10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

☒	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, 2017 

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 425
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:

Title of each class	Name of each exchange on which registered
Common Stock, $0.001 par value	New York Stock Exchange LLC
10% Series A Cumulative Redeemable Perpetual Preferred Stock, $0.001 par value	None

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

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

☐   Yes           ☒   No

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

☐   Yes           ☒   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.  

☒   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).

☒    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, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  ☐	Accelerated filer   ☐
Non-accelerated filer  ☐	Smaller reporting company ☒
Emerging growth  ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.    ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

☐   Yes           ☒   No

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 $2.0 million.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: 23,589,790 shares of common stock, $0.001 par value, outstanding on March 15, 2018.

DOCUMENTS INCORPORATED BY REFERENCE

NONE.

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ENERJEX RESOURCES, INC. 

FORM 10-K 

TABLE OF CONTENTS 

		Page
PART I		5
ITEM 1	BUSINESS	5
ITEM 2	PROPERTIES	32
ITEM 1A.	RISK FACTORS	17
ITEM 1B.	UNRESOLVED STAFF COMMENTS	32
ITEM 3.	LEGAL PROCEEDINGS	32
ITEM 4.	MINE SAFETY DISCLOSURE	32
PART II		33
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	33
ITEM 6.	SELECTED FINANCIAL DATA	34
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	34
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	41
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	41
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	41
ITEM 9A	CONTROLS AND PROCEDURES	41
ITEM 9B.	OTHER INFORMATION	42
PART III		43
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	43
ITEM 11.	EXECUTIVE COMPENSATION	43
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	43
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	43
ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	43
PART IV		44
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	44

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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 14 of this report.

Unless the context otherwise requires and for the purposes of this report only:     

● “Exchange Act” refers to the Securities Exchange Act of 1934, as amended;

● “SEC” or the “Commission” refers to the United States Securities and Exchange Commission; and

● “Securities Act” refers to the Securities Act of 1933, as amended.

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 425, San Antonio, Texas 78209.

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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.

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PART I

ITEM 1. BUSINESS

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. (“EnerJex Kansas”). All of our current operations are conducted through EnerJex Kansas, Inc., Black Sable Energy, LLC, a Texas limited liability company (“Black Sable”) and Black Raven Energy, Inc. a Nevada corporation (“Black Raven”). Our leasehold interests are held in our wholly-owned subsidiaries Black Sable, Working Interest, LLC (“Working Interest”) EnerJex Kansas and Black Raven.

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 2016 and 2017 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 October 19, 2017, EnerJex entered into an Agreement and Plan of Merger (the “Merger Agreement”) with AgEagle Aerial Systems, Inc., a Nevada corporation (“AgEagle”), which designs, develops, produces, and distributes technologically advanced small unmanned aerial vehicles (UAV or drones) that are supplied to the agriculture industry, and AgEagle Merger Sub, Inc., a Nevada corporation and wholly-owned subsidiary of the Company (“Merger Sub”). Pursuant to the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will be merged with and into AgEagle, Merger Sub will cease to exist and AgEagle will survive as a wholly-owned subsidiary of the Company (the “Merger”). The respective boards of directors of EnerJex and AgEagle have approved the Merger Agreement and the transactions contemplated thereby.

At the effective time of the Merger (the “Effective Time”), the shares of AgEagle capital stock will be automatically converted into the right to receive 85% of the then issued and outstanding capital stock of the Company on a fully-diluted basis. In addition, at the Effective Time all outstanding options and warrants to purchase shares of AgEagle common stock will be assumed by the Company and converted into options and warrants to purchase shares of Company common stock. No fractional shares of Company common stock will be issued in the Merger but will be rounded to the nearest whole share. Following the consummation of the Merger, former stockholders of AgEagle with respect to the Merger are expected to own 85% of the Company’s outstanding common stock (inclusive of the AgEagle assumed stock options and warrants), and current common and Series A Preferred stockholders of the Company are expected to own 15% of the Company, excluding shares of common stock that may be issued in connection with the conversion of the Company’s Series B Preferred Stock and Series C Preferred Stock, and not including any additional shares which may be issued in connection with the Company’s closing obligation to provide up to $4 million in new working capital and the elimination of all liabilities currently on the Company’s balance sheet.

