,658 shares of Series A preferred stock which was equal to the quotient determined by dividing (x) that portion of the holder’s original Series A preferred stock purchase price that had not yet been paid in dividends, by (y) $23.75.

F-10

On June 20, 2014, we closed an underwritten initial public offering of 639,157 shares of our Series A preferred stock at a purchase price of $23.75 per share for gross proceeds of $15,179,938. Costs associated with the offering were $1,832,374 for net proceeds of $13,347,564.

Effective September 30, 2014 the Board of Directors approved the retirement of 383,333 shares in held in the Treasury. Accordingly $2,551,000 was reclassified to Paid-in capital.

Option transactions

Officers (including officers who are members of the Board of Directors), directors, employees and consultants are eligible to receive options under our stock option plans.  We administer the stock option plans and we determine those persons to whom options will be granted, the number of options to be granted, the provisions applicable to each grant and the time periods during which the options may be exercised.  No options may be granted more than ten years after the date of the adoption of the stock option plans.

Each option granted under the stock option plans will be exercisable for a term of not more than ten years after the date of grant.  Certain other restrictions will apply in connection with the plans when some awards may be exercised.  In the event of a change of control (as defined in the stock option plans), the vesting date on which all options outstanding under the stock option plans may first be exercised will be accelerated.  Generally, all options terminate 90 days after a change of control. 

Stock Incentive Plan

The Board of Directors approved the EnerJex Resources, Inc. Stock Option Plan on August 1, 2002 (the “2002-2003 Stock Option Plan”). Originally, the total number of options that could be granted under the 2002-2003 Stock Option Plan was not to exceed 26,666 shares. In September 2007 our stockholders approved a proposal to amend and restate the 2002-2003 Stock Option Plan to increase the number of shares issuable to 66,666.  On October 14, 2008 our stockholders approved a proposal to amend and restate the 2002-2003 Stock Option Plan to (i) rename it the EnerJex Resources, Inc. Stock Incentive Plan (the “Stock Incentive Plan”), (ii) increase the maximum number of shares of our common stock that may be issued under the Stock Incentive Plan to 83,333, and (iii) add restricted stock as an eligible award that can be granted under the Stock Incentive Plan.

On December 31, 2010 we granted 60,000 options that vest ratably over a 48 month period and are exercisable at $6.00 per share to an Officer of the company. The term of the options is 5 years. The fair value of the options as calculated using the Black-Scholes model was $307,751.  The amount recognized as expense for the year ended December 31, 2015 was zero and for the year ended December 31, 2014 was $76,938.

2013 Stock Incentive Plan

The Board and stockholders approved the adoption of the 2013 Stock Incentive Plan (“Plan”). The Plan reserves 333,300 shares of our common stock for the granting of options and issuance of restricted shares to our employees, officers, directors, and consultants. The Plan increases reserved shares annually based on plan provisions.

In 2015, we granted 67,332 options to employees and directors.  Fifty percent of these options vest one year after the date of the grant.  The remaining options vest ratably each month over a two year period.   The fair value of the option on the date of the grant calculated using the Black-Scholes model was $295,932 using the following weighted average assumptions: exercise price of $9.85 per share; common stock price of ranging from $.30 to $2.00 per share; volatility ranging from 70% to 72%; term of three years; dividend yield of 0%; interest rate of 1.41%. 

In 2014, we granted 2,367 options to employees. Thirty-three percent of these options vest one year after the date of the grant.   The remaining options vest ratably each month over a two year period.   The fair value of the option on the date of the grant calculated using the Black-Scholes model was $12,178 using the following weighted average assumptions: exercise price of $10.50 per share; common stock price of $7.95 per share; volatility of 72%; term of three years; dividend yield of 0%; interest rate of .47%.

We expensed $374,433 and $420,103 for the years ended December 31, 2014 and December 31, 2015 respectively for options granted. We also expensed $76,938 for the year ended December 31, 2014 for options recorded as prepaid assets.

F-11

A summary of stock options is as follows:

				Weighted Ave.					Weighted Ave.
	Options			Exercise Price			Warrants		Exercise Price
Outstanding January 1, 2014		231,133		$	9.36				$
Granted		2,367			10.50
Cancelled		(2,168	)		(10.50	)
Exercised		-			-			-		-
Outstanding December 31, 2014		231,332		$	9.33			-	$	-
Granted		67,332						1,904,286		2.75
Cancelled		(10,333	)		(10.50	)		-		-
Exercised								-		-
Outstanding December 31, 2015		288,331		$	10.17			1,904,286	$	2.75

The number of options that were vested at December 31, 2015 was 231,629. The number of options that were not vested at December 31, 2015 was 56,702.

Note 4 - Asset Retirement Obligation

Our asset retirement obligations relate to the abandonment of oil and gas wells. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, inflation rates and credit adjusted risk-free interest rates. The following shows the changes in asset retirement obligations:

Asset retirement obligations, January 1, 2014	$	2,687,801
Liabilities incurred during the period		65,385
Liabilities settled during the year		(102,929	)
Accretion		255,836
Asset retirement obligations, December 31, 2014	$	2,906,093
Release of liabilities associated with the sale of oil properties		(70,083	)
Liabilities settled during the year		(2,244	)
Accretion		257,712
Asset retirement obligations, December 31, 2015	$	3,091,478

F-12

Note 5 - Long-Term Debt

Senior Secured Credit Facility

On October 3, 2011, the Company, DD Energy, Inc., EnerJex Kansas, Inc., Black Sable Energy, LLC and Working Interest, LLC (“Borrowers”) entered into an Amended and Restated Credit Agreement with Texas Capital Bank, and other financial institutions and banks that may become a party to the Credit Agreement from time to time. The facilities provided under the Amended and Restated Credit Agreement are to be used to refinance Borrowers prior outstanding revolving loan facility with Bank, dated July 3, 2008, and for working capital and general corporate purposes.

At our option, loans under the facility will bear stated interest based on the Base Rate plus Base Rate Margin, or Floating Rate plus Floating Rate Margin (as those terms are defined in the Credit Agreement). The Base Rate will be, for any day, a fluctuating rate per annum equal to the higher of (a) the Federal Funds Rate plus 0.50% and (b) the Bank’s prime rate. The Floating Rate shall mean, at Borrower’s option, a per annum interest rate equal to (i) the Eurodollar Rate plus Eurodollar Margin, or (ii) the Base Rate plus Base Rate Margin (as those terms are defined in the Amended and Restated Credit Agreement). Eurodollar borrowings may be for one, two, three, or six months, as selected by the Borrowers. The margins for all loans are based on a pricing grid ranging from 0.00% to 0.75% for the Base Rate Margin and 2.25% to 3.00% for the Floating Rate Margin based on the Company’s Borrowing Base Utilization Percentage (as defined in the Amended and Restated Credit Agreement).

We entered into a First Amendment to Amended and Restated Credit Agreement and Second Amended and Restated Promissory Note in the amount of $50,000,000 with Texas Capital Bank, which closed on December 15, 2011. The Amendment reflects the addition of Rantoul Partners, as an additional Borrower and adds as additional security for the loans the assets held by Rantoul Partners.

On August 31, 2012, we entered into a Second Amendment to Amended and Restated Credit Agreement with Texas Capital Bank. The Second Amendment: (i) increased the borrowing base to $7,000,000 (ii) reduced the minimum interest rate to 3.75% and (iii) added additional new leases as collateral for the loan.

On November 2, 2012, we entered into a Third Amendment to Amended and Restated Credit Agreement with Texas Capital Bank. The Third Amendment (i) increased the borrowing base to $12,150,000 and (ii) clarified certain continuing covenants and provided a limited waiver of compliance with one of the covenants so clarified for the fiscal quarter ended December 31, 2011.

On January 24, 2013, we entered into a Fourth Amendment to Amended and Restated Credit Agreement, which was made effective as of December 31, 2012 with Texas Capital Bank.  The Fourth Amendment reflects the following changes: (i) the Bank consented to the restructuring transactions related to the dissolution of Rantoul Partners, and (ii) the Bank terminated a Limited Guaranty, as defined in the Credit Agreement, executed by Rantoul Partners in favor of the Bank

On April 16, 2013, the Bank increased our borrowing base to $19.5 million.

On September 30, 2013, the Company entered into a Fifth Amendment to the Amended and Restated Credit Agreement.   The Fifth Amendment reflects the following changes:  (i) an expanded principal commitment amount of the Bank to $100,000,000; (ii) increased the Borrowing Base to $38,000,000; (iii) added Black Raven Energy, Inc. to the Credit Agreement as borrower parties; (iv) added certain collateral and security interests in favor of the Bank; and (v) reduced the Company’s current interest rate to 3.30%.

On November 19, 2013, we entered into a Sixth Amendment to the Amended and Restated Credit Agreement. The Sixth Amendment reflects the following changes: (i) the addition of Iberia Bank as a participant in our credit facility, and (ii) a technical correction to our covenant calculations.

On May 22, 2014, we entered into a Seventh Amendment to the Amended and Restated Credit Agreement. The Seventh Amendment reflects the Bank’s consent to our issuance of up to 850,000 shares of our 10% Series A Cumulative Redeemable Perpetual Preferred Stock.

On August 15, 2014 we entered into an Eighth Amendment to the Amended and Restated Credit Agreement. The Eighth Amendment reflects the following changes: (i) the borrowing base was increased from $38 million to $40 million, and (ii) the maturity of the facility was extended by three years to October 3, 2018.

On April 29, 2015, we entered into a Ninth Amendment to the Amended and Restated Credit Agreement. In the Ninth Amendment, the Banks (i) re-determined the Borrowing Base based upon the recent Reserve Report dated January 1, 2015, (ii) imposed affirmative obligations on the Company to use a portion of proceeds received with regard to future sales of securities or certain assets to repay the loan, (iii) consented to non-compliance by the Company with certain terms of the Credit Agreement, (iv) waived certain provisions of the Credit Agreement, and (v) agreed to certain other amendments to the Credit Agreement.

On May 1, 2015, the Borrowers and the Banks entered into a Letter Agreement to clarify that up to $1,000,000 in proceeds from any potential future securities offering will be unencumbered by the Banks’ Liens as described in the Credit Agreement through November 1, 2015, and that, until November 1, 2015, such proceeds shall not be subject to certain provisions in the Credit Agreement prohibiting the Company from declaring and paying dividends that may be due and payable to holders of securities issued in such potential offerings or issued prior to the Letter Agreement.

On August 12, 2015, we entered into a Tenth Amendment to the Amended and Restated Credit Agreement. The Tenth Amendment reflects the following changes: (i) allow the Company to sell certain oil assets in Kansas, (ii) allow for approximately $1,300,000 of the proceeds from the sale to be reinvested in Company owned oil and gas projects and (iii) apply not less than $1,500,000 from the proceed of the sale to outstanding loan balances.

On November 13, 2015, the Company entered into a Eleventh Amendment to the Amended and Restated Credit Agreement. The Eleventh Amendment reflects the following changes: (i) waived certain provisions of the Credit Agreement, (ii) suspend certain hedging requirements, and (iii) to make certain other amendments to the Credit Agreement.

Our current borrowing base is $18,600,000, of which we had borrowed $18,600,000 as of December 31, 2015. The interest rate on amounts borrowed under our credit facility during 2015 was approximately 4.3% and for the year ended December 31, 2014, the interest rate on amounts borrowed was approximately 3.3%. This facility expires on October 3, 2018. 

F-13

Note 6 - Commitments and Contingencies

Rent expense for the years ended December 31, 2015 and 2014 was approximately $149,000 and $159,000 respectively. Future non-cancellable minimum lease payments are approximately, $147,000 for 2016, $145,000 for 2017, $91,000 for 2018 and $77,000 for 2019.

We, as a lessee and operator of oil and gas properties, are subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject to the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area.  As of December 31, 2015, we have no reserve for environmental remediation and are not aware of any environmental claims.

As of December 31, 2015, the Company has an outstanding irrevocable letter of credit in the amount of $50,000 issued in favor of the Texas Railroad Commission. This letter of credit is required by the Commission by all companies operating in the state in accordance with limits prescribed by the Texas Railroad Commission.

Note 7 - Income Taxes

There was no current or deferred income tax expense (benefit) for the years ended December 31, 2015 and December 31, 2014.

The following table sets forth a reconciliation of the provision for income taxes to the statutory federal rate:

	Year Ended December 31,
	2015			2014
Statutory tax rate		35.00	%		35.00	%
State tax rate, net of federal tax		1.90	%		1.37	%
Other permanent items		0.00	%		0.05	%
Change in valuation allowance		(36.90	)%		(36.42	)%
Effective tax rate		0.00	%		0.00	%

Significant components of the deferred tax assets and liabilities are as follows:

	Year Ended December 31,
	2015			2014
Non-current deferred tax asset:
Oil and gas costs and long-lived assets	$	14,513,571		$	(1,038,092	)
Derivative instruments		934,340			(1,717,301	)
Net operating loss carry-forward		29,532,954			25,915,146
Valuation allowance		(44,980,865	)		(23,159,753	)
Net deferred tax asset (liability)	$	-		$	-

At December 31, 2015, we have a net operating loss carry forward of approximately $81 million expiring in 2021-2036 that is subject to certain limitations on an annual basis. A valuation allowance has been established against net operating losses where it is more likely than not that such losses will expire before they are utilized.

The Company incurred a change of control as defined by the Internal Revenue Code. Accordingly, the rules will limit the utilization of the Company’s net operating losses. The limitation is determined by multiplying the value of the stock immediately before the ownership change by the applicable long-term exempt rate. It is estimated that approximately $40.9 million of net operating losses may be subject to an annual limitation. Any unused annual limitation may be carried over to later years. The amount of the limitation may under certain circumstances be increased by the built-in gains in assets held by the Company at the time of the change that are recognized in the five-year period after the change.

F-14

Note 8 - Fair Value Measurements

We hold certain financial assets which are required to be measured at fair value on a recurring basis in accordance with the Statement of Financial Accounting Standard No. 157, “Fair Value Measurements” (“ASC Topic 820-10”).   ASC Topic 820-10 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).  ASC Topic 820-10 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants on the measurement date. A fair value measurement assumes that the transaction to sell the asset or transfer the liability occurs in the principal market for the asset or liability. The three levels of the fair value hierarchy under ASC Topic 820-10 are described below:

Level 1. Valuations based on quoted prices in active markets for identical assets or liabilities that an entity has the ability to access.  We believe receivables, payables and our debt approximate fair value at December 31, 2015.

Level 2. Valuations based on quoted prices for similar assets or liabilities, quoted prices for identical assets or liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable data for substantially the full term of the assets or liabilities.  We consider the derivative liability to be Level 2.  We determine the fair value of the derivative liability utilizing various inputs, including NYMEX price quotations and contract terms.

Level 3. Valuations based on inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. We consider the marketable securities to be a Level 3. Our derivative instruments consist of fixed price commodity swaps.  

	Fair Value Measurement
	Level 1		Level 2		Level 3
Crude oil contracts	$	-	$	2,531,401	$	-
Marketable securities	$	-	$	-	$	210,990

Note 9 - Derivative Instruments

We have entered into certain derivative or physical arrangements with respect to portions of our crude oil production to reduce our sensitivity to volatile commodity prices and/or to meet hedging requirements under our Credit Facility.  We believe that these derivative arrangements, although not free of risk, allow us to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations.  However, derivative arrangements limit the benefit of increases in the prices of crude oil.  Moreover, our derivative arrangements apply only to a portion of our production.

We have an Inter-creditor Agreement in place between the Company; our counterparties, BP Corporation North America, Inc. and Cargill Incorporated and our agent, Texas Capital Bank, N.A., which allows Texas Capital Bank to also act as agent for the counterparties for the purpose of holding and enforcing any liens or security interests resulting from our derivative arrangements.  Therefore, we generally are not required to post additional collateral, including cash.

The following derivative contracts were in place at December 31, 2015:

	Term	Monthly Volumes (1)			Price/Bbl		Fair Value
Deferred premium put	1/16-6/16		9,000	Bbls	$	85.00	$	2,170,912
Deferred premium put	7/16-12/16		5,000	Bbls	$	60.00		360,489
							$	2,531,401

⁽¹⁾      Monthly volumes are the weighted average throughout the period.

The total fair value of derivative contracts is shown in both current and non-current assets on the balance sheet.  We recorded a loss related to our derivative contracts for the year ended December 31, 2015 of $2,194,679 and a gain of $6,073,960 for the year ended December 31, 2014. 

F-15

Note 10 – Net Income Per Common Share

The Company reports earnings per share in accordance with ASC Topic 260-10, “Earnings per Share.” Basic earnings per share is computed by dividing income available to common shareholders by the weighted average number of common shares available. Diluted earnings per share is computed similar to basic earnings per share except that the denominator is increased to include the number of additional common shares that would have been outstanding if the potential common shares had been issued and if the additional common shares were dilutive.

Note 11 – Impairment of Oil and Gas Properties

Pursuant to full cost accounting rules, the Company must perform a ceiling test each quarter on its proved oil and natural gas assets within each separate cost center. All of the Company’s costs are included in one cost center because all of the Company’s operations are located in the United States.The Company’s ceiling test was calculated using trailing twelve-month, unweighted-average first-day-of-the-month prices for oil and natural gas as of December 31, 2015, which were based on a West Texas Intermediate oil price of $52.73 per Bbl and a Henry Hub natural gas price of $2.76 per MMBtu (adjusted for basis and quality differentials), respectively. The trailing twelve-month, unweighted-average first-day-of-the-month prices for oil and natural gas as of September 30, 2015, was based on a West Texas Intermediate oil price of $59.21 per Bbl and a Henry Hub natural gas price of $3.06 per MMBtu (adjusted for basis and quality differentials), respectively. The twelve-month, unweighted-average first-day-of-the –month price as of June 30, 2015 was $71.68 per Bbl and $3.39per MMBtu The twelve-month, unweighted-average first-day-of-the –month price as of March 31, 2015 was $78.82 per Bbl and $3.74 per MMBtu (adjusted for basis and quality differentials), respectively. Utilizing these prices, the calculated ceiling amount was less than the net capitalized cost of oil and natural gas properties as of December 31, 2015, and as a result, a pre-tax write-down of $11.4 million was recorded. Utilizing these prices, the calculated ceiling amount was less than the net capitalized cost of oil and natural gas properties as of September 30, 2015, and as a result, a pre-tax write-down of $9.7 million was recorded. At June 30, 2015 the calculated ceiling amount was less than net capitalized cost of oil and natural gas properties resulted in a pre-tax write-down of $11.4 million. At March 31, 2015 the calculated ceiling amount was less than net capitalized cost of oil and natural gas properties resulted in a pre-tax write-down of $16.4 million. Additional material write-downs of the Company’s oil and gas properties could occur in subsequent quarters in the event that oil and natural gas prices remain at current depressed levels, or if the Company experiences significant downward adjustments to its estimated proved reserves.

Note 12 – Other Income

The following table depicts the components of other income for the years ended December 31, 2015 and December 31, 2014:

	Year ended December 31, 2015			Year ended December 31, 2014
Realized gain (loss) clearing of derivative contracts	$	4,662,012		$	(914,694	)
Loss on sale of fixed assets		(13,661	)		(9,738	)
Miscellaneous income		27,105			4,004
Interest income		398			901
Other Income	$	4,675,854		$	(919,527	)

Note 13 - Subsequent Events

On October 3, 2011, the Company, entered into an Amended and Restated Credit Agreement with Texas Capital Bank, and other financial institutions and banks (“TCB” or “Bank”) that may become a party to the Credit Agreement from time to time. The facilities provided under the Amended and Restated Credit Agreement was to be used to refinance a prior outstanding revolving loan facility with TCB dated July 3, 2008, and for working capital and general corporate purposes. On August 15, 2014 the Company entered into an Eighth Amendment to the Amended and Restated Credit Agreement. Among other things the Eighth Amendment extended the maturity of the Agreement by three years to October 3, 2018. On August 12, 2015, the Company entered into a Tenth Amendment to the Amended and Restated Credit Agreement. Among other things the Tenth Amendment established the requirement of monthly borrowing base reductions commencing September 1, 2015 and continuing on the first of each month thereafter.

On April 1, 2016 the Company informed the Bank that it would cease making the mandatory monthly borrowing base reduction payments and did not make the required April 1, 2016 payment. The Company made its mandatory quarterly interest payment on April 6, 2016 and on April 7, 2016 entered into a Forbearance Agreement whereby the Bank agreed to not exercise remedies and rights afforded it under the Amended and Restated Credit Agreement for thirty days. The thirty day period will be used by the Company to pursue strategic alternatives.

The Company accesses a number of data bases and utilizes several consultants to monthly prepare commodity price projections used in its cash forecasting models. The models indicate it will have sufficient cash to satisfy obligation as they become due through the end of the first quarter of 2017, if it ceases to make the principle reduction called for by the Tenth Amendment entered into by the Company on August 12, 2015. If actual commodity prices are less than forecasted the Company would not have enough cash to meet obligations as they become due. Should this occur the Company could suspend quarterly interest payments, restructure, amend or refinance existing debt through private options or seek a protected reorganization under chapter 11 of the U.S. federal bankruptcy code.

F-16

Note 14 - Supplemental Oil and Gas Reserve Information (Unaudited)

Results of operations from oil and gas producing activities

The following table shows the results of operations from the Company’s oil and gas producing activities.  Results of operations from these activities are determined using historical revenues, production costs and depreciation and depletion. The results of operations from the Company’s oil and gas producing activities below exclude non-oil and gas revenues, general and administrative expenses, interest income and interest expense. Income tax expense was determined by applying the statutory rates to pretax operating results.

	Year Ended			Year Ended
	December 31,			December 31,
	2015			2014
Production revenues	$	4,878,722		$	14,293,368
Production costs		(4,501,940	)		(6,762,248	)
Depletion and depreciation		(1,108,039	)		(3,259,442	)
Income tax		255,940			(1,495,087	)
Results of operations for producing activities	$	(475,317	)	$	2,776,591

F-17

Capitalized costs

The following table summarizes the Company’s capitalized costs of oil and gas properties.