In connection with the Merger, the Company agreed to file a proxy statement seeking stockholder approval (which proxy was filed as part of the Form S-4 Registration Statement filed by the Company which has become effective to date) to: (a) amend the terms of its Series A Preferred Stock (as discussed below); (b) approve the issuance of the Company’s shares in connection with the Merger to the AgEagle shareholders and new investors, in excess of 19.9% of the Company’s total issued and outstanding shares of common stock; (c) approve the issuance of shares to current Company management and directors in lieu of deferred salary and fees, a majority of which will be held in escrow to secure the Company’s indemnity obligations under the Merger Agreement; and (d) change the name of the Company to “AgEagle Aerial Resources, Inc.” 

The Merger Agreement provides that, immediately following the Effective Time, the existing board of directors and officers of the Company will resign and new directors and officers will be appointed by AgEagle.

The Company intends to dispose of its principal assets, consisting primarily of its Kansas oil and gas properties, concurrently with the closing of the Merger. In the event the Merger is not consummated, the Company does not have a present intention to dispose of the above described assets.

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The completion of the Merger is subject to various customary conditions, including, among other things: (a) the approval of the stockholders of the Company and AgEagle (which Company shareholder approval has been received to date); (b) the accuracy of the representations and warranties made by each of the Company and AgEagle and the compliance by each of the Company and AgEagle with their respective obligations under the Merger Agreement; (c) approval of the stockholders of the Company for the issuance of its common stock and any other securities (x) to the AgEagle stockholders in connection with the Merger and (y) in connection with the financing transactions contemplated by the Merger Agreement; (d) approval for the listing of shares of the Company’s common stock to be issued in the Merger and other related transactions on the NYSE American; and (e) that all of the Company’s assets as disclosed shall have been sold, transferred or otherwise disposed of and the corresponding debt and liabilities shall have been extinguished. The Company’s existing cash resources are insufficient to satisfy all of its outstanding liabilities. Accordingly, in order to satisfy the condition and consummate the Merger, the Company will be required to raise additional funding prior to the closing of the Merger, the failure of which could result in the Company’s failure to consummate the Merger Agreement.

The Merger Agreement contains customary representations, warranties and covenants, including covenants obligating each of the Company and AgEagle to continue to conduct its respective business in the ordinary course, to provide reasonable access to each other’s information and to use reasonable best efforts to cooperate and coordinate to make any filings or submissions that are required to be made under any applicable laws or requested to be made by any government authority in connection with the Merger. The Merger Agreement also contains a customary “no solicitation” provision pursuant to which, or the completion or termination of the Merger, neither the Company nor AgEagle may solicit or engage in discussions with any third party regarding another acquisition proposal unless, in the Company’s case, it has received an unsolicited, bona fide written proposal that the recipient’s board of directors determines is or would reasonably be expected to result in a superior proposal. The Company has paid AgEagle a $50,000 non-refundable fee at the signing of the Merger Agreement. The Merger Agreement contains certain termination rights in favor of each of the Company and AgEagle.

In addition, the Merger Agreement contains provisions for indemnification in the event of any damages suffered by either party as a result of breaches of representations and warranties contained therein. The aggregate maximum indemnification obligation of any indemnifying party for damages with respect to breaches of representations and warranties set forth in the Merger Agreement shall not exceed, in the aggregate, $350,000, other than for fraud, intentional misrepresentation or willful breach. An indemnifying party shall satisfy its indemnification obligations with shares of the Company’s common stock equal to the aggregate amount of losses of the indemnified party, calculated based upon the greater of (i) the value of the Company common stock as of the closing of the Merger; and (ii) the average closing price of the Company’s common stock on the NYSE American for the five trading days immediately prior to the date such a claim is made. The Company has agreed to deposit an aggregate of 1,215,278 shares of common stock to be issued to current officers and directors of the Company in lieu of deferred salary and fees into escrow to secure its indemnification obligations, the issuance of such shares requiring the approval of the Company’s common stockholders.

On October 19, 2017, concurrently with the execution of the Merger Agreement, a principal stockholder of AgEagle (the “Key AgEagle Stockholder”) entered into a voting agreement in favor of EnerJex (the “EnerJex Voting Agreement”). Pursuant to the EnerJex Voting Agreement, the Key AgEagle Stockholder has agreed, among other things, to vote all shares of capital stock of AgEagle beneficially owned by him in favor of the Merger and the adoption of the Merger Agreement and the approval of the transactions contemplated by the Merger Agreement, and any actions required in furtherance thereof. The AgEagle Voting Agreement will terminate upon the earliest to occur of: (i) the termination of the Merger Agreement in accordance with its terms; or (ii) the date on which the Merger becomes effective.

In connection with, and as a condition to the closing of the Merger, the Company is seeking the consent of the holder of its Series A Preferred Stock (“Series A Preferred Stock”) to amend the terms thereof to: (i) allow the Company to pay all accrued but unpaid dividends up to September 30, 2017 in additional shares of Series A Preferred Stock based on the value of the liquidation preference thereof, (ii) eliminate the right of the Series A Preferred Stock holders to receive any dividends accruing after September 30, 2017, and (iii) convert each share of Series A Preferred Stock into 10 shares of Company common stock. An affirmative vote of 66.7% of all shares of Series A Preferred Stock voting as a class as of the record date of the proxy statement is required to amend the terms of the Certificate of Designation to provide for these changes, as required under the Merger Agreement. As of September 30, 2017, the Series A Preferred Stock had accrued a total of $6,039,972 in accrued but unpaid dividends, which would result in an additional 241,599 shares of Series A Preferred Stock being issued by the Company to satisfy these accrued dividends.

The Merger Agreement provides either party the right to terminate the Merger if it has not been consummated by January 31, 2018, provided that if all of the conditions to closing shall have been satisfied or shall be capable of being satisfied at such time, the required closing date may be extended until March 31, 2018. On January 31, 2018, the Company extended the required closing date with AgEagle to March 31, 2018.

More information regarding AgEagle, its business operations, financial results and risk factors relating thereto, is described in greater detail in the Current Report on Form 8-K filed by the Company with the SEC on October 20, 2017.

On November 21, 2017, Alpha Capital Anstalt (“Alpha”) signed a binding commitment letter with the Company to provide prior to or at the closing of the Merger, a minimum of $4 million in new equity capital at a pre-money valuation of between $16 million and $25 million (the “Private Placement”). Per the terms of this commitment letter, in the event any unaffiliated third parties of EnerJex participate in the Private Placement, Alpha’s obligations to fund the Private Placement shall be reduced by such aggregate gross dollar amount funded by such unaffiliated third parties. Alpha has also agreed to convert all notes they hold from the Company into equity at the closing of the Merger. For their funding commitment, Alpha will receive a fee equal to 2.5% of the Company’s outstanding common stock on a fully-diluted basis payable at the closing of the Merger. Alpha’s obligations to fund the Private Placement shall terminate on the earlier to occur of (i) the consummation of the Merger, and (ii) March 31, 2018. The Company further agreed that, at no time from the date hereof until the consummation of the Merger, shall it provide or disclose to Alpha any “material non-public information” regarding itself, without the prior consent of Alpha. The funding of the Private Placement is subject to standard conditions such as accuracy of representations and warranties provided in the Merger Agreement, and other similar conditions.

At a special meeting of shareholders held on March 21, 2018, the Company’s shareholders approved (a) the issuance of the Company’s common stock to the shareholders of AgEagle in connection with and pursuant to the terms of the Merger Agreement in accordance with NYSE American Rules 712 and 713; (b) an amendment to the Company’s Articles of Incorporation to amend the 10% Series A Cumulative Redeemable Perpetual Preferred Stock to: (i) allow the Company to pay all accrued but unpaid dividends up to September 30, 2017 in additional shares of Series A Preferred Stock based on the value of the liquidation preference thereof, (ii) eliminate the right of the Series A Preferred Stock holders to receive any dividends accruing after September 30, 2017, (iii) convert each share of Series A Preferred Stock into 10 shares of common stock (subject to adjustment for a reverse stock split (discussed below)), and (iv) increase the number of Series A Preferred shares by 241,599 shares; (c) an amendment to the Company’s Articles of Incorporation to change the name of the Company to “AgEagle Aerial Systems, Inc.”; (d) the adoption of the EnerJex 2017 Omnibus Equity Incentive Plan (the “Plan”); (e) the issuance of 2,248,264 shares of common stock to current officers and directors in lieu of deferred salary and fees, a majority of which will be held in escrow to secure the Company’s obligations under the Merger Agreement; (f) the conversion of the Company’s Series C Convertible Preferred Stock into shares of common stock in order to comply with the listing rules of the NYSE American; (g) the conversion of the Company’s 10% Series A Cumulative Redeemable Perpetual Preferred Stock into shares of common stock in order to comply with the listing rules of the NYSE American; (h) the issuance of shares of the Company’s common stock, conversion of the Company’s Series C Preferred Stock and conversion of $425,000 owed under five promissory notes held by, Alpha Capital Anstalt, of which $200,000 of the notes have previously been converted into Series C Preferred Stock as of the date of this filing, into shares of common stock in order to comply with the listing rules of the NYSE American. 