	Year Ended			Year Ended
	December 31,			December 31,
	2015			2014
Properties subject to amortization	$	26,642,325		$	78,090,619
Accumulated depletion		(14,935,386	)		(13,827,347	)
Net capitalized costs	$	11,706,939		$	64,263,272

Cost incurred in property acquisition, exploration and development activities

	Year Ended		Year Ended
	December 31,		December 31,
	2015		2014
Acquisition of properties	$	85,895	$	1,017,698
Exploration costs		-		-
Development costs		165,926		6,078,167
Net capitalized costs	$	251,821	$	7,095,865

Estimated quantities of proved reserves

Our ownership interests in estimated quantities of proved oil and gas reserves and changes in net proved reserves all of which are located in the United States are summarized below.  Proved reserves are estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those that are expected to be recovered through existing wells with existing equipment and operating methods. Reserves are stated in barrels of oil equivalent. Geological and engineering estimates by Cobb & Associates, Inc. of proved oil and gas reserves at one point in time are highly interpretive, inherently imprecise and subject to ongoing revisions that may be substantial in amount. Although every reasonable effort is made to ensure that the reserve estimates are accurate, by their nature reserve estimates are generally less precise than other estimates presented in connection with financial statement disclosures.

	2015												2014
				Natural Gas						Oil						Natural Gas						Oil
	Crude Oil			Liquids			Natural Gas			Equivalents			Crude Oil			Liquids			Natural Gas			Equivalents
	BBL's			BBLs			MCF's			BOE's			BBL's			BBLs			MCF's			BOE's
Proved reserves
Beginning		2,946,400			90,900			8,177,280			4,400,180			4,444,500			40,600			7,917,000			5,804,600
Revisions of previous estimates		(1,151,384	)		(35,925	)		(1,723,732	)		(1,474,598	)		(1,352,091	)		56,919			578,506			(1,198,754	)
Purchases of minerals in place														2,234									2,234
Extensions and discoveries														2,226									2,226
Sales of minerals in place		(217,032	)								(217,032	)											-
Production		(96,244	)		(6,045	)		(188,408	)		(133,690	)		(150,469	)		(6,619	)		(318,226	)		(210,126	)
Ending		1,481,740			48,930			6,265,140			2,574,860			2,946,400			90,900			8,177,280			4,400,180

Proved developed reserves at December 31, 2015 consisted of 74% oil and 26% natural gas and totaled 1,851.9 MBOEs. Proved developed reserves for December 31, 2014 consisted of 77% oil and 23% natural gas and totaled 3,048.3 MBOEs. Proved undeveloped reserves for December 31, 2015 were 723.0 MBOEs. Proved undeveloped reserves at December 31, 2014 were 1,351.9 MBOEs.

For the year ended December 31, 2015 proved reserves decreased 1,825.3 MBOEs of which production accounted for 133.7 MBOEs or 7.3% of the decrease. The remaining decrease of 1,691.6 MBOEs, was due primarily to decreases in commodity prices. Crude oil prices decreased $40.00 or 46.1% and natural gas prices declined 42.2% or $1.37. Diminished commodity pricing triggered negative revisions of 586.6 MBOEs of crude oil classified as proved developed producing, negative revisions of 42.9 MBOEs of crude oil classified as proved developed non-producing and negative revisions of 522.1 of MBOEs of crude oil classified as proved undeveloped reserves. Natural gas liquids decreased pricing resulted in decreases of 65.6 MBOEs to the proved developed producing category. Reduced natural gas prices also reduced amounts classified as proved developed producing by 1,347.9 MMCF’s as well as natural gas reserves classified as proved undeveloped by 637.8 MCF. These decreases were partially offset by increases to natural gas liquid reserves classified as proved developed non-producing of 29.7 MBOE and 262.4 MMCF of natural gas reserves classified as proved developed non-producing. In 2015 there were no material transfers from the proved undeveloped category of reserves to the proved developed category.

For the year ended December 31, 2014 proved reserves decreased 1,404.4 MBOEs, of which production accounted for 210.1 MBOEs or 14.9% of the decrease. The remaining decrease of 1,194.3 MBOEs or 20.5%, was due primarily to a revision of decline curves related to our Cherokee project in Eastern Kansas. Our third party independent engineering firm, MHA Petroleum Consultants revised their decline curve forecast methodology in response to 2014 production performance that fell short of forecast using the original methodology, resulting in a negative revision of a 686,091 BOEs of crude oil classified as proved developed producing, a negative revision of 38,100 BOEs of crude oil classified as proved developed non-producing and a negative revision of 627,893 of BOEs of crude oil classified as proved undeveloped reserves for a total of 1,352,091 BOEs. These decreases were partially offset by increases to estimated proved developed reserves of approximately 240,000 BOE of natural gas and 56,919 barrels of natural gas liquids that resulted from the transfer of an Adena gas-cap well from proved non-producing to the proved developed producing category. Additionally, proved developed non-producing natural gas reserves decreased approximately 143,000 BOE again due to the transferring of a gas-cap well from proved non-producing to the proved developed producing category.

Proved undeveloped reserves decreased 627,893 BOEs in 2014. The decrease was due almost entirely to the crude oil revisions, which resulted from revisions to decline curves related to our Cherokee project in Eastern Kansas. Our third party independent engineering firm, MHA Petroleum Consultants revised their decline curve forecast methodology in response to 2014 production performance that fell short of forecast using the original methodology. No material amount of reserves were the result to a transfer from proved undeveloped reserves to the proved developed category.

F-18

In 2015 the Company invested approximately $250,000 in its oil and gas properties. These reduced expenditures were primarily in response to extremely low commodity prices. The Company has $7.4 million of current asset on hand, approximately $3.7 million of unrealized hedge gains and important infrastructure in Colorado completed which will facilitate the exploitation and development of proved undeveloped reserves over the next five years. At year end the Company’s review of proved undeveloped reserves revealed no instances of reserves that have not been developed within five years of their initial recording as a proved undeveloped reserve. In addition it believes it has the financial wherewithal to develop all it’s proved undeveloped reserves within the five year time frames required; utilizing its balance sheet, it borrowed $.5 million from its bank in January 2015 and has the ability to joint venture any of its assets.

Standardized measure of discounted future net cash flows

The standardized measure of discounted future net cash flows from our proved reserves for the periods presented in the financial statements is summarized below.

	Year Ended			Year Ended
	December 31,			December 31,
	2015			2014
Future production revenue	$	74,087,130		$	282,557,900
Future production costs		(46,015,320	)		(101,119,500	)
Future development costs		(5,901,660	)		(13,736,500	)
Future cash flows before income tax		22,170,150			167,701,900
Future income taxes		-			(4,211,005	)
Future net cash flows		22,170,150			163,490,895
10% annual discount for estimating of future cash flows		(13,400,180	)		(100,787,044	)
Standardized measure of discounted net cash flows	$	8,769,970		$	62,703,851

Changes in standardized measure of discounted future net cash flows

The following is a summary of a standardized measure of discounted net future cash flows related to the Company’s proved oil and gas reserves. The information presented is based on a calculation of estimated proved reserves using discounted cash flows based on the 12-month average price for oil and gas calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month prior period. The additions to estimated proved reserves from new discoveries and extensions could vary significantly from year to year. Additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant.

	Year Ended			Year Ended
	December 31,			December 31,
	2015			2014
Balance beginning of year	$	62,703,851		$	81,447,656
Sales, net of production costs		(491,055	)		(7,531,119	)
Net change in pricing and production costs		(51,184,718	)		(19,087,068	)
Net change in future estimated development costs		7,834,840			6,281,385
Purchase of minerals in place		-			190,502
Extensions and discoveries		-			35,203
Sale of minerals in place		(2,746,550	)		-
Revisions		(8,448,569	)		(25,498,141	)
Accretion of discount		16,770,190			27,098,964
Change in income tax		(15,668,019	)		(233,531	)
Balance end of year	$	8,769,970		$	62,703,851

F-19

EX-10.28

EXHIBIT 10.28

FORBEARANCE AGREEMENT

This FORBEARANCE AGREEMENT (this “Forbearance Agreement”), dated April 4, 2016 (the “Effective Date”), is by and amongENERJEX RESOURCES, INC., a Nevada corporation (“Parent”), ENERJEX KANSAS, INC. (f/k/a Midwest Energy, Inc.), a Nevada corporation (“EnerJex Kansas”), WORKING INTEREST, LLC, a Kansas limited liability company (“Working Interest”), BLACK SABLE ENERGY, LLC, a Texas limited liability company (“Black Sable”), BLACK RAVEN ENERGY, INC., a Nevada corporation (“Black Raven”), ADENA, LLC, a Colorado limited liability company (“Adena”; together with Parent, EnerJex Kansas, Working Interest, Black Sable and Black Raven, collectively, “Borrowers” and each, a “Borrower”), and TEXAS CAPITAL BANK, N.A., a national banking association, as a Bank, L/C Issuer and Administrative Agent (in such latter capacity and together with its successors and permitted assigns in such capacity the “Administrative Agent”), and the several banks and financial institutions from time to time parties to the Credit Agreement, as defined below (the “Banks”). Capitalized terms used but not defined in this Forbearance Agreement have the meaning given them in the Credit Agreement.

RECITALS:

WHEREAS, an “Amended and Restated Credit Agreement” was entered into as of October 3, 2011, by and among the Borrowers, the Administrative Agent and the Banks (as amended from time to time prior to the Effective Date, the “Credit Agreement”);

WHEREAS, in connection with the Credit Agreement, the Borrowers executed and delivered to the Administrative Agent their promissory notes in principal amounts aggregating up to $100,000,000 (the “Notes”), secured in part by various deeds of trust, security agreements and other security instruments;

WHEREAS, an Event of Default occurred and exists due to the failure of the Borrowers to make a principal payment on the Obligations (the “Payment Default”);

WHEREAS, the Borrowers agree that the Maturity Date of the Notes has been accelerated to April 1, 2016 and that all principal and accrued, unpaid interest on the Notes is now due and payable;

WHEREAS, in addition to the principal and interest on the Notes, the amendment fees of $56,500 and $71,250 referred to, respectively, in the Ninth Amendment and the Eleventh Amendment are now due and payable (collectively, the “Amendment Fees”);

WHEREAS, the Notes have been accruing interest at the Default Rate since December 31, 2015, and will continue to accrue interest at the Default Rate, but until the occurrence of a Termination Event (hereinafter defined), interest on the Notes will be payable at the Contract Rate (hereinafter defined) monthly as specified in the Credit Agreement;

-1-

WHEREAS, in addition to the Payment Default, other Defaults and Events of Default exist under the Credit Agreement and each of the other Loan Documents, as listed on Exhibit One hereto (together with the Payment Default, the “Forbearance Defaults”), and the Borrowers have been properly notified thereof or, if not so notified, have waived and hereby waive the requirement of such notices to the fullest extent not prohibited by Law;

WHEREAS, the Borrowers have requested a period of forbearance from the exercising of certain remedies and rights available to the Administrative Agent and the Banks as a result of the occurrence of the Forbearance Defaults;

WHEREAS, the Borrowers intend to utilize the Forbearance Period primarily for the purpose of negotiating and entering into an arrangement with a potential purchaser to acquire the Notes or with a potential investor to make a capital infusion into the Borrowers; and

WHEREAS, the Borrowers have requested that the Banks permit the Borrowers to utilize funds from time to time hereafter deposited into the TCB Accounts for Proper Purposes (hereinafter defined) during the Forbearance Period.

NOW, THEREFORE, in consideration of the premises, the mutual covenants made herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Borrowers, the Administrative Agent and the Banks agree as follows:

Article 1
Definitions and INTERPRETATION

1.1         Terms Defined in Credit Agreement. Terms used herein shall have the same meanings given such terms in the Credit Agreement (as amended by this Forbearance Agreement) unless otherwise defined herein or the context otherwise requires.

1.2         References. References in this Forbearance Agreement to “hereby,” “herein,” “hereinafter,” “hereinabove,” “hereinbelow,” “hereof,” “hereunder” and words of similar import shall be to this Forbearance Agreement in its entirety and not only to the particular article or section in which such reference appears. Exhibits and schedules to any Loan Document (including this Forbearance Agreement) shall be deemed incorporated by reference in such Loan Document. References to any document, instrument, or agreement (a) shall include all exhibits, schedules, and other attachments thereto, and (b) shall include all documents, instruments, or agreements issued or executed in replacement thereof. This Forbearance Agreement, for convenience only, has been divided into articles and sections; and it is understood that the rights and other legal relations of the parties hereto shall be determined from this instrument as an entirety and without regard to the aforesaid division into articles and sections and without regard to headings prefixed to such articles or sections. Whenever the context requires, reference herein made to the single number shall be understood to include the plural; and likewise, the plural shall be understood to include the singular. Definitions of terms defined in the singular or plural shall be equally applicable to the plural or singular, as the case may be, unless otherwise indicated. Words denoting sex shall be construed to include the masculine, feminine and neuter, when such construction is appropriate; and specific enumeration shall not exclude the general but shall be construed as cumulative; the word “or” is not exclusive; the word “including” (in its various forms) shall mean “including, without limitation”; in the computation of periods of time, the word “from” means “from and including” and the words “to” and “until” mean “to but excluding”; and all references to money refer to the legal currency of the United States of America.

-2-

1.3         Amendment of Defined Instruments. Unless the context otherwise requires or unless otherwise provided herein, the terms defined in this Forbearance Agreement which refer to a particular agreement, instrument or document also refer to and include all renewals, extensions, modifications, amendments and restatements of such agreement, instrument or document, provided that nothing contained in this Section shall be construed to authorize any such renewal, extension, modification, amendment or restatement.

1.4         Negotiated Transaction. This Forbearance Agreement has been reviewed and negotiated by sophisticated parties with access to legal counsel, and no rule of construction shall apply hereto or thereto which would require or allow this Forbearance Agreement to be construed against any party because of its role in drafting this Forbearance Agreement.

Article 2
Acknowledgement AND AGREEMENTS

The Borrowers hereby acknowledge and agree that:

2.1         Each of the Forbearance Defaults has occurred under the Credit Agreement and has not been waived.

2.2         By agreement between (i) the Borrowers and (ii) the Banks and LC Issuer, the maturity of the Notes has been accelerated and the Notes are presently due and payable.

2.3         Interest on the Notes will accrue interest at the Default Rate upon the occurrence of a Termination Event;

2.4         As a result of the Forbearance Defaults, the Administrative Agent presently has the right to exercise any and all rights and remedies provided under the Credit Agreement and the other Loan Documents or at law or in equity to collect the Obligations and to foreclose the Liens securing same and may pursue such rights during the Forbearance Period, except to the extent otherwise provided in Section 5.1 of this Forbearance Agreement.

2.5         The Borrowers have consented to, and hereby consent to, Texas Capital Bank, N.A. and IberiaBank (and their respective employees, agents, representatives, attorneys and other professionals) (i) communicating directly with (a) any potential purchaser that has signed a confidentiality agreement with the Administrative Agent or a Bank and (b) the employees, agents, representatives, attorneys and other professionals representing such potential purchaser, regarding such potential purchaser’s interest in acquiring all or a part of the Notes or of the Borrowers or of the Borrowers’ respective assets and (ii) disclosing to (a) any such potential purchaser that has signed a confidentiality agreement with the Administrative Agent or a Bank and (b) the employees, agents, representatives, attorneys and other professionals representing such potential purchaser, anything directly or indirectly related to the assets, liabilities, financial condition and operations of the Borrowers or actions or intended actions of Administrative Agent and the Banks regarding the Borrowers.

-3-

2.6         Each Bank has the right to sell all or any portion of its Note to any Person without notice to or the consent of the Borrowers.

2.7         All of the conditions precedent in this Forbearance Agreement are solely for the benefit of the Administrative Agent and the Banks, and no Person other than the Administrative Agent and the Banks may rely thereon or insist on compliance therewith.

Article 3
Representation and warranties

3.1         To induce the Administrative Agent and the Banks to enter into this Forbearance Agreement, each of the Borrowers hereby represents and warrants to the Administrative Agent and the Banks as follows with the intention that the Administrative Agent and the Banks shall rely thereon without any investigation or verification thereof by the Administrative Agent, the Banks or their respective counsel:

3.1.1    Execution of Agreement. This Forbearance Agreement has been duly executed and delivered by or on behalf of each of the Borrowers.

3.1.2    Authorized Action. The execution, delivery and performance of this Forbearance Agreement have been duly authorized by all necessary corporate or company action of the respective Borrowers. Each of the Borrowers are duly organized, validly existing and in good standing in their respective states of organization.

3.1.3    No Violation of Law. The consummation of this Forbearance Agreement does not violate any Laws applicable to any of the Borrowers.

3.1.4    Other Funds. None of the Borrowers (i) has any other funds on deposit at any financial institution other than Texas Capital Bank, N.A. or (ii) owns any marketable securities (other than securities issued by Oakridge Energy, Inc.) or other liquid assets.

Article 4
AmendmentS AND MODIFICATIONS TO Credit Agreement

4.1         Amendments to Credit Agreement.

4.1.1    The following definitions are hereby added to Section 10.1 of the Credit Agreement as follows:

“AFE” means an authorization for expenditure as customarily used by an operator of an Oil and Gas Property to obtain approval from the owners of such Property to undertake certain activities at the costs estimated therein, in each case unrelated to infrastructure or capital expenditure.

“Amendment Fees” has the meaning given such term in the Recitals to the Forbearance Agreement.

-4-

“Cash Base Budget and Forecast” means a projected sources and uses of cash of the Borrowers in such detail as shall be reasonably satisfactory to the Administrative Agent covering a 13-week period.

“Claim Notice” means each notice of lien filing, each demand for payment, each notice of cancellation or termination of any agreement, each petition naming either of the Borrowers as a defendant, or any notice, claim or request for a consent from an operator of an Oil and Gas Property.

“Contract Rate” means the per annum interest rate determined under the Credit Agreement when the Default Rate is not in effect.

“Forbearance Agreement” means the Forbearance Agreement between the Borrowers, the Administrative Agent and the Banks dated April 4, 2016.

“Forbearance Defaults” has the meaning given such term in the Recitals hereto.

“Forbearance Period” means the period commencing with the Effective Date and ending on the Termination Date.

“Line Item Budget” means a line item budget in form and detail reasonably satisfactory to the Administrative Agent, identifying the Persons or categories of Persons to whom payments are to be made, the amounts of such payments and the week during which such payments will be made. The initial Line Item Budget will cover the period from the Effective Date to May 1, 2016.

“Non-Forbearance Defaults” means any Default or Event of Default other than a Forbearance Default.

“Production Report” means for any period, a report setting forth the volumes of production during such period by well and in total and the sale proceeds therefrom and containing such other and additional information as the Administrative Agent shall reasonably require.

“Proper Purpose” means any of the following:

(i) emergency expenditures necessary for the protection of persons, property and the environment;

(ii) payment of general and administrative expenses incurred in the ordinary course of business and consistent with the Cash Base Budget and Forecast;

(iii) payment of lease operating expenses, production taxes, ad valorem taxes, and any required royalty payments related to the Oil and Gas Properties of the Borrowers and consistent with the Cash Base Budget and Forecast;

(iv) payment of accounts payable incurred in the ordinary course of business and consistent with the Cash Base Budget and Forecast;

(v) as permitted by Section 6.1 of the Forbearance Agreement;

(vi) payments to the Administrative Agent for application to the Obligations;

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(vii) payments consistent with the Line Item Budget;

(viii) payments to attorneys for services rendered, but not as a retainer in excess of $25,000 for future services;

(ix) payments to accountants in the ordinary course of business; and

(x) other payments approved by the Administrative Agent from time to time.

“TCB Accounts” means the deposit accounts identified on Schedule One hereto.

“Termination Date” has the meaning given such term in Section 5.5 of the Forbearance Agreement.

“Termination Event” means the earliest to occur of: (i) May 1, 2016, (ii) the occurrence of a Non-Forbearance Default, (iii) any of the Borrowers has violated or failed to satisfy any provision of the Forbearance Agreement within the time limitations set forth in the Forbearance Agreement, time being of the essence in the performance by the Borrowers of their obligations under each Section of the Forbearance Agreement, (iv) any representation, warranty, certification or statement made or deemed to have been made by or on behalf of the Borrowers in connection with the Forbearance Agreement, was incorrect in any material respect when made in the reasonable judgment of the Administrative Agent, (v) any of the Borrowers or any Person representing any of them shall deny (a) the liability of any of the Borrowers under any Loan Document or (b) the enforceability of any provision of any Loan Document or the Forbearance Agreement, (vi) the failure of any of the Borrowers to immediately deposit any payments or revenues received by it into the TCB Accounts, (vii) the occurrence of any event described in Section 9.01(f) of the Credit Agreement, or (viii) the commencement by any Person, other than the Administrative Agent or the Banks, of any action or proceeding against any of the Borrowers, including a suit or other action (other than routine notices of Lien filings) to enforce any Liens against any Oil and Gas Properties or other assets of any of the Borrowers.

4.1.2    The following definition in Section 1.01 of the Credit Agreement is hereby amended and restated in its entirety as follows:

“Maturity Date” means April 1, 2016.

4.1.3    Notwithstanding any other provisions of any other Loan Document to the contrary, during the Forbearance Period and thereafter, the Borrowers agree that (i) the Borrowers shall have no rights to (a) borrow or re-borrow any amounts under the Credit Agreement, (b) request any Letters of Credit, (c) convert any Loan to a Eurodollar Loan, (d) continue after the Interest Period applicable thereto any Eurodollar Loan as a Eurodollar Loan, or (e) enter into any Swap Contracts without the written consent of the Administrative Agent and (ii) neither of the Banks nor the Administrative Agent is committed to extend any credit to the Borrowers in connection with the Credit Agreement.

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Article 5
FORBEARANCE

5.1         Forbearance.

5.1.1    Subject to the satisfaction of the conditions set forth in Article 6 of this Forbearance Agreement, during the Forbearance Period the Administrative Agent agrees to forbear from foreclosing the Liens of the Security Documents. Each of the Banks hereby consents to such forbearance.

5.1.2    The Banks waive their right to collect interest at a per annum interest rate above the Contract Rate prior to the occurrence of a Termination Event, but interest on the Notes will continue to accrue at the Default Rate during the Forbearance Period and thereafter.