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The Plan provides for the grant of up to 2,000,000 shares of common stock (such number based on a post-reverse split amount) as awards which may include incentive stock options (“ISOs”), non-qualified stock options (“NQSOs”), unrestricted shares, restricted shares, restricted stock units, performance stock, performance units, SARs, tandem stock appreciation rights, distribution equivalent rights, or any combination of the foregoing, to key management employees, non-employee directors, and non-employee consultants of the Company or any of its subsidiaries (however, solely Company employees or employees of the Company’s subsidiaries are eligible for incentive stock option awards).

Additionally, the Company plans to conduct a 1-for-25 reverse stock split of the Company’s outstanding common stock, which was approved by Company shareholders on April 27, 2017, prior to the closing of the Merger, which the Company anticipates occurring prior to March 31, 2018.

In addition, as discussed below under “Significant Developments in 2017” the Company’s lender sold our loan on May 10, 2017.  

Significant Developments in 2017

The following briefly describes our most significant corporate developments occurring in 2017:

On February 10, 2017, the Company, Texas Capital Bank (“TCB”) and IberiaBank (collectively, “Sellers”), and PWCM Investment Company IC LLC, and certain financial institutions (collectively, “Buyers”) entered into a Loan Sale Agreement (“LSA”), pursuant to which Sellers sold to Buyers, and Buyers purchased from Sellers, all of Sellers’ right, title and interest in, to and under the October 2011 Amended and Restated Credit Agreement and related loan documents associated therewith, in exchange for (i) a cash payment of $5,000,000 (the “Cash Purchase Price”), (ii) a Synthetic Equity Interest equal to 10% of the proceeds, after Buyer’s realization of a 150% return on the Cash Purchase Price within five (5) years of the closing date of the sale, with payment being distributed 65.78947368% to TCB and 34.21052632% to IberiaBank, and (iii) at any time prior to February 10, 2022, Buyer may acquire the interest in clause (ii) above. In connection with the LSA, the Company released Sellers and its successors as holders of the rights under the Credit Agreement and Loan Documents, including Buyers, from any and all claims under the Credit Agreement and Loan Documents. 

Also on February 10, 2017, the Company and its subsidiaries, and successor lender entered into a binding letter agreement dated February 10, 2017, which was subsequently amended on March 30, 2017 (as amended, the “letter agreement”) pursuant to which:

1. the successor lender agreed to forgive our existing secured loan in the approximate principal amount of $17,295,000, and in exchange entered into a secured promissory note (which we refer to as the “restated secured note”) in the original principal amount of $4,500,000.

2. we:

a. conveyed our oil and gas properties and associated performance and surety bonds in Colorado, Texas, and Nebraska;

b. conveyed all of our shares of Oakridge Energy, Inc. (together, the “conveyed oil and gas assets”); and

c. retained our assets in Kansas and continued as a going concern. The Kansas assets currently provide most of our current operating revenue.

The restated secured note:

a. is secured by a first-priority lien in the Company’s oil and gas producing assets situated in the State of Kansas,

b. evidences accrued interest on the $4,500,000 principal balance at a rate of 16% per annum,

c. bears interest from and after May 1, 2017, at a rate of 16.0% per annum,

d. is pre-payable in full at a discount at any time during the term of the restated secured note upon the Company paying $3,300,000 to successor lender, and

e. matures and is due and payable in full on November 1, 2017 (subject to the extensions described below).

The Company has extended the restated secured note to March 23, 2018. We have an option to extend the maturity date of the restated secured note to April 30, 2018, upon payment of an extension fee of $50,000.

So long as we repay the $3,300,000 in indebtedness on or prior to the maturity date, as extended, all other amounts payable under the restated secured note are to be forgiven.

The closing occurred on May 10, 2017. As part of the closing procedures and net settlement, we issued a promissory note to Pass Creek Resources LLC in the amount of $105,806. The promissory bears interest at 16% per annum and matured on June 9, 2017. The amount due was not paid on June 9, 2017, but the holder has not provided the Company a notice of default.