5.1.3    The Banks waive their right to collect the Amendment Fees until the occurrence of a Termination Event.

5.1.4    The Banks agree not to offset amounts in the TCB Accounts against the Obligations prior to the occurrence of a Termination Event.

5.2         Permitted Actions. During the Forbearance Period and thereafter, the Administrative Agent and the Banks may continue to give notices, and exercise any and all other rights and remedies under the Credit Agreement (as amended by this Forbearance Agreement), this Forbearance Agreement, the other Loan Documents, at law or in equity, which are prepatory to or required in connection with the commencement of a foreclosure action. The Administrative Agent and the Banks retain their rights of set off or offset against amounts on deposit at either Bank.

5.3         No Waiver of Rights. Except as specifically set forth in Section 5.1 above, neither the execution and delivery by the Administrative Agent and the Banks of this Forbearance Agreement nor forbearance by the Administrative Agent pursuant to the terms of this Forbearance Agreement will (a) be construed to be a waiver of any Default or Event of Default or a waiver of any rights of the Administrative Agent or the Banks as set forth in the Credit Agreement, the other Loan Documents, or this Forbearance Agreement, or (b) limit or impair the Administrative Agent’s right to demand strict performance of all other terms and covenants of the Credit Agreement or the other Loan Documents. Each of the Borrowers further acknowledges and agrees that: (i) any exercise of rights by the Administrative Agent and the Banks upon termination of the Administrative Agent’s obligation to forbear in accordance with this Forbearance Agreement will not be affected by reason of the forbearance provided for herein, and (ii) none of the Borrowers may assert as a defense thereto the passage of time, course of dealing, estoppel, laches or any statute of limitations based thereon. Nothing in this Forbearance Agreement constitutes satisfaction of all or any portion of the Notes or other Obligations under the Credit Agreement or any other Loan Document.

5.4         No Other Modifications. Except as expressly set forth in this Forbearance Agreement, all obligations of the Borrowers under the Credit Agreement and the other Loan Documents remain in full force and effect.

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5.5         Termination of Forbearance Period. The Forbearance Period will terminate automatically and without notice to the Borrowers on the occurrence of a Termination Event (the “Termination Date”).

5.6         Effect of Termination. Upon the Termination Date, the Administrative Agent shall immediately be entitled to exercise all rights and remedies provided at law, in equity or under the Credit Agreement under this Forbearance Agreement or under the other Loan Documents without any notice having been previously given to the Borrowers, all such notices being hereby waived by the Borrowers to the fullest extent not prohibited by Laws.

5.7         Limited Scope of Agreement. All obligations of the Borrowers under the Credit Agreement and the other Loan Documents (including, without limitation, the Obligations) remain in full force and effect except as expressly set forth herein.

5.8         No Obligation to Renew, Etc. The Borrowers agree that the Banks have no obligation to renew, modify or extend the term of the Forbearance Period.

Article 6
COVENANTS of THE BORROWerS

In consideration of the Administrative Agent’s agreement to forbear as set forth in Section 5.1, the Borrowers hereby agree as follows:

6.1         Activities of the Borrowers; Use of Funds. It is hereby acknowledged that, due to the occurrence of the Forbearance Defaults, the Administrative Agent is entitled to foreclose on or collect certain funds and assets of the Borrowers and apply such funds and future revenues deposited in the TCB Accounts to the Obligations under the Credit Agreement. Notwithstanding such fact, the Borrowers shall be permitted during the Forbearance Period to use such funds and future revenues deposited in the TCB Accounts for Proper Purposes; provided, however that the Borrowers shall not, during the Forbearance Period, in any way use such funds and future revenues deposited in the TCB Accounts for the purpose of drilling any new oil or gas wells.

6.2         Reports.

6.2.1    On Thursday, April 7, 2016, and each Thursday occurring thereafter, the Borrowers shall provide to the Administrative Agent with a detailed update (which update may be orally given) of the status of negotiations with (i) each potential purchaser of the Notes and (ii) with each potential investor in the Borrowers.

6.2.2    On Thursday, April 7, 2016, and each Thursday occurring thereafter, the Borrowers shall provide to the Administrative Agent with a Production Report, updated to such Thursday.

6.2.3    On Thursday, April 7, 2016, and on each Thursday occurring thereafter, the Borrowers shall provide to the Administrative Agent with a Cash Base Budget and Forecast for the 13-week period following such Thursday.

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6.2.4    On Thursday, April 7, 2016, and on the first day of each month thereafter, the Borrowers shall provide to the Administrative Agent an updated Line Item Budget for April or such subsequent month, as applicable.

6.3         Strategic Matters.

6.3.1    Each of the Borrowers agrees to provide to the Administrative Agent, within two (2) Business Days after its receipt thereof, copies of each offer letter, written inquiry or written proposal (as modified from time to time) received by it or its attorneys or financial advisors from a potential purchaser, potential acquirer or potential investor after the Effective Date with respect to (i) the purchase of the Notes or (ii) a capital infusion into the Borrowers.

6.3.2    Each of the Borrowers agrees to provide to the Administrative Agent, within two (2) Business Days after its receipt thereof, copies of each Claim Notice received by it or its attorneys after the Effective Date.

6.3.3    Each of the Borrowers agrees to provide to the Administrative Agent, within two (2) Business Days after its receipt thereof or, if it is the party filing or sending same, within two (2) Business Days after it files or sends same, copies of each document, report, letter demand or request filed or otherwise related to any arbitration matter to which either of the Borrowers is a party and shall consult with the Administrative Agent regarding the appointment of arbitrators in connection therewith or any decision being made related to such arbitration. The foregoing requirement to make deliveries to the Administrative Agent shall not apply to items that are protected by an attorney-client privilege.

6.4         Proposals. The Borrowers agree to deliver to the Administrative Agent on or before 21 days following the Effective Date, a proposal (i) from a potential purchaser to acquire the Notes or (ii) from a potential investor to make a capital infusion into the Borrowers.

6.5         No Consent to Operations. The Borrowers agree not to consent to, propose, or approve an AFE with respect to any operations on the Oil and Gas Properties of any of the Borrowers without the prior written approval of the Administrative Agent and the Banks (which approval may be communicated by e-mail and may be withheld for any reason or no reason).

6.6         Further Assurances. The Borrowers hereby agree to execute and deliver any and all documents, instruments and agreements, and to take such other actions, as the Administrative Agent may reasonably require effecting the transactions and arrangements contemplated by this Forbearance Agreement.

Article 7
miscellaneous

7.1         Conditions Precedent. The effectiveness of the provisions of Section 5.1 of this Forbearance Agreement, shall be subject to the satisfaction or waiver of each of the following conditions concurrently with the execution of this Forbearance Agreement (all documents and opinions to be delivered below must be in form and substance satisfactory to the Administrative Agent):

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7.1.1    Transfer of Funds to TCB Accounts. All funds in the control of any of the Borrowers shall have been transferred to the TCB Accounts by wire transfer.

7.1.2    Payment of Banks’ Legal Fees. The Borrowers shall pay the legal fees and expenses of counsel to each Bank incurred to the date of execution and delivery of this Forbearance Agreement.

7.2         Notices. Notices to any party hereunder shall be given in accordance with Section 10.02 of the Credit Agreement, at the addresses set forth on the signatures pages hereto, except that any notice to the Borrowers may also be given by any electronic means, including e-mail, to any electronic address believed by the sender of such notice to be an address of any of the Borrowers, or an officer of any of the Borrowers or legal counsel to the Borrowers.

7.3         Amendments and Waivers. Any provision of this Forbearance Agreement may be amended or waived (either generally or in a particular instance and either retroactively or prospectively) by a written instrument signed by all of the parties hereto. Delivery of an executed counterpart of such written instrument by telecopy, e-mail, facsimile or other electronic means shall be effective delivery of a manually executed counterpart of such written instrument.

7.4         GOVERNING LAW. This Forbearance Agreement has been negotiated, is being executed and delivered, and will be performed in whole or in part, in the State of Texas. This Forbearance Agreement and any litigation between the parties (whether grounded in contract, tort, statute, law or equity shall be governed by, construed in accordance with, and interpreted and enforced pursuant to the Laws of the State of Texas (and the applicable federal Laws of the United States of America) without giving effect to its choice of law principles, except that any litigation between the parties with respect to a foreclosure proceeding involving real property located in a state shall be governed by the laws of such state.

7.5         VENUE. Each of the Borrowers hereby irrevocably submits to the non-exclusive jurisdiction of any United States federal or Texas state court sitting in Houston, Harris County, Texas in any action or proceeding arising out of or relating to any Loan Documents and each of the Borrowers hereby irrevocably agrees that all claims in respect of such action or proceeding may be heard and determined in any such court, and each of the Borrowers and hereby specifically consents to the jurisdiction of the State District Courts of Harris County, Texas and the United States District Court for the Southern District of Texas, Houston Division. Nothing herein shall limit the right of the Administrative Agent and the Banks to bring proceedings against the Borrowers and in the courts of any other jurisdiction. Any judicial proceeding by any of the Borrowers against the Administrative Agent, any Bank or any Affiliate of the Administrative Agent or any Bank involving, directly or indirectly, any matter in any way arising out of, related to, or connected with any Loan Document shall be brought only in the State District Courts of Harris County, Texas, or in the United States District Court for the Southern District of Texas, Houston Division.

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7.6         WAIVER OF JURY TRIAL AND EXEMPLARY DAMAGES. EACH OF THE BORROWERS HEREBY KNOWINGLY, VOLUNTARILY, INTENTIONALLY, IRREVOCABLY, AND UNCONDITIONALLY WAIVES (A) ALL RIGHTS TO TRIAL BY JURY IN ANY ACTION, SUIT, PROCEEDING, COUNTERCLAIM, OR OTHER LITIGATION THAT RELATES TO OR ARISES OUT OF ANY OF THIS FORBEARANCE AGREEMENT OR ANY OTHER LOAN DOCUMENT OR THE ACTS OR OMISSIONS OF THE ADMINISTRATIVE AGENT OR THE BANKS IN THE ENFORCEMENT OF ANY OF THE TERMS OR PROVISIONS OF THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT OR OTHERWISE WITH RESPECT THERETO AND (B) TO THE MAXIMUM EXTENT NOT PROHIBITED BY LAWS, ANY RIGHT IT MAY HAVE TO CLAIM OR RECOVER IN ANY SUCH LITIGATION ANY SPECIAL DAMAGES (AS DEFINED BELOW). THE PROVISIONS OF THIS SECTION ARE A MATERIAL INDUCEMENT FOR THE BANKS’ AND THE ADMINISTRATIVE AGENT’S ENTERING INTO THIS FORBEARANCE AGREEMENT. AS USED IN THIS SECTION, “SPECIAL DAMAGES” INCLUDES ALL SPECIAL, CONSEQUENTIAL, EXEMPLARY, OR PUNITIVE DAMAGES (REGARDLESS OF HOW NAMED).

7.7         Invalid Provisions; Severability. If any provision of this Forbearance Agreement is held to be illegal, invalid or unenforceable under present or future laws effective during the term hereof, such provision shall be fully severable, this Forbearance Agreement shall be construed and enforced as if such illegal, invalid or unenforceable provision had never comprised a part hereof, and the remaining provisions hereof shall remain in full force and effect and shall not be affected by the illegal, invalid or unenforceable provision or by its severance herefrom. Furthermore, in lieu of such illegal, invalid or unenforceable provision there shall be added automatically as a part of this Forbearance Agreement a provision as similar in terms to such illegal, invalid or unenforceable provision as may be possible and be legal, valid and enforceable.

7.8         NO DEFENSES OF BORROWERS. Each of the Borrowers stipulates, warrants, represents and agrees that, as of the Effective Date, it has no defenses against its obligations to pay any of the Obligations or any other amount due and owing to the Administrative Agent or the Banks pursuant to the Loan Documents. Each of the Borrowers acknowledges, warrants and agrees that, to the best of its knowledge, the Administrative Agent and each Bank have acted in good faith in all respects as to the Loan Documents and this Forbearance Agreement, and has conducted in a commercially reasonable manner its relationships with the Borrowers in connection with the Loan Documents and this Forbearance Agreement, and the Borrowers hereby waive and release any claims to the contrary.

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7.9          RELEASE OF CLAIMS.

7.9.1    Each of the Borrowers for itself, its successors and assigns and all those at interest therewith (collectively, the “Releasing Parties”), jointly and severally, hereby voluntarily and forever, RELEASE, DISCHARGE AND ACQUIT the Administrative Agent, each Bank, and their respective officers, directors, shareholders, employees, agents, successors, assigns, representatives, affiliates and insurers (sometimes referred to below collectively as the “Released Parties”) and all those at interest therewith of and from any and all claims, causes of action, liabilities, damages, costs (including, without limitation, attorneys’ fees and all costs of court or other proceedings), and losses of every kind or nature at this time known or unknown, direct or indirect, fixed or contingent, which the Releasing Parties have or hereafter may have arising out of any act, occurrence, transaction or omission occurring from the beginning of time to the date of execution of this Forbearance Agreement if related to the Notes, the Credit Agreement, the other Loan Documents or the First Forbearance Agreement (the “Released Claims”), except that (i) the future duties and obligations of the Administrative Agent and the Banks under this Forbearance Agreement and the other Loan Documents, and the rights of each Borrower to its funds on deposit with either Bank, shall not be included in the term Released Claims and (ii) the right of the Borrower to require the correction of manifest accounting errors and similar administrative errors shall not be included in the term Released Claims. IT IS THE EXPRESS INTENT OF THE RELEASING PARTIES THAT THE RELEASED CLAIMS SHALL INCLUDE ANY CLAIMS OR CAUSES OF ACTION ARISING FROM OR ATTRIBUTABLE TO THE NEGLIGENCE, GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF ANY OF THE RELEASED PARTIES.

7.10        No Commitment to Renew. By execution of this Forbearance Agreement, each of the Borrowers warrants and represents to the Administrative Agent and the Banks and agree that there is no commitment of any party for a renewal, extension, or modification of the Credit Agreement, the Notes, the Forbearance Period or this Forbearance Agreement in the future on any terms whatsoever.

7.11        Statute of Limitations. The parties hereto agree that the statute of limitations pertaining to the Credit Agreement, the Notes, the other Loan Documents and the documents executed in connection therewith shall be tolled during the Forbearance Period.

7.12        Ratification.

7.12.1  The Borrowers hereby ratify all of their Obligations under the Credit Agreement and each of the Loan Documents to which it is a party, and agrees and acknowledges that the Credit Agreement and each of the Loan Documents to which it is a party shall continue in full force and effect after giving effect to this Forbearance Agreement. Except as expressly set forth in Section 5.1, nothing in this Forbearance Agreement extinguishes, novates or releases any right, claim, Lien, security interest or entitlement of the Administrative Agent or the Banks created by or contained in any of such documents.

7.13       No Waiver of Events of Default. The execution of this Forbearance Agreement shall not be construed as a waiver of any existing Default or Event of Default under the Credit Agreement and the other Loan Documents, and, except as expressly set forth in Section 5.1, the Administrative Agent and Banks reserve their rights to exercise any and all remedies provided for in the Credit Agreement, the other Loan Documents, at law or in equity with respect to any such Default or Event of Default upon the Termination Date without any notice having been previously given to the Borrowers, all of which notices are hereby waived to the fullest extent not prohibited by applicable Laws.

7.14       Costs; Expenses. In addition to other or similar rights granted in the Credit Agreement and other Loan Documents, the Borrowers agree to pay on demand all reasonable out-of-pocket costs and expenses of the Administrative Agent and each Bank incurred in connection with the negotiation, preparation, execution and delivery of this Forbearance Agreement, including the reasonable fees and disbursements and other charges of their respective counsel.

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7.15       Conditions to Effectiveness. This Forbearance Agreement shall be effective upon the execution and delivery by the Borrowers, the Administrative Agent and the Banks.

7.16       Counterparts. This Forbearance Agreement may be executed in a number of counterparts, each of which shall be an original and all of which together shall constitute one and the same instrument. Delivery of an executed counterpart of a signature page of this Forbearance Agreement by telecopy, e-mail, facsimile or other electronic means shall be effective as a delivery of a manually executed counterpart of this Forbearance Agreement.

7.17       Effect. This Forbearance Agreement is one of the Loan Documents. Except as expressly provided hereby, the Credit Agreement the other Loan Documents shall remain unchanged and in full force and effect.

Article 8
ENTIRE AGREEMENT

THIS FORBEARANCE AGREEMENT CONSTITUTES THE ENTIRE AGREEMENT BETWEEN THE PARTIES HERETO WITH RESPECT TO THE SUBJECT HEREOF AND SHALL SUPERSEDE ANY PRIOR AGREEMENT BETWEEN THE PARTIES HERETO, WHETHER WRITTEN OR ORAL, RELATING TO THE SUBJECT HEREOF. FURTHERMORE, IN THIS REGARD, THIS FORBEARANCE AGREEMENT MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF SUCH PARTIES.

THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG SUCH PARTIES.

[Signature pages follow]

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IN WITNESS WHEREOF, the parties hereto have caused this Forbearance Agreement to be duly executed as of the Effective Date.

BORROWERS:
ENERJEX RESOURCES, INC.
By:
	Robert G. Watson
	Chief Executive Officer
ENERJEX KANSAS, INC.
By:
	Robert G. Watson
	Chief Executive Officer
WORKING INTEREST, LLC
By:
	Robert G. Watson
	Chief Executive Officer
BLACK SABLE ENERGY, LLC
By:
	Robert G. Watson
	Chief Executive Officer
BLACK RAVEN ENERGY, INC.
By:
	Robert G. Watson
	Chief Executive Officer
ADENA, LLC
By:
	Robert G. Watson
	Chief Executive Officer

Signature Page to Forbearance Agreement
(EnerJex Resources, Inc., et al)

ADMINISTRATIVE AGENT AND L/C ISSUER:
TEXAS CAPITAL BANK, N.A.,
as Administrative Agent, L/C Issuer and a Bank
By:
	Name:
	Title:
BANKS:
TEXAS CAPITAL BANK, N.A.,
By:
	Name:
	Title:
IBERIA BANK
By:
	Name:
	Title:

Signature Page to Forbearance Agreement
(EnerJex Resources, Inc., et al)

EXHIBIT ONE

FORBEARANCE DEFAULTS

1.         The Borrowers are in breach of the Interest Ratio covenant contained in Section 7.12(c) of the Credit Agreement for the fiscal quarter ended December 31, 2015.

2.          Borrower has failed to make required principal payments due under Section 2.04(a) of the Credit Agreement.

Exhibit One to Forbearance Agreement
(EnerJex Resources, Inc., et al)

SCHEDULE ONE

DEPOSIT ACCOUNTS

Borrower	Acct. Number at Texas Capital Bank
BLACK RAVEN ENERGY	3111028704
BLACK RAVEN ENERGY	3111029983
BLACK SABLE ENERGY	3111021329
ENERJEX KANSAS INC	3111012088
ENERJEX RESOURCES	3111021311
ENERJEX RESOURCES	3111035980

Schedule One to Forbearance Agreement
(EnerJex Resources, Inc., et al)

EX-21.1

EXHIBIT 21.1

Subsidiaries of EnerJex Resources, Inc.

As of December 31, 2014

Name of Subsidiary	State of Incorporation	Percentage Ownership
EnerJex Kansas, Inc.	Nevada		100	%
Black Raven Energy, Inc.	Nevada		100	%
Black Sable Energy, LLC	Texas		100	%
Working Interest, LLC	Kansas		100	%

EX-23.1

EXHIBIT 23.1

William M. Cobb & Associates, Inc.

Worldwide Petroleum Consultants

12770 Coit Road, Suite 907	(972) 385-0354
Dallas, Texas 75251	Fax: (972) 788-5165
	E-Mail: office@wmcobb.com

Consent of William M. Cobb & Associates, Inc.

As independent petroleum engineers, William M. Cobb & Associates, Inc. hereby consents to the use of references in the Form 10-K of EnerJex Resources, Inc. of our estimates of reserves as of December 31, 2015 and to all references to our firm included in this Form 10-K.

The Form 10-K contains references to a certain report prepared by William M. Cobb & Associates, Inc for the exclusive use of EnerJex Resources, Inc. The analysis, conclusions, and methods contained in the report are based upon information that was in existence at the time the report was rendered and William M. Cobb & Associates, Inc. has not updated and undertakes no duty to update anything contained in the report. While the report may be used as a descriptive resource, investors are advised that William M. Cobb & Associates, Inc. has not verified information provided by others except as specifically noted in the report, and William M. Cobb & Associates, Inc. makes no representation or warranty as to the accuracy of such information. Moreover, the conclusions contained in such report are based on assumptions that William M. Cobb & Associates, Inc. believed were reasonable at the time of its preparation and that are described in such report in reasonable detail. However, there are a wide range of uncertainties and risks that are outside of the control of William M. Cobb & Associates, Inc. which may impact these assumptions, including but not limited to unforeseen market changes, actions of governments or individuals, natural events, economic changes, and changes of laws and regulations or interpretation of laws and regulations.

	Sincerely,
	WILLIAM M. COBB & ASSOCIATES, INC.
	Texas Registered Engineering Firm F-84
	Michael L. Wiggins, Ph.D., P.E.
	Senior Vice President
Dallas, Texas Date: April 11, 2016

EX-23.2

EXHIBIT 23.2

 

CONSENT OF MHA PETROLEUM CONSULTANTS LLC

INDEPENDENT PETROLEUM ENGINEERS

As independent petroleum engineers, MHA Petroleum Consultants LLC hereby consents to the use of reference in the Form 10-K of EnerJex Resources, Inc. of our estimates of reserves as of December 31, 2014 and to all references to our firm included in this Form 10-K.

The Form 10-K contains references to a certain report prepared by MHA Petroleum Consultants LLC for the exclusive use of EnerJex Resources, Inc. The analysis, conclusions, and methods contained in the report are based upon information that was in existence at the time the report was rendered and MHA Petroleum Consultants LLC has not updated and undertakes no duty to update anything contained in the report. While the report may be used as a descriptive resource, investors are advised that MHA Petroleum Consultants LLC has not verified information provided by others except as specifically noted in the report, and MHA Petroleum Consultants LLC makes no representation or warranty as to the accuracy of such information. Moreover, the conclusions contained in such report are based on assumptions that MHA Petroleum Consultants LLC believed were reasonable at the time of its preparation and that are described in such report in reasonable detail. However, there are a wide range of uncertainties and risks that are outside of the control of MHA Petroleum Consultants LLC which may impact these assumptions, including but not limited to unforeseen market changes, actions of governments or individuals, natural events, economic changes, and changes of laws and regulations or interpretation of laws and regulations.