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In connection with the May 10, 2017 closing and in consideration of the satisfaction of $13,425,000 of the amount due under the Credit Agreement, as amended, the Company and certain of its subsidiaries transferred to PCR Holdings LLC, an affiliate of the successor lenders under the Credit Agreement, all of the Company’s oil and gas properties and assets located in Colorado, Texas, and Nebraska, as well as the Company’s shares of Oakridge Energy, Inc.

To evidence the Company’s remaining $4,500,000 of indebtedness to PWCM Investment Company IC LLC (“PWCM”), RES Investment Group, LLC (“RES”), Round Rock Development Partners, LP (“Round Rock”), and Cibolo Holdings, LLC (“Cibolo Holdings,” and together with PWCM, RES and Round Rock, “Successor Lenders”), the Company’s subsidiaries (except Kansas Holdings, LLC) entered into a Second Amended and Restated Credit Agreement with Cortland Capital Market Services LLC, as Administrative Agent, and the other financial institutions and banks parties thereto (the “New Credit Agreement”), and a related Amended and Restated Note (the “New Note”), in the amount of $3.3 million as described above. 

Our subsidiaries’ obligations under the credit agreement and note are non-recourse and are secured by a first-priority lien in the Company’s and its subsidiaries’ oil properties and assets located in Kansas. The Company was removed as a borrower under the Credit Agreement, but entered into a Guaranty of Recourse Carveouts, pursuant to which the Company guarantees its subsidiaries’ payment of certain fees and expenses due under the Credit Agreement, and may be liable for certain conduct, such as fraud, bad faith, gross negligence, and waste of the Kansas oil properties or assets.

On April 27, 2017, the Company entered into a Services Agreement (“Service Agreement”) with Camber Energy, Inc., to perform certain outsourced interim services for $150,000 per month. Effective December 4, 2017, the Company and Camber Energy, Inc. (“Camber”), mutually agreed to terminate the agreement between the parties effective November 30, 2017.

On December 20, 2017, the Company entered into a Stock Purchase Agreement for the sale of 1,061,750 shares of its Series A 10% Preferred Stock (“Preferred Stock”). The Preferred Stock was sold to one investor at $0.612 per share or the aggregate of $649,791. The Company intends to use the proceeds from the sale of the Preferred Stock to satisfy certain closing conditions of the Merger.

On December 22, 2017, the Company entered into the First Amendment to the Second Amended and Restated Credit Agreement (the “Amendment) with Pass Creek Resources, LLC (“Pass Creek”) and Cortland Capital Market Services, LLC (“Administration Agent”). The Company, Pass Creek, and Administrative Agent are parties to the Second Amended and Restated Credit Agreement dated May 10, 2017. The Maturity Date of the Loan has been extended to the earlier of (i) February 15, 2018 or April 30, 2018, if (a) the Company provides notice to the Administrative Agent of their intent to extend the maturity date and (b) no later than the first Business Day following delivery of such notice pay a $100,000 extension fee, or (ii) the merger of AgEagle Merger Sub, Inc., a wholly-owned subsidiary of the Company and AgEagle Aerial Systems, Inc. pursuant to the Agreement and Plan of Merger dated as of October 19, 2017. At the closing of the First Amendment, the Company paid Pass Creek a $65,000 extension fee and $7,500 to the Administrative Agent for additional fees. The Company also paid the Administrative Agent an additional $45,000 upon the filing of a definitive proxy statement by the Company with the Securities and Exchange Commission. The Company also agreed to borrow Improvement Advances in an amount not to exceed $300,000. The Company has extended the restated secured note to March 23, 2018. We have the option to extend the maturity date of the restated secured note to April 30, 2018, upon payment of an extension fee of $50,000.

Our Business

Our principal strategy, other than completing the Merger as described above, is to acquire, develop, explore and produce domestic onshore oil and natural gas properties. Our business activities are currently focused in Kansas.

Our total net proved oil and gas reserves as of December 31, 2017 were 0.5 million barrels of oil equivalents (BOE), of which 100% was oil. Of the 0.5 million BOE of total proved reserves, approximately 14.7% are classified as proved developed producing and approximately 85.3% are classified as proved undeveloped.

The total PV10 (present value) of our proved reserves as of December 31, 2017 was approximately $1.5 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, 2017.

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Our Kansas Properties

The table below summarizes our current Kansas acreage by project name as of December 31, 2017.

Project Name	Developed Acreage (1)				Undeveloped Acreage				Total Acreage
	Gross		Net (2)		Gross		Net  (2)		Gross		Net (2)
Mississippian Project		4,365		3,492		—		—		4,365		3,492
Other		584		146		—		—		584		146
Total		4,949		3,638		—		—		4,949		3,638

(1) Developed acreage includes all acreage that was held by production as of December 31, 2017.