MHA Petroleum Consultants, LLC
By	/s/Leslie S. O’Connor
	Leslie A. O’Connor Vice President

Denver, Colorado

Date: April 11, 2016

EX-23.3

EXHIBIT 23.3

William M. Cobb & Associates, Inc.

Worldwide Petroleum Consultants

12770 Coit Road, Suite 907	(972) 385-0354
Dallas, Texas 75251	Fax: (972) 788-5165
	E-Mail: office@wmcobb.com

February 29, 2016

Mr. Robert Watson, Jr.

President & CEO

EnerJex Resources, Inc.

4040 Broadway, Suite 508

San Antonio, TX 78209

Dear Mr. Watson:

William M. Cobb & Associates, Inc. (Cobb & Associates) has estimated the proved reserves and future net revenues attributable to certain oil and gas interests owned by EnerJex Resources, Inc. (EnerJex) as of January 1, 2016. This reserve report was independently prepared Cobb & Associates based upon information furnished by EnerJex and supplemented with information available from public sources.

The assets evaluated in this report are located in Colorado, Kansas, and Texas with the majority of the properties located in the Denver-Julesburg (DJ) Basin. It is our understanding that the proved reserves estimated in this report represents all of the proved resources owned by EnerJex as of January 1, 2016.

Cobb & Associates has prepared the estimates contained in this report with respect to reserve quantities and categorization, future production forecasts, future net revenues, and discounted value of such future revenues in accordance with the regulations and definitions of the US Securities and Exchange Commission (SEC) Regulation S-X, Rule 4-10(a). The estimates of proved reserves and future revenue are consistent with the standards of the SEC for the public reporting of oil and gas reserves and conform to Financial Accounting Standards Board (FASB) Accounting Standards Codification Topic 932, Extractive Activities – Oil and Gas, except that per well overhead expenses are excluded for operated properties and future income taxes are excluded for all properties.

This analysis has been completed concurrent with the date of this report; which has been prepared for EnerJex’s use in filing its annual SEC reports. In our opinion, the data, methodology, procedures, and assumptions used in preparing this report for EnerJex are appropriate for estimating oil and gas reserves and consistent with generally accepted petroleum engineering principles and practices.

RESERVE AND CASH FLOW SUMMARIES

Table 1 is a summary of EnerJex’s unrisked net proved reserves and the undiscounted and discounted cash flows prior to federal income tax as of January 1, 2016. The table provides detailed reserve information by sub-category for proved reserves. None of the values presented in this table are intended to represent an estimate of fair market value for EnerJex’s properties. Proved reserves are classified as proved developed producing (PDP), proved non-producing (PNP), and proved undeveloped (PUD) in this report.

Mr. Robert Watson, Jr.

February 29, 2016

Page 2

TABLE 1

ENERJEX RESOURCES, INC.

TOTAL PROVED RESERVES

AS OF JANUARY 1, 2016

	Net Reserves						Net Costs						Future Net Cash Flow
Reserve Category	Oil  (MBBL)		Gas  (MMCF)		NGL  (MBBL)		Future Net Income M$		OPEX & Taxes M$		Investment M$		Undiscounted M$		Discounted at 10% M$
PDP		956.6		256.1		5.1		41,003		30,332		-0-		10,671		5,516
PNP		372.6		2,586.9		43.9		19,338		11,791		2,558		4,990		1,511
PUD		152.6		3,422.2		0.0		13,746		3,893		3,344		6,509		1,743
Total		1,481.7		6,265.1		48.9		74,087		46,015		5,902		22,170		8,770

Note: Columns may not add due to rounding.

Oil volumes, which include condensate, and NGL volumes are expressed in thousands of stock tank barrels (MBBL). A stock tank barrel is equivalent to 42 United States gallons at 60 degrees Fahrenheit and atmospheric pressure. Gas volumes are expressed in millions of standard cubic feet (MMCF) as measured at 60 degrees Fahrenheit and the legal base pressure.

PRODUCT PRICES

This evaluation has utilized NYMEX commodity prices consistent with SEC standards, which is the unweighted average of the “first-day-of-the-month pricing” for the 12 months ending December 2015. Oil and gas prices are referenced to NYMEX West Texas Intermediate (WTI) and NYMEX Henry Hub (HH) pricing, respectively. The SEC oil price is $50.28 per barrel while the SEC gas price is $2.58 per MMBTU. Product prices used in the revenue forecasts have been adjusted for quality, location, and BTU content based on EnerJex’s lease operating statements. Net prices after adjustments are shown in Table 2 by State. Commodity prices have been held constant in this evaluation.

TABLE 2  

ENERJEX RESOURCES, INC.

AVERAGE NET PRODUCT PRICING

AS OF JANUARY 1, 2016

State	Oil Price $/BBL		Gas Price  $/MCF		NGL Price  $/BBL
Colorado		41.33		1.75		10.08
Kansas		44.10		0.00		0.00
Texas		38.72		0.00		0.00
Total		42.25		1.75		10.08

Mr. Robert Watson, Jr.

February 29, 2016

Page 3

COSTS

Lease operating cost data were based on historical information furnished by EnerJex for the most recent twelve month period. Based on this data, monthly operating costs were estimated for each producing property. These operating costs were estimated to cover normal operations including artificial lift, compression, and water handling. For non-operated properties, these costs included per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs for the operated properties include only direct lease- and field-level costs. Operating costs have been divided into per-well costs and per-unit-of-production costs for those properties reported on a lease basis. Based on our experience, the operating cost data appears reasonable. The operating costs were not escalated in the cash flow analysis.

Capital investments were provided by EnerJex and incorporated in our analysis as appropriate. Drilling, completion, workover, and facility cost estimates were based on AFEs prepared by EnerJex or recent expenditures in the area. The cost estimates provided appear reasonable and were not escalated in the cash flow analysis. Estimates in this report do not include any salvage value for the lease and well equipment or abandonment costs.

RESERVE METHODOLOGY

Oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate may be recoverable in future years from known reservoirs under expected economic and operating conditions. Reserves are considered proved if economic productivity is supported by either actual production or conclusive formation tests. Probable and possible reserves are unproved reserves and have a higher degree of uncertainty for recovery than proved reserves. Reserve definitions used by Cobb & Associates are consistent with definitions set forth by the SEC.

The reserves included in this report are estimates only and should not be construed as being exact quantities. Governmental policies, uncertainties of supply and demand, the prices actually received for the reserves, and the costs incurred in recovering such reserves, may vary from the price and cost assumptions in this report. In any case, estimates of reserves and revenues may increase or decrease as a result of future operations.

Reserve estimates were prepared using generally accepted petroleum engineering principles and practices. The method, or combination of methods, utilized in the study of each property or reservoir included an assessment of the stage of reservoir development, quality of data, and length of production history. The basis for this reserve determination was geological and engineering data and historical performance information furnished by EnerJex and supplemented with publicly available production data.

Cobb & Associates personnel reviewed the available technical information and performance data to estimate ultimate recoveries for each reservoir or well using performance analysis, volumetric analysis, and analogy. The methodology used in the study of each property or reservoir was based on standard geological and engineering methods that incorporate all information available at the time of its application. Reserve classification was based on the status of the well as of January 1, 2016.

Mr. Robert Watson, Jr.

February 29, 2016

Page 4

Reserve estimates are a function of the quality of data available and of engineering and geological interpretation and, as such, are strictly technical judgments. We believe the reserve estimates prepared in this report are representative and are within reasonable ranges of uncertainty for the properties studied. However, they are estimates and subject to revision based on additional performance and technical data obtained subsequent to the publication date of these estimates.

Cobb & Associates has not examined titles to the appraised properties nor has the actual degree of interest owned been independently confirmed. This information has been furnished by EnerJex and accepted as accurate. In evaluating available information concerning this appraisal, we have excluded from our consideration all matters as to which legal or accounting interpretation, rather than engineering, may be controlling. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering data and conclusions necessarily represent only informed professional judgments.

Cobb & Associates is an independent consulting firm. Our compensation is not contingent on the results obtained or reported. This report was prepared by an associate of the firm who is a licensed professional engineer with more than 30 years of experience in the estimation, assessment, and evaluation of oil and gas reserves. The work papers of Cobb & Associates associated with this evaluation, including the data provided by EnerJex, are on file in our offices.

Sincerely,
WILLIAM M. COBB & ASSOCIATES, INC.
Texas Registered Engineering Firm F-84
Michael L. Wiggins, Ph.D., P.E.
Senior Vice President

MLW:ar

M: Enerjex: Letter Report 022916

EX-23.4

EXHIBIT 23.4

January 22, 2016

Mr. Robert Watson Jr.

President and CEO

Enerjex Resources

4040 Broadway, Suite 508

San Antonio, Texas 78209

Dear Mr. Watson:

The following reserve report was independently prepared by MHA Petroleum Consultants, LLC based upon information supplied to them by Enerjex Resources, Inc.

In accordance with your request, we have evaluated the assets of Enerjex Resources (Enerjex), as of January 1, 2015. This includes the proved reserves and future revenue to the Enerjex interest’s in certain oil and gas properties located in Colorado, Nebraska, Kansas, and Texas. It is our understanding that the proved reserves estimated herein constitute all of the proved reserves owned by Enerjex. We have examined the estimates with respect to reserves quantities, reserves categorization, future producing rates, future net revenue, and the present value of such future net revenue, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). The estimates of reserves and future revenue have been prepared in accordance with the definitions and regulations of the SEC and conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas, except that per-well overhead expenses are excluded for the operated properties and future income taxes are excluded for all properties. We completed our analysis on or about the date of this letter. This report has been prepared for Enerjex's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

The following table sets forth our estimates of the net reserves and future net revenue, as of January 1, 2015 for the proved properties:

Enerjex Resources Proved Reserves Estimated Net Reserve and Income Data As of January 1, 2015
	Net Remaining Reserves
Reserve Category	Oil MBBL	Gas MMCF	NGL MBBL	Future Net Income M$	Direct Operating Expense & Taxes M$	Equity Investment M$	Undisc. Net Cash Flow M$	Discounted Net Cash Flow @ 10% M$
PDP	1,844.7	1,804.2	76.7	164,938.8	64,623.1	9.0	100,306.8	42,258.7
PNP	426.5	2,313.3	14.2	42,386.2	15,277.2	3,178.1	23,930.9	9,683.5
PUD	675.3	4,059.9	0.0	75,232.8	21,219.2	10,549.5	43,464.2	12,376.5
Total Proved	2,946.5	8,177.4	90.9	282,557.8	101,119.5	13,736.6	167,701.9	64,318.7

The oil volumes shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

Oil and gas prices used are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period covering 2014, consistent with SEC standards. The SEC oil price was $94.99/bbl, while SEC natural gas price was $4.35/MMBTU. Adjustments to these prices were made based on regional differentials and result in the net prices shown below:

STATE	OIL PRICE $/BBL	GAS PRICE $/MCF	NGL PRICE $/BBL
Colorado	81.78	3.19	27.72
Kansas	88.01	0.00	0.00
Nebraska	0.00	4.35	0.00
Texas	86.21	0.00	0.00

Operating costs are based on historical operating expense records. For the nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs for the operated properties include only direct lease- and field-level costs. Operating costs have been divided into per-well costs and per-unit-of-production costs for those properties reported on a lease basis. Capital costs are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Operating costs and capital costs are not escalated for inflation. Estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, estimates of MHA are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Enerjex, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing these estimates.

MHA uses standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to establish the conclusions set forth herein. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

Supporting data documenting this evaluation, along with data provided by Enerjex, are on file in our office. The technical person primarily responsible for conducting this analysis meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards.

We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,

MHA Petroleum Consultants, LLC

Leslie S. O’Connor

Managing Partner

CERTIFICATION OF QUALIFICATION

LESLIE S. O’CONNOR Managing Partner Petroleum Consultant

MHA Petroleum Consultants LLC

730 17^th Street, Suite 410

Denver, CO 80202

Phone: +1 303 277 0270

e-mail: loconnor@mhausa.com

EDUCATION

§ Extended BSc Geology with Applied Engineering, North Arizona University, 1978

§ Graduate Studies in Petroleum Engineering, Colorado School of Mines

PROFESSIONAL PROFILE

§ In excess of 35 years of petroleum engineering experience

§ Project management

§ Oil and gas field studies; United States, China, Mexico, South America, Western and Eastern Europe and Asia

§ Petrophysical studies

§ Unitization studies

§ Workover opportunity identification

§ Property evaluation, acquisition and divestitures

§ Reservoir and economic evaluation

§ Expert witness testimony

§ Gas deliverability and gas storage

§ Coal bed methane studies

§ Reservoir simulation

§ Waterflood feasibility studies

§ Development of reservoir engineering courses for industry

§ Studied fields in the United States (essentially all oil and gas areas), U.K. Offshore, China, Mexico, South America, Western and Eastern Europe and Asia

WORK EXPERIENCE

MHA PETROLEUM CONSULTANTS LLC, Denver, Colorado:

(August 2011) Managing Partner and Petroleum Consultant

(March 2008) President and Petroleum Consultant

(May 2006) Vice President and Petroleum Consultant

Responsible for Denver and International operations: project manager, reserve and economic evaluations, litigation support, reservoir studies, acquisition and divestiture support. Manages an organization of approximately 30 people with active engineering projects worldwide. In charge of staff recruitment, development of new business and new business contacts, as well as maintaining relationships with the company’s existing client base.

SPROULE ASSOCIATES INC., Denver, Colorado

(February, 1997 to May, 2006) U. S. Manager and Petroleum Consultant

Responsible for U. S. operations; opened U. S. office for Sproule Associates Ltd. Project manager, reservoir studies, property evaluations, litigation support, acquisition and divestiture support, CBM studies, petrophysical studies, feasibility studies, reservoir and economic studies of properties throughout the U. S.

GEOQUEST RESERVOIR TECHNOLOGIES, DENVER, Colorado:

(Formerly Intera Petroleum and Jerry R. Bergeson & Associates, Inc.)

(January, 1981 to January, 1997) Petroleum Consultant

Technical reservoir studies, property evaluations, secondary recovery studies, gas deliverability and gas storage, petrophysical studies, unitization studies, expert testimony, reservoir and economic studies of properties in Williston Basin, Rocky Mountain, Mid-Continent, West Coast and Gulf Coast areas of the U. S.

THUMS LONG BEACH COMPANY, Long Beach, California:

(January, 1980 to January, 1981) Development/Drilling Engineer

Responsible for design of highly deviated wellbores, completion design, field operations.

Dresser Atlas, Long Beach, California:

(August, 1978 to December, 1979) Field Engineer

Open hole logging operations and log interpretation. Supervised field crew, planned and operated offshore skid unit on Exxon’s offshore Belmont Island platform.

PROFESSIONAL MEMBERSHIPS:

§ Society of Petroleum Engineers – Recipient of the 1995 Regional Service Award

§ Society of Petroleum Engineers -Recipient of the 1990 Denver Section Service Award

§ Society of Petroleum Engineers-Recipient of the 2014 Regional Service Award

§ Society of Petroleum Evaluation Engineers

§ American Association of Petroleum Geologists

§ Society of Professional Well Log Analysts

§ Rocky Mountain Association of Geologists

¨ AAPG Certified Petroleum Geologist #5270; Board Certified by Division of Professional Affairs

¨ Licensed Professional Geoscientist, Texas #181

¨ Licensed Professional Geologist, Wyoming #PG-3059

¨ Licensed Professional Geologist, Utah #5207412-2250

¨ Licensed Professional Geoscientist, Louisiana #14

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Robert G. Watson, Chief Executive Officer of EnerJex Resources, Inc., certify that:

1. I have reviewed this Annual Report on Form 10-K of EnerJex Resources, 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, 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 quarterly report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our 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 report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our 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 principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure 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; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the 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 control over financial reporting.

Date: April 11, 2016

/s/  Robert G. Watson, Jr.

Robert G. Watson, Jr.

Chief Executive Officer

(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Douglas M. Wright, Chief Financial Officer of EnerJex Resources, Inc., certify that:

1. I have reviewed this Annual Report on Form 10-K of EnerJex Resources, 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, 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 quarterly report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our 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 report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our 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 principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure 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; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the 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 control over financial reporting.

Date: April 11, 2016

/s/  Douglas M. Wright

Douglas M. Wright

Chief Financial Officer

(Principal Financial Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Robert G. Watson, Jr., certify that:

1. I have reviewed this Annual Report on Form 10-K of EnerJex Resources, Inc., a Nevada corporation;

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, 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. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our 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 report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our 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 principles;

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

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 (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the 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 control over financial reporting.

Date:     April 11, 2016

/s/ Robert G. Watson, Jr.

Robert G. Watson, Jr.

Chief Executive Officer

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Douglas M. Wright, certify that:

1. I have reviewed this Annual Report on Form 10-K of EnerJex Resources, Inc., a Nevada corporation;

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, 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. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our 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 report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our 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 principles;

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

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 (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the 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 control over financial reporting.

Date:     April 11, 2016

/s/ Douglas M. Wright

Douglas M. Wright

Chief Financial Officer

XML

Document And Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Apr. 11, 2016	Jun. 30, 2015
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY
Entity Registrant Name	EnerJex Resources, Inc.
Entity Central Index Key	0000008504
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Smaller Reporting Company
Entity Public Float			$ 6.0
Trading Symbol	ENRJ
Entity Common Stock, Shares Outstanding		8,423,936

XML

Consolidated Balance Sheets - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Current Assets:
Cash	$ 3,101,682	$ 805,524
Accounts receivable	977,488	1,278,509
Derivative receivable	2,531,401	3,736,005
Inventory	144,327	248,218
Marketable securities	210,990	1,018,573
Deposits and prepaid expenses	247,325	324,339
Total current assets	7,213,213	7,411,168
Non-current assets:
Fixed assets, net of accumulated depreciation of $1,658,073 and $1,945,607	1,995,010	2,404,703
Oil & gas properties using full cost accounting, net of accumulated DD&A of $14,935,386 and $13,827,347	11,706,939	64,263,272
Derivative receivable	0	985,746
Other non-current assets	919,239	993,207
Total non-current assets	14,621,188	68,646,928
Total assets	21,834,401	76,058,096
Current liabilities:
Accounts payable	1,142,842	3,042,835
Accrued liabilities	1,131,057	1,060,926
Current portion of long term debt	1,986,660	35,595
Total current liabilities	4,260,559	4,139,356
Non-Current Liabilities:
Asset retirement obligation	3,091,478	2,906,093
Long-term debt	16,625,000	23,011,660
Other long-term liabilities	390,937	0
Total non-current liabilities	20,107,415	25,917,753
Total liabilities	$ 24,367,974	$ 30,057,109
Commitments and Contingencies
Stockholders’ (Deficit) Equity:
Common stock, $0.001 par value, 250,000,000 shares authorized; shares issued and outstanding - 8,423,936 at December 31, 2015 and 7,643,114 at December 31, 2014	$ 8,424	$ 7,643
Accumulated other comprehensive income	0	(552,589)
Paid in capital	68,848,944	63,825,998
Accumulated deficit	(71,391,881)	(17,280,817)
Total stockholders’ (deficit) equity	(2,533,573)	46,000,987
Total liabilities and stockholders’ (deficit) equity	21,834,401	76,058,096
10% Series A Cumulative Redeemable Perpetual Preferred Stock [Member]
Stockholders’ (Deficit) Equity:
Preferred Stock Value	938	752
Series B Convertible Preferred stock [Member]
Stockholders’ (Deficit) Equity:
Preferred Stock Value	$ 2	$ 0

XML

Consolidated Balance Sheets (Parenthetical) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	$ 1,658,073	$ 1,945,607
Properties using full-cost accounting	$ 14,935,386	$ 13,827,347
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	250,000,000	250,000,000
Common stock, shares issued	8,423,936	7,643,114
Common stock, shares outstanding	8,423,936	7,643,114
10% Series A Cumulative Redeemable Perpetual Preferred Stock [Member]
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, shares authorized	25,000,000	25,000,000
Preferred stock, shares issued	938,248	751,815
Preferred Stock Shares Outstanding	938,248	751,815
Series B Convertible Preferred stock [Member]
Preferred stock, par value	$ 0.001
Preferred stock, shares authorized	1,764
Preferred stock, shares issued	1,764
Preferred Stock Shares Outstanding	1,764

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Consolidated Statements of Operations - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Crude oil revenues	$ 4,525,089	$ 13,257,608
Natural gas revenues	353,633	1,035,759
Total revenues	4,878,722	14,293,367
Expenses:
Direct operating costs	4,501,940	6,762,248
Depreciation, depletion and amortization	1,311,446	3,549,245
Impairment of oil and gas assets	48,930,087	0
Professional fees	680,860	987,229
Salaries	1,927,552	1,479,688
Administrative expense	636,459	790,572
Total expenses	57,988,344	13,568,982
Income from operations	(53,109,622)	724,385
Other income (expense):
Interest expense	(1,293,407)	(1,305,194)
Gain (loss) on mark to market of derivative contracts	(2,194,679)	6,073,960
Other income (loss)	4,675,854	(919,527)
Total other income (expense)	1,187,768	3,849,239
(Loss) income before provision for income taxes	(51,921,854)	4,573,624
Provision for income taxes	0	0
Net (loss) income	(51,921,854)	4,573,624
Net (loss) income	(51,921,854)	4,573,624
Preferred dividends	(1,798,274)	(1,392,035)
Net (loss) income attributable to common stockholders	$ (53,720,128)	$ 3,181,589
Net (loss) income per common share basic and diluted	$ (6.50)	$ 0.42
Weighted Average Shares	8,265,716	7,492,007

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Consolidated Statement of Stockholders' Equity - USD ($)	Total	10% Series A Preferred Stock [Member]	Series B Preferred Stock [Member]	Preferred Stock [Member]	Common Stock [Member]	Accumulated Other Comprehensive Income [Member]	Paid-in Capital [Member]	Retained Deficit [Member]
Balance at Dec. 31, 2013	$ 28,910,601			$ 4,780	$ 7,307	$ (552,589)	$ 49,913,509	$ (20,462,406)
Balance (in shares) at Dec. 31, 2013				4,779,460	7,307,158
Stock issued for services	234,654				$ 17		234,637
Stock issued for services (in shares)					17,332
Stock based compensation	326,579						326,579
Issuance of 10% series A cumulative preferred stock and retirement of legacy preferred stock	13,347,564	$ 752		$ (4,780)	$ 319		13,351,273
Issuance of 10% series A cumulative preferred stock and retirement of legacy preferred stock (in shares)		751,815		(4,779,460)	318,624
Preferred stock dividends	(1,392,035)							(1,392,035)
Net loss for the year	4,573,624							4,573,624
Balance at Dec. 31, 2014	46,000,987	$ 752		$ 0	$ 7,643	(552,589)	63,825,998	(17,280,817)
Balance (in shares) at Dec. 31, 2014		751,815		0	7,643,114
Dividend received from Oakridge Energy	552,589					552,589
Stock issued for services	24,000	$ 3			$ 18		23,979
Stock issued for services (in shares)		3,000			17,500
Stock based compensation	396,124						396,124
Sale of common stock	825,506				$ 763		824,643
Sale of common stock (in shares)					763,322
Sale of series A preferred stock	2,014,593	$ 183					2,014,410
Sale of series A preferred stock (in shares)		183,433
Sale of series B preferred stock	1,763,792		$ 2				1,763,790
Sale of series B preferred stock (in shares)			1,764
Preferred stock dividends	(2,189,210)							(2,189,210)
Net loss for the year	(51,921,854)							(51,921,854)
Balance at Dec. 31, 2015	$ (2,533,573)	$ 938	$ 2	$ 0	$ 8,424	$ 0	$ 68,848,944	$ (71,391,881)
Balance (in shares) at Dec. 31, 2015		938,248	1,764	0	8,423,936

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Consolidated Statement of Stockholders' Equity (Parenthetical)	12 Months Ended
	Dec. 31, 2014
10% Series A Preferred Stock [Member]
Preferred Stock, Dividend Rate, Percentage	10.00%

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Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities
Net (loss) income	$ (51,921,854)	$ 4,573,624
Depreciation, depletion and amortization	1,311,446	3,549,245
Impairment of oil and gas assets	48,930,087	0
Stock, options and warrants issued for services	420,103	638,171
Accretion of asset retirement obligation	257,712	255,836
Settlement of asset retirement obligations	(2,244)	(102,930)
(Gain) loss on derivatives	2,190,350	(6,073,101)
Loss on sale of fixed assets	13,661	9,738
Adjustments to reconcile net (loss) income (used in) provided by operating activities:
Accounts receivable	301,021	1,183,237
Inventory	103,891	(9,424)
Deposits and prepaid expenses	77,014	(27,282)
Accounts payable	(1,899,993)	618,826
Accrued liabilities	70,131	(1,973,941)
Cash flows (used in) provided by operating activities	(148,675)	2,641,999
Cash flows from investing activities
Purchase of fixed assets	(7,876)	(298,903)
Oil and gas properties additions	(251,821)	(7,095,865)
Sale of oil and gas properties	2,867,305	987,939
Proceeds from sale of fixed assets	33,142	1,250
Dividend received from Oakridge Energy	1,360,172	0
Cash flows provided by (used in) investing activities	4,000,922	(6,405,579)
Cash flows from financing activities
Proceeds from sale of stock	4,603,812	13,347,564
Repayments of long-term debt	(4,935,595)	(14,035,595)
Borrowings on long-term debt	500,000	5,500,000
Preferred stock dividends paid	(1,798,274)	(1,392,035)
Deferred financing costs	73,968	(159,026)
Cash flows (used in) provided by financing activities	(1,556,089)	3,260,908
Increase (decrease) in cash and cash equivalents	2,296,158	(502,672)
Cash and cash equivalents, beginning	805,524	1,308,196
Cash and cash equivalents, end	3,101,682	805,524
Supplemental disclosures:
Interest paid	840,513	741,757
Income taxes paid	0	0
Non-cash investing and financing activities:
Share-based payments issued for services	420,103	638,171
Preferred dividends payable	$ 390,936	$ 0

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Summary of Accounting Policies

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Summary of Accounting Policies

Note 1 - Summary of Accounting Policies

Basis of Presentation

Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States. Our operations are considered to fall within a single industry segment, which are the acquisition, development, exploitation and production of crude oil and natural gas properties in the United States.  Our consolidated financial statements include our wholly owned subsidiaries.

All significant intercompany balances and transactions have been eliminated upon consolidation.  Certain reclassifications have been made to the prior year financial statements to conform to the current year presentation. 

Nature of Business

We are an independent energy company engaged in the business of producing and selling crude oil and natural gas. The crude oil and natural gas is obtained primarily by the acquisition and subsequent exploration and development of mineral leases.  Development and exploration may include drilling new exploratory or development wells on these leases. These operations are conducted primarily in Kansas, Colorado, Nebraska and Texas.

Use of Estimates in the Preparation of Financial Statements

The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.  Significant estimates included in the consolidated financial statements are: (1) oil and gas revenues and reserves; (2) depreciation, depletion and amortization; (3) valuation allowances associated with income taxes (4) accrued assets and liabilities; (5) stock-based compensation; (6) asset retirement obligations, (7) valuation of derivative instruments and (8) impairment of oil and gas assets.  Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates.  Actual results could differ from those estimates.

Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear any interest.  We regularly review receivables to insure that the amounts will be collected and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method.  Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.

 

Inventory

Inventories are comprised of crude oil held in storage and materials and supplies used in field operations. Crude oil inventories are valued at lower of cost or market, on a first-in, first out basis. Material and supplies are valued at lower of cost or market, based upon specific cost or by using a weighted average cost.

Share-Based Payments

The value we assign to the options and warrants that we issue is based on the fair market value as calculated by the Black-Scholes pricing model. To perform a calculation of the value of our options and warrants, we determine an estimate of the volatility of our stock.  We need to estimate volatility because there has not been enough trading of our stock to determine an appropriate measure of volatility. We believe our estimate of volatility is reasonable, and we review the assumptions used to determine this whenever we issue new equity instruments.

Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before the tax returns or when income items are recognized in the tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Deferred tax liabilities arise when income items are recognized in the financial statements before the tax returns or when expenses are recognized in the tax return prior to the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted.

We routinely assess the reliability of our deferred tax assets.  If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset is reduced by a valuation allowance.  In addition we routinely assess uncertain tax positions, and accrue for tax positions that are not more-likely-than-not to be sustained upon examination by taxing authorities.

Uncertain Tax Positions

We follow guidance in Topic 740 of the Codification for its accounting for uncertain tax positions. Topic 740 prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, we determine whether it is more-likely-than-not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based solely on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement.

We have no liability for unrecognized tax benefits recorded as of December 31, 2015 and 2014. Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the consolidated statement of operations or consolidated balance sheet as of December 31, 2015. In addition, we do not believe that there are any positions for which it is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase or decrease within the next twelve months. We recognize related interest and penalties as a component of income tax expense.

Tax years open for audit by federal tax authorities as of December 31, 2015 are the years ended December 31, 2012, 2013 and 2014. Tax years ending prior to 2012 are open for audit to the extent that net operating losses generated in those years are being carried forward or utilized in an open year.

Fair Value Measurements

Accounting guidance establishes a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and creates a fair value hierarchy that prioritizes the information used to develop those assumptions.  Additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy.  We incorporate a credit risk assumption into the measurement of certain assets and liabilities.

Cash and Cash Equivalents

We consider all highly liquid investment instruments purchased with original maturities of three months or less to be cash equivalents for purposes of the consolidated statements of cash flows and other statements. We maintain cash on deposit, which, can exceeds federally insured limits. We have not experienced any losses on such accounts and believe we are not exposed to any significant credit risk on cash and equivalents.

Revenue Recognition

Oil and gas revenues are recognized net of royalties when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collection of the revenue is probable. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met.

Fixed Assets

Property and equipment are recorded at cost. At December 31, 2015, Fixed Assets consisted of vehicles of $354,886, furniture and equipment of $552,288, building and leasehold improvements of $23,069 and gathering and compression systems of $2,722,839 as well as accumulated depreciation of vehicles $328,659, accumulated depreciation of furniture and fixtures of $478,578, accumulated depreciation of building and leasehold improvements of $13,342 and accumulated depreciation of gathering and compression systems of $837,494.

At December 31, 2014, Fixed Assets consisted of vehicles $967,483, furniture and equipment of $608,061, building and leasehold improvements of $23,069 and gathering and compression systems of $2,751,697, as well as accumulated depreciation of vehicles of $697,042, accumulated depreciation of furniture and fixtures of $494,333, accumulated depreciation of building and leasehold improvements of $9,386 and accumulated depreciation of gathering and compression systems of $744,846. 

Depreciation is determined by the use of the straight-line method of accounting using the estimated lives of the assets (3-15 years).  Expenditures for maintenance and repairs are charged to expense.

Debt issue costs

Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt utilizing the straight-line method of amortization over the estimated life of the debt.

Oil & Gas Properties and Long-Lived Assets

We follow the full cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities.

Proved properties are amortized using the units of production method (UOP). Currently we only have operations in the United States of America. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the cost of these reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (DD&A), estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs, less related salvage value. 

The cost of unproved properties are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed into service. Geological and geophysical costs not associated with specific properties are recorded as proved property immediately. Unproved properties are reviewed for impairment quarterly.

Impairment of long-lived assets is recorded when indications of impairment are present. Impairment is indicated when the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying value.  The carrying value of the assets is then reduced to their estimated fair value that is measured based on an estimate of future discounted cash flows.

Under the full-cost-method of accounting, the net book value of oil and gas properties, less deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is (a) the present value of future net revenues computed by applying current prices of oil & gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil & gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of 10 percent and assuming continuation of existing economic conditions plus (b) the cost of properties not being amortized plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized less (d) income tax effects related to differences between book and tax basis of properties. Future cash outflows associated with settling accrued retirement obligations are excluded from the calculation. Estimated future cash flows are calculated using end-of-period costs and an un-weighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months held flat for the life of the production, except where prices are defined by contractual arrangements.

Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the statement of operations. The ceiling calculation is performed quarterly. For the year ended December 31, 2015 impairments of $16,401,376, $11,421,613, $9,720,983 and $11,386,115 were record in the first, second, third and fourth quarters respectively. For the year ended December 31, 2014 there were no impairments resulting from the quarterly ceiling tests.

Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25%) of our reserve quantities are sold, in which case a gain or loss is recognized in income. In 2015 the Company sold its Cherokee project assets located in Eastern Kansas for net proceeds of $2,867,305. At the time of the sale the reserve quantities made up approximately 6.7% of total reserve quantities. Accordingly, the net proceeds reduced the carrying value of our oil and gas properties.

Asset Retirement Obligations

The asset retirement obligation relates to the plug and abandonment costs when our wells are no longer useful. We determine the value of the liability by obtaining quotes for this service and estimate the increase we will face in the future. We then discount the future value based on an intrinsic interest rate that is appropriate for us. If costs rise more than what we have expected there could be additional charges in the future, however, we monitor the costs of the abandoned wells and we will adjust this liability if necessary.

Major Purchasers

For the years ended December 31, 2015, and 2014 we sold our produced crude oil to ARM Energy Management, LLC, Coffeyville Resources Inc., Plains Marketing, L.P., MV Purchasing and Sunoco Logistics Inc. on a month-to-month basis and we sold our produced natural gas to United Energy Trading and Western Operating Company.

Marketable Securities Available for Sale

The Company classifies its marketable equity securities as available-for-sale and they are carried at fair market value, with the unrealized gains and losses included in accumulated other comprehensive income and reported in stockholders’ equity. The difference between historical cost and market totaled $552,589 for the year ended December 31, 2014. For the year ended December 31, 2015 the Company received a dividend of $1,360,172. This receipt of cash was first applied to the other comprehensive loss reported in stockholders’ equity and then to the carrying value of the security reported in current assets. This resulted in a new carrying value of $210,990 for this security. The Company expects future distributions and estimates that the sum of future distributions to be in excess of the remaining book value.

Net Income Per Common Share

Basic net income per share is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect, in periods in which they have a dilutive effect, the impact of common shares issuable upon exercise of stock options and warrants and conversion of convertible debt that are not deemed to be anti-dilutive. The dilutive effect of the outstanding stock options and warrants is computed using the treasury stock method.

For the year ended December 31, 2015, diluted net loss per share did not include the effect of 298,664 shares of common stock issuable upon the exercise of outstanding stock options as their effect would be anti-dilutive.

For the year ended December 31, 2014, diluted net income per share did not include the effect of  231,332 shares of common stock issuable upon the exercise of outstanding stock options as their exercise price was above market value.

Reclassifications

Certain reclassifications have been made to prior periods to conform to current presentations.

Recent Accounting Pronouncements Applicable to the Company

The Company does not believe there are any recently issued, but not yet effective; accounting standards that would have a significant impact on the Company’s financial position or results of operations.

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Going Concern

12 Months Ended

Dec. 31, 2015

Going Concern Disclosure [Abstract]

Going Concern Disclosure [Text Block]

Note 2 - Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern.

 

On October 3, 2011, the Company, entered into an Amended and Restated Credit Agreement with Texas Capital Bank, and other financial institutions and banks (“TCB” or “Bank”) that may become a party to the Credit Agreement from time to time. The facilities provided under the Amended and Restated Credit Agreement was to be used to refinance a prior outstanding revolving loan facility with TCB dated July 3, 2008, and for working capital and general corporate purposes. On August 15, 2014 the Company entered into an Eighth Amendment to the Amended and Restated Credit Agreement. Among other things the Eighth Amendment extended the maturity of the Agreement by three years to October 3, 2018. On August 12, 2015, the Company entered into a Tenth Amendment to the Amended and Restated Credit Agreement. Among other things the Tenth Amendment established the requirement of monthly borrowing base reductions commencing September 1, 2015 and continuing on the first of each month thereafter.

On April 1, 2016 the Company informed the Bank that it would cease making the mandatory monthly borrowing base reduction payments and did not make the required April 1, 2016 payment. The Company made its mandatory quarterly interest payment on April 6, 2016 and on April 7, 2016 entered into a Forbearance Agreement whereby the Bank agreed to not exercise remedies and rights afforded it under the Amended and Restated Credit Agreement for thirty days. The thirty day period will be used by the Company to pursue strategic alternatives.

The Company accesses a number of data bases and utilizes several consultants to monthly prepare commodity price projections used in its cash forecasting models. The models indicate it will have sufficient cash to satisfy obligation as they become due through the end of the first quarter of 2017, if it ceases to make the principle reduction called for by the Tenth Amendment entered into by the Company on August 12, 2015. If actual commodity prices are less than forecasted the Company would not have enough cash to meet obligations as they become due. Should this occur the Company could suspend quarterly interest payments, restructure, amend or refinance existing debt through private options or seek a protected reorganization under chapter 11 of the U.S. federal bankruptcy code.

This factor raises substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

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Equity Transactions

12 Months Ended

Dec. 31, 2015

Equity [Abstract]

Equity Transactions

Note 3 - Equity Transactions

Stock transactions in fiscal year ended December 31, 2015

On March 13, 2015, the Company issued in a registered offering 763,547 registered shares of its common stock together with 1,242.17099 shares of its newly designated Series B Convertible Preferred Stock (the “Preferred Stock”) convertible into 709,812 shares of common stock. We also issued in an unregistered offering, 521.62076 shares of Preferred Stock convertible into 298,069 shares of common stock, and warrants to purchase 1,771,428 shares of its common stock. The shareholder’s ability to convert a portion of the Preferred Stock and to exercise the warrant are restricted: (i) prior to the Company obtaining approval of the offering by its shareholders, which we expect to obtain before May 31, 2015, and (ii) pursuant to customary “blocker” provisions restricting the investor’s ownership to 9.99% of our outstanding common stock.

 

The Preferred Stock has a liquidation preference of $1,000 per share, and will be convertible at the option of the shareholder at a conversion ratio equal to approximately 571 shares of common stock for each one (1) share of Preferred Stock, subject to customary adjustments and anti-dilution price protection. Dividends are payable on the shares of Preferred Stock only if and to the extent that dividends are payable on the common stock into which the Preferred Stock is convertible. The Preferred Stock has no maturity date and can be redeemed by the Company beginning twelve months after the closing of the offering or upon a change of control. Each warrant will be exercisable for one share of common stock, for a period of five years beginning nine months after March 13, 2015, at a cash exercise price of $2.75 per share, and may be exercised on a cashless basis after that nine-month period if no effective registration statement covers the warrant shares by that time.

 

On May 13, 2015, the Company sold 183,433 shares of its 10% Series A Cumulative Redeemable Perpetual Preferred Stock at $12.50 per share for gross proceeds of approximately $2.3 million. The Company intends to use the net proceeds of this offering for general corporate purposes, including capital expenditures, working capital, preferred stock dividends, and repayment of outstanding borrowings under its senior credit facility.

 

The offering was made pursuant to a registration statement on Form S-3 (File No. 333-199030) previously filed and declared effective by the U.S. Securities and Exchange Commission (SEC). 

Stock transactions in fiscal year ended December 31, 2014

In 2014, 7,707 shares were issued to employees of the Company as compensation. The value of those shares was $59,298. Also in 2014, 9,625 shares were issued and 17,500 shares are owed (but not issued) for professional services rendered on behalf of the Company. The value of those share was $175,356.

Effective after the close of trading in EnerJex common stock on May 30, 2014, the Company affected a 1-for-15 reverse stock split, by which each share of EnerJex common stock was reclassified, and changed into 1/15th of a fully paid and non-assessable share of common stock. In lieu of fractions of a share, the Company paid to holders of fractions of a share cash equal to $11.25 per share, which was the minimum value designated in the amended and restated certificate of designations affecting the reverse stock split.

On June 16, 2014, we adopted the Amended and Restated Certificate of Designation modifying the terms of our then-existing Series A preferred stock. Concurrently with filing of that Amended and Restated Certificate of Designation, the holders of our existing Series A preferred stock exchanged each outstanding share of such existing Series A preferred stock for (i) a number of shares of our common stock into which such Series A preferred stock was then convertible immediately prior to the exchange (318,630 shares in the aggregate), and (ii) 112,658 shares of Series A preferred stock which was equal to the quotient determined by dividing (x) that portion of the holder’s original Series A preferred stock purchase price that had not yet been paid in dividends, by (y) $23.75.

On June 20, 2014, we closed an underwritten initial public offering of 639,157 shares of our Series A preferred stock at a purchase price of $23.75 per share for gross proceeds of $15,179,938. Costs associated with the offering were $1,832,374 for net proceeds of $13,347,564.

Effective September 30, 2014 the Board of Directors approved the retirement of 383,333 shares in held in the Treasury. Accordingly $2,551,000 was reclassified to Paid-in capital.

Option transactions

Officers (including officers who are members of the Board of Directors), directors, employees and consultants are eligible to receive options under our stock option plans.  We administer the stock option plans and we determine those persons to whom options will be granted, the number of options to be granted, the provisions applicable to each grant and the time periods during which the options may be exercised.  No options may be granted more than ten years after the date of the adoption of the stock option plans.

Each option granted under the stock option plans will be exercisable for a term of not more than ten years after the date of grant.  Certain other restrictions will apply in connection with the plans when some awards may be exercised.  In the event of a change of control (as defined in the stock option plans), the vesting date on which all options outstanding under the stock option plans may first be exercised will be accelerated.  Generally, all options terminate 90 days after a change of control. 

Stock Incentive Plan

The Board of Directors approved the EnerJex Resources, Inc. Stock Option Plan on August 1, 2002 (the “2002-2003 Stock Option Plan”). Originally, the total number of options that could be granted under the 2002-2003 Stock Option Plan was not to exceed 26,666 shares. In September 2007 our stockholders approved a proposal to amend and restate the 2002-2003 Stock Option Plan to increase the number of shares issuable to 66,666.  On October 14, 2008 our stockholders approved a proposal to amend and restate the 2002-2003 Stock Option Plan to (i) rename it the EnerJex Resources, Inc. Stock Incentive Plan (the “Stock Incentive Plan”), (ii) increase the maximum number of shares of our common stock that may be issued under the Stock Incentive Plan to 83,333, and (iii) add restricted stock as an eligible award that can be granted under the Stock Incentive Plan.

On December 31, 2010 we granted 60,000 options that vest ratably over a 48 month period and are exercisable at $6.00 per share to an Officer of the company. The term of the options is 5 years. The fair value of the options as calculated using the Black-Scholes model was $307,751.  The amount recognized as expense for the year ended December 31, 2015 was zero and for the year ended December 31, 2014 was $76,938.

2013 Stock Incentive Plan

The Board and stockholders approved the adoption of the 2013 Stock Incentive Plan (“Plan”). The Plan reserves 333,300 shares of our common stock for the granting of options and issuance of restricted shares to our employees, officers, directors, and consultants. The Plan increases reserved shares annually based on plan provisions.

In 2015, we granted 67,332 options to employees and directors.  Fifty percent of these options vest one year after the date of the grant.  The remaining options vest ratably each month over a two year period.   The fair value of the option on the date of the grant calculated using the Black-Scholes model was $295,932 using the following weighted average assumptions: exercise price of $9.85 per share; common stock price of ranging from $.30 to $2.00 per share; volatility ranging from 70% to 72%; term of three years; dividend yield of 0%; interest rate of 1.41%. 

In 2014, we granted 2,367 options to employees. Thirty-three percent of these options vest one year after the date of the grant.   The remaining options vest ratably each month over a two year period.   The fair value of the option on the date of the grant calculated using the Black-Scholes model was $12,178 using the following weighted average assumptions: exercise price of $10.50 per share; common stock price of $7.95 per share; volatility of 72%; term of three years; dividend yield of 0%; interest rate of .47%.

We expensed $374,433 and $420,103 for the years ended December 31, 2014 and December 31, 2015 respectively for options granted. We also expensed $76,938 for the year ended December 31, 2014 for options recorded as prepaid assets.