(2) Net acreage is based on our net working interest as of December 31, 2017.

Mississippian Project

Our Mississippian Project is located in Woodson and Greenwood Counties in Southeast Kansas, where we own a 90% working interest in 4,949 gross acres. Approximately 73.5% of the gross leased acres in this project are currently held-by-production.

As of December 31, 2017, our Mississippian Project was producing approximately 100 gross barrels of oil per day from the Mississippian formation at a depth of approximately 1,700 feet. 

Our Business Strategy

Since the execution of the merger agreement on October 19, 2017, our primary business strategy has focused on achieving the requirements necessary to consummate the merger. We continue to move forward with this strategy with an anticipated closing prior to March 31, 2018. Prior to our pending merger, our principal strategy focused on the 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. The principal elements of our business strategy were:

● 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.

● 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; and

● our ability to implement development program.

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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.

In the event the merger is not consummated, our intent is to refocus on the development of oil and gas properties as set forth above. 

Drilling Activity

During the years ended December 31, 2017 and 2016, we had no drilling activity.

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, 2017 and 2016, the average sales prices, average production costs and direct lifting costs per unit of production.

	Year ended December 31,
	2017		2016
Net Production
Crude oil (bbl)		31,834		58,123
Natural gas liquids (bbl)		75		530
Natural gas (mcf)		11,649		47,554
Average Sales Prices
Crude oil ($ per bbl)		41.04		40.75
Natural gas liquids ($ per bbl)		12.70		7.02
Natural gas (per $ mcf)		1.67		1.51
Average Production Cost (1)  $  per BOE		39.26		43.79
Average Lifting Costs (2) $ per BOE		40.29		39.97

(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, 2017 and 2016. 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,
	2017			2016
Production revenues	$	1,329,004		$	2,461,727
Production costs		(1,363,946	)		(2,661,258	)
Depreciation, depletion and amortization		(127,713	)		(254,329	)
Results of operations for producing activities	$	(162,655	)	$	(453,860	)

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, 2017.

	Active
Project	Gross		Net (1)
Crude Oil
Mississippian Project		45		40.5
Other		3		2.7
Total Oil		48		43.2

(1) Net wells are based on our net working interest as of December 31, 2017.

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Reserves

Proved Reserves

The estimated total PV10 (present value) of our proved reserves as of December 31, 2017 was $1.5 million, compared to $3.4 million as of December 31, 2016. Our total net proved oil and gas reserves as of December 31, 2017 were 0.5 million BOE (100% oil), compared to 1.6 million BOE (64.1% natural gas) as of December 31, 2016. Of the 0.5 million net BOE of total proved reserves at December 31, 2017, approximately 14.7% are classified as proved developed producing and approximately 85.3% are classified as proved undeveloped. See “Glossary” on page 14 for our definition of PV10.

The estimated PV10 of the 0.5 million BOE is set forth in the following table. The PV10 is calculated using an average net oil price of $45.45 per barrel and by applying an annual discount rate of 10% to the forecasted future net cash flow.

Summary of Proved Oil and Gas Reserves

December 31, 2017

	Gross								Net
			Natural Gas				Oil				Natural Gas				Oil
Proved Reserves	Crude Oil		Liquids		Natural Gas		Equivalents		Crude Oil		Liquids		Natural Gas		Equivalents		PV 10 (2)
Category	BBL’s		BBL’s		MCF’s		BOE’s		BBL’s		BBL’s		MCF’s		BOE’s (1)		(before tax)
Proved, Developed		94,100		—		—		94,100		66,810		—		—		66,810		511,740
Proved, Undeveloped		525,100		—		—		525,100		388,980		—		—		388,980		956,800
Total Proved		619,200		—		—		619,200		455,800		—		—		455,800		1,468,540

(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, 2017.

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.

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 2017, we sold oil to ARM Energy Management LLC, Coffeyville Resources, Inc., 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.

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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.

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 2017 we had month-to-month sales contracts with ARM Energy Management LLC, Coffeyville Resources, Inc., 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.

 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.

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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.

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.

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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 one full-time employee. 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, and general and administrative functions. We believe that this use of third-party service providers may enhance our ability to contain operating and general expenses, and capital costs.

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.

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Exploration The phase of operations which covers the search for oil and gas generally in unproven or semi-proven territory.