A summary of stock options is as follows:

			Weighted Ave.				Weighted Ave.
	Options		Exercise Price		Warrants		Exercise Price
Outstanding January 1, 2014		231,133	$	9.36			$
Granted		2,367		10.50
Cancelled		(2,168)		(10.50)
Exercised		-		-		-		-
Outstanding December 31, 2014		231,332	$	9.33		-	$	-
Granted		67,332				1,904,286		2.75
Cancelled		(10,333)		(10.50)		-		-
Exercised						-		-
Outstanding December 31, 2015		288,331	$	10.17		1,904,286	$	2.75

The number of options that were vested at December 31, 2015 was 231,629. The number of options that were not vested at December 31, 2015 was 56,702.

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Asset Retirement Obligation

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation

Note 4 - Asset Retirement Obligation

Our asset retirement obligations relate to the abandonment of oil and gas wells. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, inflation rates and credit adjusted risk-free interest rates. The following shows the changes in asset retirement obligations:

Asset retirement obligations, January 1, 2014	$	2,687,801
Liabilities incurred during the period		65,385
Liabilities settled during the year		(102,929)
Accretion		255,836
Asset retirement obligations, December 31, 2014	$	2,906,093
Release of liabilities associated with the sale of oil properties		(70,083)
Liabilities settled during the year		(2,244)
Accretion		257,712
Asset retirement obligations, December 31, 2015	$	3,091,478

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Long-Term Debt

12 Months Ended

Dec. 31, 2015

Long-Term Debt [Abstract]

Long-Term Debt

Note 5 - Long-Term Debt

Senior Secured Credit Facility

On October 3, 2011, the Company, DD Energy, Inc., EnerJex Kansas, Inc., Black Sable Energy, LLC and Working Interest, LLC (“Borrowers”) entered into an Amended and Restated Credit Agreement with Texas Capital Bank, and other financial institutions and banks that may become a party to the Credit Agreement from time to time. The facilities provided under the Amended and Restated Credit Agreement are to be used to refinance Borrowers prior outstanding revolving loan facility with Bank, dated July 3, 2008, and for working capital and general corporate purposes.

At our option, loans under the facility will bear stated interest based on the Base Rate plus Base Rate Margin, or Floating Rate plus Floating Rate Margin (as those terms are defined in the Credit Agreement). The Base Rate will be, for any day, a fluctuating rate per annum equal to the higher of (a) the Federal Funds Rate plus 0.50% and (b) the Bank’s prime rate. The Floating Rate shall mean, at Borrower’s option, a per annum interest rate equal to (i) the Eurodollar Rate plus Eurodollar Margin, or (ii) the Base Rate plus Base Rate Margin (as those terms are defined in the Amended and Restated Credit Agreement). Eurodollar borrowings may be for one, two, three, or six months, as selected by the Borrowers. The margins for all loans are based on a pricing grid ranging from 0.00% to 0.75% for the Base Rate Margin and 2.25% to 3.00% for the Floating Rate Margin based on the Company’s Borrowing Base Utilization Percentage (as defined in the Amended and Restated Credit Agreement).

We entered into a First Amendment to Amended and Restated Credit Agreement and Second Amended and Restated Promissory Note in the amount of $50,000,000 with Texas Capital Bank, which closed on December 15, 2011. The Amendment reflects the addition of Rantoul Partners, as an additional Borrower and adds as additional security for the loans the assets held by Rantoul Partners.

On August 31, 2012, we entered into a Second Amendment to Amended and Restated Credit Agreement with Texas Capital Bank. The Second Amendment: (i) increased the borrowing base to $7,000,000 (ii) reduced the minimum interest rate to 3.75% and (iii) added additional new leases as collateral for the loan.

On November 2, 2012, we entered into a Third Amendment to Amended and Restated Credit Agreement with Texas Capital Bank. The Third Amendment (i) increased the borrowing base to $12,150,000 and (ii) clarified certain continuing covenants and provided a limited waiver of compliance with one of the covenants so clarified for the fiscal quarter ended December 31, 2011.

On January 24, 2013, we entered into a Fourth Amendment to Amended and Restated Credit Agreement, which was made effective as of December 31, 2012 with Texas Capital Bank.  The Fourth Amendment reflects the following changes: (i) the Bank consented to the restructuring transactions related to the dissolution of Rantoul Partners, and (ii) the Bank terminated a Limited Guaranty, as defined in the Credit Agreement, executed by Rantoul Partners in favor of the Bank

On April 16, 2013, the Bank increased our borrowing base to $19.5 million.

On September 30, 2013, the Company entered into a Fifth Amendment to the Amended and Restated Credit Agreement.   The Fifth Amendment reflects the following changes:  (i) an expanded principal commitment amount of the Bank to $100,000,000; (ii) increased the Borrowing Base to $38,000,000; (iii) added Black Raven Energy, Inc. to the Credit Agreement as borrower parties; (iv) added certain collateral and security interests in favor of the Bank; and (v) reduced the Company’s current interest rate to 3.30%.

On November 19, 2013, we entered into a Sixth Amendment to the Amended and Restated Credit Agreement. The Sixth Amendment reflects the following changes: (i) the addition of Iberia Bank as a participant in our credit facility, and (ii) a technical correction to our covenant calculations.

On May 22, 2014, we entered into a Seventh Amendment to the Amended and Restated Credit Agreement. The Seventh Amendment reflects the Bank’s consent to our issuance of up to 850,000 shares of our 10% Series A Cumulative Redeemable Perpetual Preferred Stock.

On August 15, 2014 we entered into an Eighth Amendment to the Amended and Restated Credit Agreement. The Eighth Amendment reflects the following changes: (i) the borrowing base was increased from $38 million to $40 million, and (ii) the maturity of the facility was extended by three years to October 3, 2018.

On April 29, 2015, we entered into a Ninth Amendment to the Amended and Restated Credit Agreement. In the Ninth Amendment, the Banks (i) re-determined the Borrowing Base based upon the recent Reserve Report dated January 1, 2015, (ii) imposed affirmative obligations on the Company to use a portion of proceeds received with regard to future sales of securities or certain assets to repay the loan, (iii) consented to non-compliance by the Company with certain terms of the Credit Agreement, (iv) waived certain provisions of the Credit Agreement, and (v) agreed to certain other amendments to the Credit Agreement.

On May 1, 2015, the Borrowers and the Banks entered into a Letter Agreement to clarify that up to $1,000,000 in proceeds from any potential future securities offering will be unencumbered by the Banks’ Liens as described in the Credit Agreement through November 1, 2015, and that, until November 1, 2015, such proceeds shall not be subject to certain provisions in the Credit Agreement prohibiting the Company from declaring and paying dividends that may be due and payable to holders of securities issued in such potential offerings or issued prior to the Letter Agreement.

On August 12, 2015, we entered into a Tenth Amendment to the Amended and Restated Credit Agreement. The Tenth Amendment reflects the following changes: (i) allow the Company to sell certain oil assets in Kansas, (ii) allow for approximately $1,300,000 of the proceeds from the sale to be reinvested in Company owned oil and gas projects and (iii) apply not less than $1,500,000 from the proceed of the sale to outstanding loan balances.

On November 13, 2015, the Company entered into a Eleventh Amendment to the Amended and Restated Credit Agreement. The Eleventh Amendment reflects the following changes: (i) waived certain provisions of the Credit Agreement, (ii) suspend certain hedging requirements, and (iii) to make certain other amendments to the Credit Agreement.

Our current borrowing base is $18,600,000, of which we had borrowed $18,600,000 as of December 31, 2015. The interest rate on amounts borrowed under our credit facility during 2015 was approximately 4.3% and for the year ended December 31, 2014, the interest rate on amounts borrowed was approximately 3.3%. This facility expires on October 3, 2018. 

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 6 - Commitments and Contingencies

Rent expense for the years ended December 31, 2015 and 2014 was approximately $149,000 and $159,000 respectively. Future non-cancellable minimum lease payments are approximately, $147,000 for 2016, $145,000 for 2017, $91,000 for 2018 and $77,000 for 2019.

We, as a lessee and operator of oil and gas properties, are subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject to the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area.  As of December 31, 2015, we have no reserve for environmental remediation and are not aware of any environmental claims.

As of December 31, 2015, the Company has an outstanding irrevocable letter of credit in the amount of $50,000 issued in favor of the Texas Railroad Commission. This letter of credit is required by the Commission by all companies operating in the state in accordance with limits prescribed by the Texas Railroad Commission.

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Income Taxes

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Income Tax

Note 7 - Income Taxes

There was no current or deferred income tax expense (benefit) for the years ended December 31, 2015 and December 31, 2014.

The following table sets forth a reconciliation of the provision for income taxes to the statutory federal rate:

	Year Ended December 31,
	2015			2014
Statutory tax rate		35.00	%		35.00	%
State tax rate, net of federal tax		1.90	%		1.37	%
Other permanent items		0.00	%		0.05	%
Change in valuation allowance		(36.90)	%		(36.42)	%
Effective tax rate		0.00	%		0.00	%

Significant components of the deferred tax assets and liabilities are as follows:

	Year Ended December 31,
	2015		2014
Non-current deferred tax asset:
Oil and gas costs and long-lived assets	$	14,513,571	$	(1,038,092)
Derivative instruments		934,340		(1,717,301)
Net operating loss carry-forward		29,532,954		25,915,146
Valuation allowance		(44,980,865)		(23,159,753)
Net deferred tax asset (liability)	$	-	$	-

At December 31, 2015, we have a net operating loss carry forward of approximately $81 million expiring in 2021-2036 that is subject to certain limitations on an annual basis. A valuation allowance has been established against net operating losses where it is more likely than not that such losses will expire before they are utilized.

The Company incurred a change of control as defined by the Internal Revenue Code. Accordingly, the rules will limit the utilization of the Company’s net operating losses. The limitation is determined by multiplying the value of the stock immediately before the ownership change by the applicable long-term exempt rate. It is estimated that approximately $40.9 million of net operating losses may be subject to an annual limitation. Any unused annual limitation may be carried over to later years. The amount of the limitation may under certain circumstances be increased by the built-in gains in assets held by the Company at the time of the change that are recognized in the five-year period after the change.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2015

Fair Value Measurements [Abstract]

Fair Value Measurements

Note 8 - Fair Value Measurements

We hold certain financial assets which are required to be measured at fair value on a recurring basis in accordance with the Statement of Financial Accounting Standard No. 157, “Fair Value Measurements” (“ASC Topic 820-10”).   ASC Topic 820-10 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).  ASC Topic 820-10 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants on the measurement date. A fair value measurement assumes that the transaction to sell the asset or transfer the liability occurs in the principal market for the asset or liability. The three levels of the fair value hierarchy under ASC Topic 820-10 are described below:

Level 1. Valuations based on quoted prices in active markets for identical assets or liabilities that an entity has the ability to access.  We believe receivables, payables and our debt approximate fair value at December 31, 2015.

Level 2. Valuations based on quoted prices for similar assets or liabilities, quoted prices for identical assets or liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable data for substantially the full term of the assets or liabilities.  We consider the derivative liability to be Level 2.  We determine the fair value of the derivative liability utilizing various inputs, including NYMEX price quotations and contract terms.

Level 3. Valuations based on inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. We consider the marketable securities to be a Level 3. Our derivative instruments consist of fixed price commodity swaps.  

	Fair Value Measurement
	Level 1		Level 2		Level 3
Crude oil contracts	$	-	$	2,531,401	$	-
Marketable securities	$	-	$	-	$	210,990

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Derivative Instruments

12 Months Ended

Dec. 31, 2015

Derivative Instruments [Abstract]

Derivative Instruments

Note 9 - Derivative Instruments

We have entered into certain derivative or physical arrangements with respect to portions of our crude oil production to reduce our sensitivity to volatile commodity prices and/or to meet hedging requirements under our Credit Facility.  We believe that these derivative arrangements, although not free of risk, allow us to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations.  However, derivative arrangements limit the benefit of increases in the prices of crude oil.  Moreover, our derivative arrangements apply only to a portion of our production.

We have an Inter-creditor Agreement in place between the Company; our counterparties, BP Corporation North America, Inc. and Cargill Incorporated and our agent, Texas Capital Bank, N.A., which allows Texas Capital Bank to also act as agent for the counterparties for the purpose of holding and enforcing any liens or security interests resulting from our derivative arrangements.  Therefore, we generally are not required to post additional collateral, including cash.

The following derivative contracts were in place at December 31, 2015:

	Term	Monthly Volumes  (1)			Price/Bbl		Fair Value
Deferred premium put	1/16-6/16		9,000	Bbls	$	85.00	$	2,170,912
Deferred premium put	7/16-12/16		5,000	Bbls	$	60.00		360,489
							$	2,531,401

⁽¹⁾      Monthly volumes are the weighted average throughout the period.

The total fair value of derivative contracts is shown in both current and non-current assets on the balance sheet.  We recorded a loss related to our derivative contracts for the year ended December 31, 2015 of $2,194,679 and a gain of $6,073,960 for the year ended December 31, 2014.

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Net Income Per Common Share

12 Months Ended

Dec. 31, 2015

Earnings Per Share [Abstract]

Earnings Per Share

Note 10 – Net Income Per Common Share

The Company reports earnings per share in accordance with ASC Topic 260-10, “Earnings per Share.” Basic earnings per share is computed by dividing income available to common shareholders by the weighted average number of common shares available. Diluted earnings per share is computed similar to basic earnings per share except that the denominator is increased to include the number of additional common shares that would have been outstanding if the potential common shares had been issued and if the additional common shares were dilutive.

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Impairment of Oil and Gas Properties

12 Months Ended

Dec. 31, 2015

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Impairment of Oil and Gas Properties

Note 11 – Impairment of Oil and Gas Properties

 

Pursuant to full cost accounting rules, the Company must perform a ceiling test each quarter on its proved oil and natural gas assets within each separate cost center. All of the Company’s costs are included in one cost center because all of the Company’s operations are located in the United States. The Company’s ceiling test was calculated using trailing twelve-month, unweighted-average first-day-of-the-month prices for oil and natural gas as of December 31, 2015, which were based on a West Texas Intermediate oil price of $52.73 per Bbl and a Henry Hub natural gas price of $2.76 per MMBtu (adjusted for basis and quality differentials), respectively. The trailing twelve-month, unweighted-average first-day-of-the-month prices for oil and natural gas as of September 30, 2015, was based on a West Texas Intermediate oil price of $59.21 per Bbl and a Henry Hub natural gas price of $3.06 per MMBtu (adjusted for basis and quality differentials), respectively. The twelve-month, unweighted-average first-day-of-the –month price as of June 30, 2015 was $71.68 per Bbl and $3.39per MMBtu The twelve-month, unweighted-average first-day-of-the –month price as of March 31, 2015 was $78.82 per Bbl and $3.74 per MMBtu (adjusted for basis and quality differentials), respectively. Utilizing these prices, the calculated ceiling amount was less than the net capitalized cost of oil and natural gas properties as of December 31, 2015, and as a result, a pre-tax write-down of $11.4 million was recorded. Utilizing these prices, the calculated ceiling amount was less than the net capitalized cost of oil and natural gas properties as of September 30, 2015, and as a result, a pre-tax write-down of $9.7 million was recorded. At June 30, 2015 the calculated ceiling amount was less than net capitalized cost of oil and natural gas properties resulted in a pre-tax write-down of $11.4 million. At March 31, 2015 the calculated ceiling amount was less than net capitalized cost of oil and natural gas properties resulted in a pre-tax write-down of $16.4 million. Additional material write-downs of the Company’s oil and gas properties could occur in subsequent quarters in the event that oil and natural gas prices remain at current depressed levels, or if the Company experiences significant downward adjustments to its estimated proved reserves.

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Other Income

12 Months Ended

Dec. 31, 2015

Other Income and Expenses [Abstract]

Other Income and Other Expense Disclosure

Note 12 – Other Income

The following table depicts the components of other income for the years ended December 31, 2015 and December 31, 2014:

	Year ended		Year ended
	December 31,		December 31,
	2015		2014
Realized gain (loss) clearing of derivative contracts	$	4,662,012	$	(914,694)
Loss on sale of fixed assets		(13,661)		(9,738)
Miscellaneous income		27,105		4,004
Interest income		398		901
Other Income	$	4,675,854	$	(919,527)

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Subsequent Events

12 Months Ended

Dec. 31, 2015

Subsequent Events [Abstract]

Subsequent Events

Note 13 - Subsequent Events 

On October 3, 2011, the Company, entered into an Amended and Restated Credit Agreement with Texas Capital Bank, and other financial institutions and banks (“TCB” or “Bank”) that may become a party to the Credit Agreement from time to time. The facilities provided under the Amended and Restated Credit Agreement was to be used to refinance a prior outstanding revolving loan facility with TCB dated July 3, 2008, and for working capital and general corporate purposes. On August 15, 2014 the Company entered into an Eighth Amendment to the Amended and Restated Credit Agreement. Among other things the Eighth Amendment extended the maturity of the Agreement by three years to October 3, 2018. On August 12, 2015, the Company entered into a Tenth Amendment to the Amended and Restated Credit Agreement. Among other things the Tenth Amendment established the requirement of monthly borrowing base reductions commencing September 1, 2015 and continuing on the first of each month thereafter.

On April 1, 2016 the Company informed the Bank that it would cease making the mandatory monthly borrowing base reduction payments and did not make the required April 1, 2016 payment. The Company made its mandatory quarterly interest payment on April 6, 2016 and on April 7, 2016 entered into a Forbearance Agreement whereby the Bank agreed to not exercise remedies and rights afforded it under the Amended and Restated Credit Agreement for thirty days. The thirty day period will be used by the Company to pursue strategic alternatives.

The Company accesses a number of data bases and utilizes several consultants to monthly prepare commodity price projections used in its cash forecasting models. The models indicate it will have sufficient cash to satisfy obligation as they become due through the end of the first quarter of 2017, if it ceases to make the principle reduction called for by the Tenth Amendment entered into by the Company on August 12, 2015. If actual commodity prices are less than forecasted the Company would not have enough cash to meet obligations as they become due. Should this occur the Company could suspend quarterly interest payments, restructure, amend or refinance existing debt through private options or seek a protected reorganization under chapter 11 of the U.S. federal bankruptcy code.

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Supplemental Oil and Gas Reserve Information (Unaudited)

12 Months Ended

Dec. 31, 2015

Supplemental Oil Reserve Information [Abstract]

Supplemental Oil and gas Reserve Information (Unaudited)

Note 14 - Supplemental Oil and Gas Reserve Information (Unaudited)

Results of operations from oil and gas producing activities

The following table shows the results of operations from the Company’s oil and gas producing activities.  Results of operations from these activities are determined using historical revenues, production costs and depreciation and depletion. The results of operations from the Company’s oil and gas producing activities below exclude non-oil and gas revenues, general and administrative expenses, interest income and interest expense. Income tax expense was determined by applying the statutory rates to pretax operating results.

	Year Ended		Year Ended
	December 31,		December 31,
	2015		2014
Production revenues	$	4,878,722	$	14,293,368
Production costs		(4,501,940)		(6,762,248)
Depletion and depreciation		(1,108,039)		(3,259,442)
Income tax		255,940		(1,495,087)
Results of operations for producing activities	$	(475,317)	$	2,776,591

Capitalized costs

The following table summarizes the Company’s capitalized costs of oil and gas properties.

	Year Ended		Year Ended
	December 31,		December 31,
	2015		2014
Properties subject to amortization	$	26,642,325	$	78,090,619
Accumulated depletion		(14,935,386)		(13,827,347)
Net capitalized costs	$	11,706,939	$	64,263,272

Cost incurred in property acquisition, exploration and development activities

	Year Ended		Year Ended
	December 31,		December 31,
	2015		2014
Acquisition of properties	$	85,895	$	1,017,698
Exploration costs		-		-
Development costs		165,926		6,078,167
Net capitalized costs	$	251,821	$	7,095,865

Estimated quantities of proved reserves

Our ownership interests in estimated quantities of proved oil and gas reserves and changes in net proved reserves all of which are located in the United States are summarized below.  Proved reserves are estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those that are expected to be recovered through existing wells with existing equipment and operating methods. Reserves are stated in barrels of oil equivalent. Geological and engineering estimates by Cobb & Associates, Inc. of proved oil and gas reserves at one point in time are highly interpretive, inherently imprecise and subject to ongoing revisions that may be substantial in amount. Although every reasonable effort is made to ensure that the reserve estimates are accurate, by their nature reserve estimates are generally less precise than other estimates presented in connection with financial statement disclosures.

	2015								2014
			Natural Gas				Oil				Natural Gas				Oil
	Crude Oil		Liquids		Natural Gas		Equivalents		Crude Oil		Liquids		Natural Gas		Equivalents
	BBL's		BBLs		MCF's		BOE's		BBL's		BBLs		MCF's		BOE's
Proved reserves
Beginning		2,946,400		90,900		8,177,280		4,400,180		4,444,500		40,600		7,917,000		5,804,600
Revisions of previous estimates		(1,151,384)		(35,925)		(1,723,732)		(1,474,598)		(1,352,091)		56,919		578,506		(1,198,754)
Purchases of minerals in place										2,234						2,234
Extensions and discoveries										2,226						2,226
Sales of minerals in place		(217,032)						(217,032)								-
Production		(96,244)		(6,045)		(188,408)		(133,690)		(150,469)		(6,619)		(318,226)		(210,126)
Ending		1,481,740		48,930		6,265,140		2,574,860		2,946,400		90,900		8,177,280		4,400,180

Proved developed reserves at December 31, 2015 consisted of 74% oil and 26% natural gas and totaled 1,851.9 MBOEs. Proved developed reserves for December 31, 2014 consisted of 77% oil and 23% natural gas and totaled 3,048.3 MBOEs. Proved undeveloped reserves for December 31, 2015 were 723.0 MBOEs. Proved undeveloped reserves at December 31, 2014 were 1,351.9 MBOEs.

For the year ended December 31, 2015 proved reserves decreased 1,825.3 MBOEs of which production accounted for 133.7 MBOEs or 7.3% of the decrease. The remaining decrease of 1,691.6 MBOEs, was due primarily to decreases in commodity prices. Crude oil prices decreased $40.00 or 46.1% and natural gas prices declined 42.2% or $1.37. Diminished commodity pricing triggered negative revisions of 586.6 MBOEs of crude oil classified as proved developed producing, negative revisions of 42.9 MBOEs of crude oil classified as proved developed non-producing and negative revisions of 522.1 of MBOEs of crude oil classified as proved undeveloped reserves. Natural gas liquids decreased pricing resulted in decreases of 65.6 MBOEs to the proved developed producing category. Reduced natural gas prices also reduced amounts classified as proved developed producing by 1,347.9 MMCF’s as well as natural gas reserves classified as proved undeveloped by 637.8 MCF. These decreases were partially offset by increases to natural gas liquid reserves classified as proved developed non-producing of 29.7 MBOE and 262.4 MMCF of natural gas reserves classified as proved developed non-producing. In 2015 there were no material transfers from the proved undeveloped category of reserves to the proved developed category.

For the year ended December 31, 2014 proved reserves decreased 1,404.4 MBOEs, of which production accounted for 210.1 MBOEs or 14.9% of the decrease. The remaining decrease of 1,194.3 MBOEs or 20.5%, was due primarily to a revision of decline curves related to our Cherokee project in Eastern Kansas. Our third party independent engineering firm, MHA Petroleum Consultants revised their decline curve forecast methodology in response to 2014 production performance that fell short of forecast using the original methodology, resulting in a negative revision of a 686,091 BOEs of crude oil classified as proved developed producing, a negative revision of 38,100 BOEs of crude oil classified as proved developed non-producing and a negative revision of 627,893 of BOEs of crude oil classified as proved undeveloped reserves for a total of 1,352,091 BOEs. These decreases were partially offset by increases to estimated proved developed reserves of approximately 240,000 BOE of natural gas and 56,919 barrels of natural gas liquids that resulted from the transfer of an Adena gas-cap well from proved non-producing to the proved developed producing category. Additionally, proved developed non-producing natural gas reserves decreased approximately 143,000 BOE again due to the transferring of a gas-cap well from proved non-producing to the proved developed producing category.

Proved undeveloped reserves decreased 627,893 BOEs in 2014. The decrease was due almost entirely to the crude oil revisions, which resulted from revisions to decline curves related to our Cherokee project in Eastern Kansas. Our third party independent engineering firm, MHA Petroleum Consultants revised their decline curve forecast methodology in response to 2014 production performance that fell short of forecast using the original methodology. No material amount of reserves were the result to a transfer from proved undeveloped reserves to the proved developed category.

In 2015 the Company invested approximately $250,000 in its oil and gas properties. These reduced expenditures were primarily in response to extremely low commodity prices. The Company has $7.4 million of current asset on hand, approximately $3.7 million of unrealized hedge gains and important infrastructure in Colorado completed which will facilitate the exploitation and development of proved undeveloped reserves over the next five years. At year end the Company’s review of proved undeveloped reserves revealed no instances of reserves that have not been developed within five years of their initial recording as a proved undeveloped reserve. In addition it believes it has the financial wherewithal to develop all it’s proved undeveloped reserves within the five year time frames required; utilizing its balance sheet, it borrowed $.5 million from its bank in January 2015 and has the ability to joint venture any of its assets.

Standardized measure of discounted future net cash flows

The standardized measure of discounted future net cash flows from our proved reserves for the periods presented in the financial statements is summarized below.

	Year Ended		Year Ended
	December 31,		December 31,
	2015		2014
Future production revenue	$	74,087,130	$	282,557,900
Future production costs		(46,015,320)		(101,119,500)
Future development costs		(5,901,660)		(13,736,500)
Future cash flows before income tax		22,170,150		167,701,900
Future income taxes		-		(4,211,005)
Future net cash flows		22,170,150		163,490,895
10% annual discount for estimating of future cash flows		(13,400,180)		(100,787,044)
Standardized measure of discounted net cash flows	$	8,769,970	$	62,703,851

Changes in standardized measure of discounted future net cash flows

The following is a summary of a standardized measure of discounted net future cash flows related to the Company’s proved oil and gas reserves. The information presented is based on a calculation of estimated proved reserves using discounted cash flows based on the 12-month average price for oil and gas calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month prior period. The additions to estimated proved reserves from new discoveries and extensions could vary significantly from year to year. Additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant.

	Year Ended		Year Ended
	December 31,		December 31,
	2015		2014
Balance beginning of year	$	62,703,851	$	81,447,656
Sales, net of production costs		(491,055)		(7,531,119)
Net change in pricing and production costs		(51,184,718)		(19,087,068)
Net change in future estimated development costs		7,834,840		6,281,385
Purchase of minerals in place		-		190,502
Extensions and discoveries		-		35,203
Sale of minerals in place		(2,746,550)		-
Revisions		(8,448,569)		(25,498,141)
Accretion of discount		16,770,190		27,098,964
Change in income tax		(15,668,019)		(233,531)
Balance end of year	$	8,769,970	$	62,703,851

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Summary of Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States. Our operations are considered to fall within a single industry segment, which are the acquisition, development, exploitation and production of crude oil and natural gas properties in the United States.  Our consolidated financial statements include our wholly owned subsidiaries.

All significant intercompany balances and transactions have been eliminated upon consolidation.  Certain reclassifications have been made to the prior year financial statements to conform to the current year presentation. 

Nature of Business

Nature of Business

We are an independent energy company engaged in the business of producing and selling crude oil and natural gas. The crude oil and natural gas is obtained primarily by the acquisition and subsequent exploration and development of mineral leases.  Development and exploration may include drilling new exploratory or development wells on these leases. These operations are conducted primarily in Kansas, Colorado, Nebraska and Texas.

Use of Estimates in the Preparation of Financial Statements

Use of Estimates in the Preparation of Financial Statements

The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.  Significant estimates included in the consolidated financial statements are: (1) oil and gas revenues and reserves; (2) depreciation, depletion and amortization; (3) valuation allowances associated with income taxes (4) accrued assets and liabilities; (5) stock-based compensation; (6) asset retirement obligations, (7) valuation of derivative instruments and (8) impairment of oil and gas assets.  Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates.  Actual results could differ from those estimates.

Trade Accounts Receivable

Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear any interest.  We regularly review receivables to insure that the amounts will be collected and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method.  Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.

Inventory

Inventory

Inventories are comprised of crude oil held in storage and materials and supplies used in field operations. Crude oil inventories are valued at lower of cost or market, on a first-in, first out basis. Material and supplies are valued at lower of cost or market, based upon specific cost or by using a weighted average cost.

Share-Based Payments

Share-Based Payments

The value we assign to the options and warrants that we issue is based on the fair market value as calculated by the Black-Scholes pricing model. To perform a calculation of the value of our options and warrants, we determine an estimate of the volatility of our stock.  We need to estimate volatility because there has not been enough trading of our stock to determine an appropriate measure of volatility. We believe our estimate of volatility is reasonable, and we review the assumptions used to determine this whenever we issue new equity instruments.

Income Taxes

Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before the tax returns or when income items are recognized in the tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Deferred tax liabilities arise when income items are recognized in the financial statements before the tax returns or when expenses are recognized in the tax return prior to the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted.

We routinely assess the reliability of our deferred tax assets.  If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset is reduced by a valuation allowance.  In addition we routinely assess uncertain tax positions, and accrue for tax positions that are not more-likely-than-not to be sustained upon examination by taxing authorities.

Uncertain Tax Positions

Uncertain Tax Positions

We follow guidance in Topic 740 of the Codification for its accounting for uncertain tax positions. Topic 740 prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, we determine whether it is more-likely-than-not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based solely on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement.

We have no liability for unrecognized tax benefits recorded as of December 31, 2015 and 2014. Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the consolidated statement of operations or consolidated balance sheet as of December 31, 2015. In addition, we do not believe that there are any positions for which it is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase or decrease within the next twelve months. We recognize related interest and penalties as a component of income tax expense.

Tax years open for audit by federal tax authorities as of December 31, 2015 are the years ended December 31, 2012, 2013 and 2014. Tax years ending prior to 2012 are open for audit to the extent that net operating losses generated in those years are being carried forward or utilized in an open year.

Fair Value Measurements

Fair Value Measurements

Accounting guidance establishes a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and creates a fair value hierarchy that prioritizes the information used to develop those assumptions.  Additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy.  We incorporate a credit risk assumption into the measurement of certain assets and liabilities.

Cash and Cash Equivalents

Cash and Cash Equivalents

We consider all highly liquid investment instruments purchased with original maturities of three months or less to be cash equivalents for purposes of the consolidated statements of cash flows and other statements. We maintain cash on deposit, which, can exceeds federally insured limits. We have not experienced any losses on such accounts and believe we are not exposed to any significant credit risk on cash and equivalents.

Revenue Recognition

Revenue Recognition

Oil and gas revenues are recognized net of royalties when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collection of the revenue is probable. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met.

Fixed Assets

Fixed Assets

Property and equipment are recorded at cost. At December 31, 2015, Fixed Assets consisted of vehicles of $354,886, furniture and equipment of $552,288, building and leasehold improvements of $23,069 and gathering and compression systems of $2,722,839 as well as accumulated depreciation of vehicles $328,659, accumulated depreciation of furniture and fixtures of $478,578, accumulated depreciation of building and leasehold improvements of $13,342 and accumulated depreciation of gathering and compression systems of $837,494.

At December 31, 2014, Fixed Assets consisted of vehicles $967,483, furniture and equipment of $608,061, building and leasehold improvements of $23,069 and gathering and compression systems of $2,751,697, as well as accumulated depreciation of vehicles of $697,042, accumulated depreciation of furniture and fixtures of $494,333, accumulated depreciation of building and leasehold improvements of $9,386 and accumulated depreciation of gathering and compression systems of $744,846. 

Depreciation is determined by the use of the straight-line method of accounting using the estimated lives of the assets (3-15 years).  Expenditures for maintenance and repairs are charged to expense.

Debt issue costs

Debt issue costs

Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt utilizing the straight-line method of amortization over the estimated life of the debt.

Oil & Gas Properties and Long-Lived Assets

Oil & Gas Properties and Long-Lived Assets

We follow the full cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities.

Proved properties are amortized using the units of production method (UOP). Currently we only have operations in the United States of America. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the cost of these reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (DD&A), estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs, less related salvage value. 

The cost of unproved properties are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed into service. Geological and geophysical costs not associated with specific properties are recorded as proved property immediately. Unproved properties are reviewed for impairment quarterly.

Impairment of long-lived assets is recorded when indications of impairment are present. Impairment is indicated when the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying value.  The carrying value of the assets is then reduced to their estimated fair value that is measured based on an estimate of future discounted cash flows.

Under the full-cost-method of accounting, the net book value of oil and gas properties, less deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is (a) the present value of future net revenues computed by applying current prices of oil & gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil & gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of 10 percent and assuming continuation of existing economic conditions plus (b) the cost of properties not being amortized plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized less (d) income tax effects related to differences between book and tax basis of properties. Future cash outflows associated with settling accrued retirement obligations are excluded from the calculation. Estimated future cash flows are calculated using end-of-period costs and an un-weighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months held flat for the life of the production, except where prices are defined by contractual arrangements.

Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the statement of operations. The ceiling calculation is performed quarterly. For the year ended December 31, 2015 impairments of $16,401,376, $11,421,613, $9,720,983 and $11,386,115 were record in the first, second, third and fourth quarters respectively. For the year ended December 31, 2014 there were no impairments resulting from the quarterly ceiling tests.

Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25%) of our reserve quantities are sold, in which case a gain or loss is recognized in income. In 2015 the Company sold its Cherokee project assets located in Eastern Kansas for net proceeds of $2,867,305. At the time of the sale the reserve quantities made up approximately 6.7% of total reserve quantities. Accordingly, the net proceeds reduced the carrying value of our oil and gas properties.

Asset Retirement Obligations

Asset Retirement Obligations

The asset retirement obligation relates to the plug and abandonment costs when our wells are no longer useful. We determine the value of the liability by obtaining quotes for this service and estimate the increase we will face in the future. We then discount the future value based on an intrinsic interest rate that is appropriate for us. If costs rise more than what we have expected there could be additional charges in the future, however, we monitor the costs of the abandoned wells and we will adjust this liability if necessary.

Major Purchasers

Major Purchasers

For the years ended December 31, 2015, and 2014 we sold our produced crude oil to ARM Energy Management, LLC, Coffeyville Resources Inc., Plains Marketing, L.P., MV Purchasing and Sunoco Logistics Inc. on a month-to-month basis and we sold our produced natural gas to United Energy Trading and Western Operating Company.

Marketable Securities Available for Sale

Marketable Securities Available for Sale

The Company classifies its marketable equity securities as available-for-sale and they are carried at fair market value, with the unrealized gains and losses included in accumulated other comprehensive income and reported in stockholders’ equity. The difference between historical cost and market totaled $552,589 for the year ended December 31, 2014. For the year ended December 31, 2015 the Company received a dividend of $1,360,172. This receipt of cash was first applied to the other comprehensive loss reported in stockholders’ equity and then to the carrying value of the security reported in current assets. This resulted in a new carrying value of $210,990 for this security. The Company expects future distributions and estimates that the sum of future distributions to be in excess of the remaining book value.

Net Income Per Common Share

Net Income Per Common Share

Basic net income per share is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect, in periods in which they have a dilutive effect, the impact of common shares issuable upon exercise of stock options and warrants and conversion of convertible debt that are not deemed to be anti-dilutive. The dilutive effect of the outstanding stock options and warrants is computed using the treasury stock method.

For the year ended December 31, 2015, diluted net loss per share did not include the effect of 298,664 shares of common stock issuable upon the exercise of outstanding stock options as their effect would be anti-dilutive.

For the year ended December 31, 2014, diluted net income per share did not include the effect of  231,332 shares of common stock issuable upon the exercise of outstanding stock options as their exercise price was above market value.

Reclassifications

Reclassifications

Certain reclassifications have been made to prior periods to conform to current presentations.

Recent Accounting Pronouncements Applicable to the Company

Recent Accounting Pronouncements Applicable to the Company

The Company does not believe there are any recently issued, but not yet effective; accounting standards that would have a significant impact on the Company’s financial position or results of operations.

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Equity Transactions (Tables)

12 Months Ended

Dec. 31, 2015

Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract]

Summary of Stock Options

A summary of stock options is as follows:

			Weighted Ave.				Weighted Ave.
	Options		Exercise Price		Warrants		Exercise Price
Outstanding January 1, 2014		231,133	$	9.36			$
Granted		2,367		10.50
Cancelled		(2,168)		(10.50)
Exercised		-		-		-		-
Outstanding December 31, 2014		231,332	$	9.33		-	$	-
Granted		67,332				1,904,286		2.75
Cancelled		(10,333)		(10.50)		-		-
Exercised						-		-
Outstanding December 31, 2015		288,331	$	10.17		1,904,286	$	2.75

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Asset Retirement Obligation (Tables)

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligation [Abstract]

Changes in Asset Retirement Obligations

The following shows the changes in asset retirement obligations:

Asset retirement obligations, January 1, 2014	$	2,687,801
Liabilities incurred during the period		65,385
Liabilities settled during the year		(102,929)
Accretion		255,836
Asset retirement obligations, December 31, 2014	$	2,906,093
Release of liabilities associated with the sale of oil properties		(70,083)
Liabilities settled during the year		(2,244)
Accretion		257,712
Asset retirement obligations, December 31, 2015	$	3,091,478

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Reconciliation of the Provision For Income Taxes to the Statutory Federal Rate

The following table sets forth a reconciliation of the provision for income taxes to the statutory federal rate:

	Year Ended December 31,
	2015			2014
Statutory tax rate		35.00	%		35.00	%
State tax rate, net of federal tax		1.90	%		1.37	%
Other permanent items		0.00	%		0.05	%
Change in valuation allowance		(36.90)	%		(36.42)	%
Effective tax rate		0.00	%		0.00	%

Significant Components of the Deferred Tax Assets and Liabilities

Significant components of the deferred tax assets and liabilities are as follows:

	Year Ended December 31,
	2015		2014
Non-current deferred tax asset:
Oil and gas costs and long-lived assets	$	14,513,571	$	(1,038,092)
Derivative instruments		934,340		(1,717,301)
Net operating loss carry-forward		29,532,954		25,915,146
Valuation allowance		(44,980,865)		(23,159,753)
Net deferred tax asset (liability)	$	-	$	-

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2015

Fair Value Measurements [Abstract]

Variable to Fixed Price Commodity Swaps Derivative Instruments

Our derivative instruments consist of fixed price commodity swaps.  

	Fair Value Measurement
	Level 1		Level 2		Level 3
Crude oil contracts	$	-	$	2,531,401	$	-
Marketable securities	$	-	$	-	$	210,990

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Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2015

Derivative Instruments [Abstract]

Derivative Contracts

The following derivative contracts were in place at December 31, 2015:

	Term	Monthly Volumes  (1)			Price/Bbl		Fair Value
Deferred premium put	1/16-6/16		9,000	Bbls	$	85.00	$	2,170,912
Deferred premium put	7/16-12/16		5,000	Bbls	$	60.00		360,489
							$	2,531,401

⁽¹⁾      Monthly volumes are the weighted average throughout the period.

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Other Income (Tables)

12 Months Ended

Dec. 31, 2015

Other Income and Expenses [Abstract]

Interest and Other Income

The following table depicts the components of other income for the years ended December 31, 2015 and December 31, 2014:

	Year ended		Year ended
	December 31,		December 31,
	2015		2014
Realized gain (loss) clearing of derivative contracts	$	4,662,012	$	(914,694)
Loss on sale of fixed assets		(13,661)		(9,738)
Miscellaneous income		27,105		4,004
Interest income		398		901
Other Income	$	4,675,854	$	(919,527)

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Supplemental Oil and Gas Reserve Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2015

Supplemental Oil Reserve Information [Abstract]

Results of operations from oil and gas producing activities

Income tax expense was determined by applying the statutory rates to pretax operating results.

	Year Ended		Year Ended
	December 31,		December 31,
	2015		2014
Production revenues	$	4,878,722	$	14,293,368
Production costs		(4,501,940)		(6,762,248)
Depletion and depreciation		(1,108,039)		(3,259,442)
Income tax		255,940		(1,495,087)
Results of operations for producing activities	$	(475,317)	$	2,776,591

Summarizes the Company’s Capitalized Costs

The following table summarizes the Company’s capitalized costs of oil and gas properties.

	Year Ended		Year Ended
	December 31,		December 31,
	2015		2014
Properties subject to amortization	$	26,642,325	$	78,090,619
Accumulated depletion		(14,935,386)		(13,827,347)
Net capitalized costs	$	11,706,939	$	64,263,272

Cost incurred in property acquisition, exploration and development activities

Cost incurred in property acquisition, exploration and development activities

	Year Ended		Year Ended
	December 31,		December 31,
	2015		2014
Acquisition of properties	$	85,895	$	1,017,698
Exploration costs		-		-
Development costs		165,926		6,078,167
Net capitalized costs	$	251,821	$	7,095,865

Estimated quantities of proved reserves

Although every reasonable effort is made to ensure that the reserve estimates are accurate, by their nature reserve estimates are generally less precise than other estimates presented in connection with financial statement disclosures.

	2015								2014
			Natural Gas				Oil				Natural Gas				Oil
	Crude Oil		Liquids		Natural Gas		Equivalents		Crude Oil		Liquids		Natural Gas		Equivalents
	BBL's		BBLs		MCF's		BOE's		BBL's		BBLs		MCF's		BOE's
Proved reserves
Beginning		2,946,400		90,900		8,177,280		4,400,180		4,444,500		40,600		7,917,000		5,804,600
Revisions of previous estimates		(1,151,384)		(35,925)		(1,723,732)		(1,474,598)		(1,352,091)		56,919		578,506		(1,198,754)
Purchases of minerals in place										2,234						2,234
Extensions and discoveries										2,226						2,226
Sales of minerals in place		(217,032)						(217,032)								-
Production		(96,244)		(6,045)		(188,408)		(133,690)		(150,469)		(6,619)		(318,226)		(210,126)
Ending		1,481,740		48,930		6,265,140		2,574,860		2,946,400		90,900		8,177,280		4,400,180

Standardized measure of discounted future net cash flows

The standardized measure of discounted future net cash flows from our proved reserves for the periods presented in the financial statements is summarized below.

	Year Ended		Year Ended
	December 31,		December 31,
	2015		2014
Future production revenue	$	74,087,130	$	282,557,900
Future production costs		(46,015,320)		(101,119,500)
Future development costs		(5,901,660)		(13,736,500)
Future cash flows before income tax		22,170,150		167,701,900
Future income taxes		-		(4,211,005)
Future net cash flows		22,170,150		163,490,895
10% annual discount for estimating of future cash flows		(13,400,180)		(100,787,044)
Standardized measure of discounted net cash flows	$	8,769,970	$	62,703,851

Changes in standardized measure of discounted future net cash flows

Additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant.