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.
FERC	Federal Energy Regulatory Commission
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.

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.

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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) 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) 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 34 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.

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.

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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.

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.

For risk factors regarding AgEagle, its business operations and financial results, which will become our business operations and financial results following the consummation of the Merger, see the Current Report on Form 8-K filed by the Company with the SEC on October 20, 2017.

Risks Related to Recent Developments

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

On October 19, 2017, EnerJex entered into an Agreement and Plan of Merger (the “Merger Agreement”) with AgEagle Aerial Systems, Inc., a Nevada corporation (“AgEagle”), which designs, develops, produces, and distributes technologically advanced small unmanned aerial vehicles (UAV or drones) that are supplied to the agriculture industry, and AgEagle Merger Sub, Inc., a Nevada corporation and wholly-owned subsidiary of the Company (“Merger Sub”). Pursuant to the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will be merged with and into AgEagle, Merger Sub will cease to exist and AgEagle will survive as a wholly-owned subsidiary of the Company (the “Merger”). The respective boards of directors of EnerJex and AgEagle have approved the Merger Agreement and the transactions contemplated thereby.

At the effective time of the Merger (the “Effective Time”), the shares of AgEagle capital stock will be automatically converted into the right to receive equal to 85% of the then issued and outstanding capital stock of the Company on a fully diluted basis. In addition, at the Effective Time all outstanding options and warrants to purchase shares of AgEagle common stock will be assumed by the Company and converted into options and warrants to purchase shares of Company common stock. No fractional shares of Company common stock will be issued in the Merger but will be rounded to the nearest whole share. Following the consummation of the Merger, former stockholders of AgEagle with respect to the Merger are expected to own 85% of the Company’s outstanding common stock (inclusive of the AgEagle assumed stock options and warrants), and current common and Series A Preferred stockholders of the Company are expected to own 15% of the Company, excluding shares of common stock that may be issued in connection with the conversion of the Company’s Series B Preferred Stock and Series C Preferred Stock, and not including any additional shares which may be issued in connection with the Company’s closing obligation to provide up to $4 million in new working capital and the elimination of all liabilities currently on the Company’s balance sheet.

In connection with the Merger, the Company will also file a proxy statement seeking stockholder approval to: (a) amend the terms of its Series A Preferred Stock (as discussed below); (b) approve the issuance of the Company’s shares in connection with the Merger to the AgEagle shareholders and new investors, in excess of 19.9% of the Company’s total issued and outstanding shares of common stock; (c) approve the issuance of shares to current Company management and directors in lieu of deferred salary and fees, a majority of which will be held in escrow to secure the Company’s indemnity obligations under the Merger Agreement; and (d) change the name of the Company to “AgEagle Aerial Resources, Inc.” 

The Merger Agreement provides that, immediately following the Effective Time, the existing board of directors and officers of the Company will resign and new directors and officers will be appointed by AgEagle.

The Company intends to dispose of its principal assets, consisting primarily of its Kansas oil and gas properties, concurrently with the closing of the Merger. In the event the Merger is not consummated, the Company does not have a present intention to dispose of the above described assets.

 17

The completion of the Merger is subject to various customary conditions, including, among other things: (a) the approval of the stockholders of the Company and AgEagle (which Company shareholder approval has been received to date); (b) the accuracy of the representations and warranties made by each of the Company and AgEagle and the compliance by each of the Company and AgEagle with their respective obligations under the Merger Agreement; (c) approval of the stockholders of the Company for the issuance of its common stock and any other securities (x) to the AgEagle stockholders in connection with the Merger and (y) in connection with the financing transactions contemplated by the Merger Agreement; (d) approval for the listing of shares of the Company’s common stock to be issued in the Merger and other related transactions on the NYSE American; and (e) that all of the Company’s assets as disclosed shall have been sold, transferred or otherwise disposed of and the corresponding debt and liabilities shall have been extinguished. The Company’s existing cash resources are insufficient to satisfy all of its outstanding liabilities. Accordingly, in order to satisfy the condition and consummate the Merger, the Company will be required to raise additional funding prior to the closing of the Merger, the failure of which could result in the Company’s failure to consummate the Merger Agreement.