	Year Ended		Year Ended
	December 31,		December 31,
	2015		2014
Balance beginning of year	$	62,703,851	$	81,447,656
Sales, net of production costs		(491,055)		(7,531,119)
Net change in pricing and production costs		(51,184,718)		(19,087,068)
Net change in future estimated development costs		7,834,840		6,281,385
Purchase of minerals in place		-		190,502
Extensions and discoveries		-		35,203
Sale of minerals in place		(2,746,550)		-
Revisions		(8,448,569)		(25,498,141)
Accretion of discount		16,770,190		27,098,964
Change in income tax		(15,668,019)		(233,531)
Balance end of year	$	8,769,970	$	62,703,851

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Summary of Accounting Policies - Additional Information (Detail) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Summary Of Accounting Policies [Line Items]
Available-for-sale Securities, Gross Unrealized Gain (Loss)										$ 552,589
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount									298,664	231,332
Property, Plant and Equipment, Gross, Total	$ 1,995,010				$ 2,404,703				$ 1,995,010	$ 2,404,703
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	1,658,073				1,945,607				1,658,073	1,945,607
Asset Impairment Charges, Total	11,386,115	$ 9,720,983	$ 11,421,613	$ 16,401,376	0	$ 0	$ 0	$ 0
Proceeds from Sale of Productive Assets									33,142	1,250
Proceeds from Dividends Received									1,360,172	0
Cash and Cash Equivalents, at Carrying Value, Total	3,101,682				805,524				3,101,682	805,524
Available-for-sale Securities [Member]
Summary Of Accounting Policies [Line Items]
Proceeds from Dividends Received									1,360,172
Cash and Cash Equivalents, at Carrying Value, Total	210,990								210,990
Vehicles [Member]
Summary Of Accounting Policies [Line Items]
Property, Plant and Equipment, Gross, Total	354,886				967,483				354,886	967,483
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	328,659				697,042				328,659	697,042
Gas Gathering and Processing Equipment [Member]
Summary Of Accounting Policies [Line Items]
Property, Plant and Equipment, Gross, Total	2,722,839				2,751,697				2,722,839	2,751,697
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	837,494				744,846				837,494	744,846
Furniture And Equipment [Member]
Summary Of Accounting Policies [Line Items]
Property, Plant and Equipment, Gross, Total	552,288				608,061				552,288	608,061
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	478,578				494,333				478,578	494,333
Building And leasehold Imrovement [Member]
Summary Of Accounting Policies [Line Items]
Property, Plant and Equipment, Gross, Total	23,069				23,069				23,069	23,069
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	$ 13,342				$ 9,386				$ 13,342	$ 9,386
Cherokee Project Assets [Member]
Summary Of Accounting Policies [Line Items]
Percentage Of Sale Reserve Quantity to Total Reserve Quantity									6.70%
Proceeds from Sale of Productive Assets									$ 2,867,305
Maximum [Member]
Summary Of Accounting Policies [Line Items]
Property, Plant and Equipment, Useful Life									15 years
Minimum [Member]
Summary Of Accounting Policies [Line Items]
Property, Plant and Equipment, Useful Life									3 years

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Equity Transactions (Summary of stock options) (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Options
Options Outstanding, Beginning Balance	231,332	231,133
Options Granted	67,332	2,367
Options Cancelled	(10,333)	(2,168)
Options Exercised		0
Options Outstanding, Ending Balance	288,331	231,332
Weighted Avg. Exercise Price
Weighted Avg. Exercise Price Outstanding, Beginning Balance	$ 9.33	$ 9.36
Weighted Avg. Exercise Price Granted		10.50
Weighted Avg. Exercise Price Cancelled	(10.50)	(10.50)
Weighted Avg. Exercise Price Exercised		0
Weighted Avg. Exercise Price Outstanding, Ending balance	$ 10.17	$ 9.33
Warrants
Warrants Granted	1,904,286
Warrants Cancelled	0
Warrants Exercised	0	0
Warrants Outstanding	1,904,286	0
Weighted Avg. Exercise Price
Weighted Avg. Exercise Price Granted	$ 2.75
Weighted Avg. Exercise Price Cancelled	0
Weighted Avg. Exercise Price Exercised	0	$ 0
Weighted Avg. Exercise Price Outstanding, Ending balance	$ 2.75	$ 0

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Equity Transactions - Additional Information (Detail) - USD ($)			1 Months Ended				12 Months Ended
	May. 13, 2015	Mar. 13, 2015	Sep. 30, 2014	Jun. 20, 2014	Jun. 16, 2014	Dec. 31, 2010	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Oct. 14, 2008	Sep. 30, 2007	Aug. 01, 2002
Stock Issued During Period, Shares, Issued for Services								9,625
Stockholders' Equity, Reverse Stock Split								May 30, 2014, the Company affected a 1-for-15 reverse stock split, by which each share of EnerJex common stock was reclassified, and changed into 1/15th of a fully paid and non-assessable share of common stock. In lieu of fractions of a share, the Company paid to holders of fractions of a share cash equal to $11.25 per share
Stock Issued During Period, Value, New Issues							$ 24,000	$ 234,654
Share-Based Compensation Arrangement By Share-Based Payment Award, Options, Outstanding, Number							288,331	231,332	231,133
Share Based Compensation Arrangements By Share Based Payment Award Options Amount Recognized As Expenses								$ 76,938
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number							56,702
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested, Number of Shares							231,629
Treasury Stock, Number of Shares Held			383,333
Adjustments to Additional Paid in Capital, Other			$ 2,551,000
Preferred Stock, Conversion Basis					the holders of our existing Series A preferred stock exchanged each outstanding share of such existing Series A preferred stock for (i) a number of shares of our common stock into which such Series A preferred stock was then convertible immediately prior to the exchange (318,630 shares in the aggregate), and (ii) 112,658 shares of Series A preferred stock which was equal to the quotient determined by dividing (x) that portion of the holders original Series A preferred stock purchase price that had not yet been paid in dividends, by (y) $23.75.
Preferred Stock, Liquidation Preference Per Share							$ 1,000
Convertible Preferred Stock, Shares Issued upon Conversion							571
Class of Warrant or Right, Exercise Price of Warrants or Rights							$ 2.75
Stock Issued During Period Shares Owed For Services								17,500
Stock Issued During Period, Value, Issued for Services								$ 175,356
Minimum [Member]
Share Price							0.30
Maximum [Member]
Share Price							$ 2.00
Stock Option Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant												26,666
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized											66,666
Stock Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized										83,333
2013 Stock Incentive Plan [Member]
Common Stock, Capital Shares Reserved for Future Issuance							333,300
IPO [Member]
Stock Issued During Period, Shares, New Issues				639,157
Sale of Stock, Price Per Share				$ 23.75
Stock Issued During Period, Value, New Issues				$ 15,179,938
Proceeds from Issuance of Preferred Stock and Preference Stock				13,347,564
Over-Allotment Option [Member]
Payments of Stock Issuance Costs				$ 1,832,374
Common Stock [Member]
Stock Issued During Period, Shares, New Issues							17,500	17,332
Stock Issued During Period, Value, New Issues							$ 18	$ 17
Employee Stock Option [Member]
Share Price								$ 7.95
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Exercise Price							$ 9.85	$ 10.50
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term							3 years	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate								72.00%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate							0.00%	0.00%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate							1.41%	0.47%
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross							67,332	2,367
Stock Issued During Period, Value, Share-based Compensation, Gross							$ 295,932	$ 12,178
Payments of Stock Issuance Costs							$ 420,103	$ 374,433
Employee Stock Option [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate							70.00%
Employee Stock Option [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate							72.00%
Registered Shares [Member] | Common Stock [Member]
Stock Issued During Period, Shares, New Issues		763,547
Shares Issuable Upon Conversion Of Preferred stock		709,812
Unregistered Shares [Member]
Restricted Ownership Percentage		9.99%
Class of Warrant or Right, Number of Securities Called by Warrants or Rights		1,771,428
Unregistered Shares [Member] | Common Stock [Member]
Shares Issuable Upon Conversion Of Preferred stock		298,069
Convertible Preferred Stock [Member] | Unregistered Shares [Member]
Stock Issued During Period, Shares, New Issues		521.62076
Series B Convertable Preferred Stock [Member] | Registered Shares [Member]
Stock Issued During Period, Shares, New Issues		1,242.17099
Series A Preferred Stock [Member]
Stock Issued During Period, Shares, New Issues							3,000
Stock Issued During Period, Value, New Issues							$ 3
Preferred Stock, Dividend Rate, Percentage								10.00%
Series A Preferred Stock [Member] | Senior Credit Facility [Member]
Stock Issued During Period, Shares, New Issues	183,433
Proceeds from Issuance of Preferred Stock and Preference Stock	$ 2,300,000
Preferred Stock, Dividend Rate, Percentage	10.00%
Shares Issued, Price Per Share	$ 12.50
Employees [Member]
Stock Issued During Period, Shares, Issued for Services								7,707
Stock Issued During Period, Value, Issued for Services								$ 59,298
Thirteen Employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term									3 years
Officer [Member]
Share-Based Compensation Arrangement By Share-Based Payment Award, Options, Outstanding, Number						60,000
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Exercise Price						$ 6.00
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term						5 years
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested in Period, Fair Value						$ 307,751
Share Based Compensation Arrangements By Share Based Payment Award Options Amount Recognized As Expenses							$ 0	$ 76,938

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Asset Retirement Obligation (Changes in Asset Retirement Obligations) (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Reconciliation Of Changes In Asset Retirement Obligations [Line Items]
Asset retirement obligations, Begining	$ 2,906,093	$ 2,687,801
Liabilities incurred during the period		65,385
Release of liabilities associated with the sale of oil properties	(70,083)
Liabilities settled during the year	(2,244)	(102,929)
Accretion	257,712	255,836
Asset retirement obligations, Ending	$ 3,091,478	$ 2,906,093

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Long-Term Debt - Additional Information (Detail) - USD ($)		1 Months Ended		12 Months Ended
	Aug. 12, 2015	May. 22, 2014	Sep. 30, 2013	Dec. 31, 2015	May. 02, 2015	Dec. 31, 2014	Aug. 15, 2014	Apr. 16, 2013	Nov. 02, 2012	Aug. 31, 2012	Dec. 15, 2011
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity				$ 18,600,000				$ 19,500,000
Line of credit facility, current borrowing capacity				$ 18,600,000
Proceeds from potential future securities offering unencumbered by Banks’ Liens					$ 1,000,000
Line of Credit Facility, Expiration Date				Oct. 03, 2018
First Amendment | Rantoul Partners
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity											$ 50,000,000
Second Amendment
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity										$ 7,000,000
Second Amendment | Minimum
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage										3.75%
Third Amendment
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity									$ 12,150,000
Fifth Amendment
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity			$ 100,000,000
Line of credit facility, current borrowing capacity			$ 38,000,000
Seventh Amendment | Series A Cumulative Redeemable Perpetual Preferred Stock
Debt Instrument [Line Items]
Preferred Stock, Dividend Rate, Percentage		10.00%
Preferred Stock Shares Issued		850,000
Eight Amendment | Minimum
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity							$ 38,000,000
Eight Amendment | Maximum
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity							$ 40,000,000
Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				4.30%		3.30%
Tenth Amendment [Member]
Debt Instrument [Line Items]
Proceed From Sale To Outstanding Loan Balances	$ 1,300,000
Proceeds from Sale of Oil and Gas Property and Equipment	$ 1,500,000
Line of Credit | Federal Funds Rate
Debt Instrument [Line Items]
Debt instrument interest rate, margin				0.50%
Line of Credit | Base Rate | Minimum
Debt Instrument [Line Items]
Debt instrument interest rate, margin				0.00%
Line of Credit | Base Rate | Maximum
Debt Instrument [Line Items]
Debt instrument interest rate, margin				0.75%
Line of Credit | Floating Rate | Minimum
Debt Instrument [Line Items]
Debt instrument interest rate, margin				2.25%
Line of Credit | Floating Rate | Maximum
Debt Instrument [Line Items]
Debt instrument interest rate, margin				3.00%
Line of Credit | Fifth Amendment | Federal Funds Rate
Debt Instrument [Line Items]
Debt instrument interest rate, margin			3.30%

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Commitments and Contingencies - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Commitments and Contingencies Disclosure [Line Items]
Operating Leases, Rent Expense	$ 149,000	$ 159,000
Operating Leases, Future Minimum Payments Due, Next Twelve Months	147,000
Operating Leases, Future Minimum Payments, Due in Two Years	145,000
Operating Leases, Future Minimum Payments, Due in Three Years	91,000
Operating Leases, Future Minimum Payments, Due in Four Years	77,000
Texas Railroad Commission [Member]
Commitments and Contingencies Disclosure [Line Items]
Letters of Credit Outstanding, Amount	$ 50,000

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Income Taxes (Reconciliation of The Provision For Income Taxes) (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Statutory tax rate	35.00%	35.00%
State tax rate, net of federal tax	1.90%	1.37%
Other permanent items	0.00%	0.05%
Change in valuation allowance	(36.90%)	(36.42%)
Effective tax rate	0.00%	0.00%

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Income Taxes (Components of The Deferred Tax Assets and Liabilities) (Detail) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Non-current deferred tax asset:
Oil and gas costs and long-lived assets	$ 14,513,571	$ (1,038,092)
Derivative instruments	934,340	(1,717,301)
Net operating loss carry-forward	29,532,954	25,915,146
Valuation allowance	(44,980,865)	(23,159,753)
Net deferred tax asset (liability)	$ 0	$ 0

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Income Taxes - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Operating Loss Carryforwards	$ 81.0
Operating Loss Carryforward, Expiration Date	2021-2036
Limitations On Use Operating Loss Carryforwards	$ 40.9

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Fair Value Measurements (Variable to Fixed Price Commodity Swaps Derivative Instruments) (Detail)	Dec. 31, 2015 USD ($)
Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Crude oil contracts	$ 0
Marketable Securities	0
Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Crude oil contracts	2,531,401
Marketable Securities	0
Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Crude oil contracts	0
Marketable Securities	$ 210,990

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Derivative Instruments (Derivative Contracts) (Detail)	12 Months Ended
	Dec. 31, 2015 USD ($) $ / Barrel-bbl bbl
Derivative [Line Items]
Fair Value	$ 2,531,401
Deferred premium put | Derivative Instrument 1
Derivative [Line Items]
Monthly Volumes Bbls | bbl	9,000	[1]
Price/Bbl | $ / Barrel-bbl	85.00
Fair Value	$ 2,170,912
Deferred premium put | Derivative Instrument 2
Derivative [Line Items]
Monthly Volumes Bbls | bbl	5,000	[1]
Price/Bbl | $ / Barrel-bbl	60.00
Fair Value	$ 360,489
Deferred premium put | Minimum | Derivative Instrument 1
Derivative [Line Items]
Term	2016-01
Deferred premium put | Minimum | Derivative Instrument 2
Derivative [Line Items]
Term	2016-07
Deferred premium put | Maximum | Derivative Instrument 1
Derivative [Line Items]
Term	2016-06
Deferred premium put | Maximum | Derivative Instrument 2
Derivative [Line Items]
Term	2016-12

[1] Monthly volumes are the weighted average throughout the period.

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Derivative Instruments - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Loss on Derivative Instruments, Pretax	$ 2,194,679	$ 6,073,960

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Impairment of Oil and Gas Properties - Additional Information (Detail)	3 Months Ended	6 Months Ended	9 Months Ended	12 Months Ended
	Mar. 31, 2015 USD ($) bbl	Jun. 30, 2015 USD ($) bbl	Sep. 30, 2015 USD ($) bbl	Dec. 31, 2015 USD ($) bbl	Dec. 31, 2014 USD ($)
Oil Price Per Barrel	78.82	71.68	59.21	52.73
Natural Gas Price Per MMBtu	3.74	3.39	3.06	2.76
Impairment of Oil and Gas Properties | $	$ 16,400,000	$ 11,400,000	$ 9,700,000	$ 48,930,087	$ 0

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Other Income (Components of Other Income) (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Interest And Other Income [Line Items]
Realized gain (loss) clearing of derivative contracts	$ 4,662,012	$ (914,694)
Loss on sale of fixed assets	(13,661)	(9,738)
Miscellaneous income	27,105	4,004
Interest income	398	901
Other Income	$ 4,675,854	$ (919,527)

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Supplemental Oil and Gas Reserve Information (Unaudited) (Results of Operations From Oil and gas Producing Activities) (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Production revenues	$ 4,878,722	$ 14,293,368
Production costs	(4,501,940)	(6,762,248)
Depletion and depreciation	(1,108,039)	(3,259,442)
Income tax	255,940	(1,495,087)
Results of operations for producing activities	$ (475,317)	$ 2,776,591

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Supplemental Oil and Gas Reserve Information (Unaudited) (Summary of Capitalized Costs of Oil and gas Properties) (Detail) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Properties subject to amortization	$ 26,642,325	$ 78,090,619
Accumulated depletion	(14,935,386)	(13,827,347)
Net capitalized costs	$ 11,706,939	$ 64,263,272

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Supplemental Oil and Gas Reserve Information (Unaudited) (Cost Incurred in Property Acquisition, Exploration and Development Activities) (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Acquisition of properties	$ 85,895	$ 1,017,698
Exploration costs	0	0
Development costs	165,926	6,078,167
Net capitalized costs	$ 251,821	$ 7,095,865

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Supplemental Oil and Gas Reserve Information (Unaudited) (Estimated Quantities of Proved Reserves) (Detail)	12 Months Ended
	Dec. 31, 2015 Boe bbl Mcf	Dec. 31, 2014 Boe bbl Mcf
Production	(133.7)	(210.1)
Crude Oil [Member]
Beginning	2,946,400	4,444,500
Revisions of previous estimates	(1,151,384)	(1,352,091)
Purchases of minerals in place		2,234
Extensions and discoveries		2,226
Sales of minerals in place	(217,032)
Production	(96,244)	(150,469)
Ending	1,481,740	2,946,400
Natural Gas Liquids [Member]
Beginning	90,900	40,600
Revisions of previous estimates	(35,925)	56,919
Production	(6,045)	(6,619)
Ending	48,930	90,900
Natural Gas [Member]
Beginning | Mcf	8,177,280	7,917,000
Revisions of previous estimates | Mcf	(1,723,732)	578,506
Production | Mcf	(188,408)	(318,226)
Ending | Mcf	6,265,140	8,177,280
Oil Equivalents [Member]
Beginning | Boe	4,400,180	5,804,600
Revisions of previous estimates | Boe	(1,474,598)	(1,198,754)
Purchases of minerals in place | Boe		2,234
Extensions and discoveries | Boe		2,226
Sales of minerals in place | Boe	(217,032)	0
Production | Boe	(133,690)	(210,126)
Ending | Boe	2,574,860	4,400,180

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Supplemental Oil and Gas Reserve Information (Unaudited)(Standardized Measure of Discounted Future Net Cash Flows) (Detail) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Future production revenue	$ 74,087,130	$ 282,557,900
Future production costs	(46,015,320)	(101,119,500)
Future development costs	(5,901,660)	(13,736,500)
Future cash flows before income tax	22,170,150	167,701,900
Future income taxes	0	(4,211,005)
Future net cash flows	22,170,150	163,490,895
10% annual discount for estimating of future cash flows	(13,400,180)	(100,787,044)
Standardized measure of discounted net cash flows	$ 8,769,970	$ 62,703,851

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Supplemental Oil and Gas Reserve Information (Unaudited) (Changes in Standardized Measure of Discounted Future Net Cash Flows) (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Balance beginning of year	$ 62,703,851	$ 81,447,656
Sales, net of production costs	(491,055)	(7,531,119)
Net change in pricing and production costs	(51,184,718)	(19,087,068)
Net change in future estimated development costs	7,834,840	6,281,385
Purchase of minerals in place	0	190,502
Extensions and discoveries	0	35,203
Sale of minerals in place	(2,746,550)	0
Revisions	(8,448,569)	(25,498,141)
Accretion of discount	16,770,190	27,098,964
Change in income tax	(15,668,019)	(233,531)
Balance end of year	$ 8,769,970	$ 62,703,851

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Supplemental Oil and Gas Reserve Information (Unaudited) - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015 USD ($) bbl Mcf	Dec. 31, 2014 USD ($) bbl Mcf	Dec. 31, 2013 bbl Mcf
Percentage Of Oil For Proved Developed Reserves	74.00%	77.00%
Percentage Of Natural Gas For Proved Developed Reserves	26.00%	23.00%
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease), Total	1,825.3	1,404.4
Proved Developed and Undeveloped Reserves, Production	133.7	210.1
Percentage of Decrease Proved Developed And Undeveloped Reserves Production	7.30%	14.90%
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates and Sales of Minerals	1,691.6	1,194.3
Decrease in Oil and Gas Prices | $		$ 20.5
Payments To Acquire Oil and Gas Property | $	$ 251,821	7,095,865
Assets, Current, Total | $	7,213,213	7,411,168
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | $	3,700,000
Loans Payable to Bank, Noncurrent | $	5,000,000
Oil and Gas Properties [Member]
Payments To Acquire Oil and Gas Property | $	$ 250,000
Assets, Current, Total | $		$ 7,400,000
Crude Oil [Member]
Proved Developed and Undeveloped Reserves, Net	1,481,740	2,946,400	4,444,500
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease), Total		1,352,091
Proved Developed and Undeveloped Reserves, Production	96,244	150,469
Decrease in Oil and Gas Prices | $	$ 40.00
Percentage of Decrease in Oil And Gas Prices	46.10%
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	(1,151,384)	(1,352,091)
Proved Developed Producing Reserves [Member] | Crude Oil [Member]
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease), Total		686,091
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	586.6
Proved Developed Non Producing Reserves [Member] | Crude Oil [Member]
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease), Total		38,100
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	42.9
Proved Undeveloped Reserves [Member] | Crude Oil [Member]
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease), Total		627,893
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	522.1
Proved Developed Reserves [Member]
Proved Developed and Undeveloped Reserves, Net	1,851.9	3,048.3
Proved Undeveloped Reserve [Member]
Proved Developed and Undeveloped Reserves, Net	723.0	1,351.9
Natural Gas [Member]
Proved Developed and Undeveloped Reserves, Net | Mcf	6,265,140	8,177,280	7,917,000
Proved Developed and Undeveloped Reserves, Production | Mcf	188,408	318,226
Decrease in Oil and Gas Prices | $	$ 1.37
Percentage of Decrease in Oil And Gas Prices	42.20%
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | Mcf	(1,723,732)	578,506
Natural Gas [Member] | Proved Developed Producing Reserves [Member]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	1,347.9
Natural Gas [Member] | Proved Developed Non Producing Reserves [Member]
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease), Total		143,000
Proved Developed and Undeveloped Reserves, Improved Recovery	262.4
Natural Gas [Member] | Proved Undeveloped Reserves [Member]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	637.8
Natural Gas Liquids [Member]
Proved Developed and Undeveloped Reserves, Net	48,930	90,900	40,600
Proved Developed and Undeveloped Reserves, Production	6,045	6,619
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	(35,925)	56,919
Natural Gas Liquids [Member] | Proved Developed Producing Reserves [Member]
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease), Total		240,000
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	65.6
Natural Gas Liquids [Member] | Proved Developed Non Producing Reserves [Member]
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease), Total		56,919
Proved Developed and Undeveloped Reserves, Improved Recovery	29.7