The Merger Agreement contains customary representations, warranties and covenants, including covenants obligating each of the Company and AgEagle to continue to conduct its respective business in the ordinary course, to provide reasonable access to each other’s information and to use reasonable best efforts to cooperate and coordinate to make any filings or submissions that are required to be made under any applicable laws or requested to be made by any government authority in connection with the Merger. The Merger Agreement also contains a customary “no solicitation” provision pursuant to which, prior to the earlier of January 31, 2018, or the completion or termination of the Merger, neither the Company nor AgEagle may solicit or engage in discussions with any third party regarding another acquisition proposal unless, in the Company’s case, it has received an unsolicited, bona fide written proposal that the recipient’s board of directors determines is or would reasonably be expected to result in a superior proposal. The Company has paid AgEagle a $50,000 non-refundable fee at the signing of the Merger Agreement. The Merger Agreement contains certain termination rights in favor of each of the Company and AgEagle.

In addition, the Merger Agreement contains provisions for indemnification in the event of any damages suffered by either party as a result of breaches of representations and warranties contained therein. The aggregate maximum indemnification obligation of any indemnifying party for damages with respect to breaches of representations and warranties set forth in the Merger Agreement shall not exceed, in the aggregate, $350,000, other than fraud, intentional misrepresentation or willful breach. An indemnifying party shall satisfy its indemnification obligations with shares of Company common stock equal to the aggregate amount of losses of the indemnified party, calculated based upon the greater of (i) the value of the Company common stock as of the closing of the Merger; and (ii) the average closing price of the Company common stock on the NYSE American for the five trading days immediately prior to the date such a claim is made. The Company has agreed to deposit an aggregate of 1,215,278 shares of common stock to be issued to current officers and directors of the Company in lieu of deferred salary and fees into escrow to secure its indemnification obligations, the issuance of such shares requiring the approval of the Company’s common stockholders.

In connection with, and as a condition to the closing of the Merger, the Company is seeking the consent of the holder of its Series A Preferred Stock (“Series A Preferred Stock”) to amend the terms thereof to: (i) allow the Company to pay all accrued but unpaid dividends up to September 30, 2017 in additional shares of Series A Preferred Stock based on the value of the liquidation preference thereof, (ii) eliminate the right of the Series A Preferred Stock holders to receive any dividends accruing after September 30, 2017, and (iii) convert each share of Series A Preferred Stock into 10 shares of Company common stock. An affirmative vote of 66.7% of all shares of Series A Preferred Stock voting as a class as of the record date of the proxy statement is required to amend the terms of the Certificate of Designation to provide for these changes, as required under the Merger Agreement. As of September 30, 2017, the Series A Preferred Stock had accrued a total of $6,039,972 in accrued but unpaid dividends, which would result in an additional 241,599 shares of Series A Preferred Stock being issued by the Company to satisfy these accrued dividends.

The Merger Agreement provides either party the right to terminate the Merger if it has not been consummated by January 31, 2018, provided that if all of the conditions to closing shall have been satisfied or shall be capable of being satisfied at such time, the required closing date may be extended until March 31, 2018. On January 31, 2018, the Company extended the required closing date with AgEagle to March 31, 2018.

Should we not be able to close this transaction, our existing and future debt agreements become due and that will threaten our ability to continue as a going concern. The Company will seek to negotiate an extension of such indebtedness or may seek bankruptcy protection if this transaction is not approved by the shareholders.

In the event the Merger closes, it will cause immediate and substantial dilution to existing shareholders and a change of control of the Company.

As described above, we are party to a Merger Agreement with AgEagle relating to the acquisition by us of the outstanding securities of AgEagle.  We anticipate the consideration exchanged with AgEagle for the securities of AgEagle will be 85% of our total outstanding securities on a fully-diluted basis.  Additionally, we anticipate issuing other securities in connection with the Merger, including, but not limited to, in order to raise funding in connection therewith. As such, in the event the contemplated transaction closes, the issuance of the common stock consideration to AgEagle and to other parties will result in immediate and substantial dilution to the interests of our then shareholders and result in a change of control of the Company.

 18

The Merger Agreement limits our ability to pursue alternatives to the Merger.

The Merger Agreement contains provisions that could adversely impact competing proposals to acquire us. These provisions include the prohibition on us generally from soliciting any acquisition proposal or offer for a competing transaction. These provisions might discourage a third party that might have an interest in acquiring all or a significant part of our company from considering or proposing an acquisition, even if that party were prepared to pay consideration with a higher value than the current proposed Merger consideration.

Failure to complete the Merger could negatively impact our stock price and future business and financial results.

If the Merger is not completed, our ongoing business may be adversely affected and we would be subject to a number of risks, including the following:

● we will not realize the benefits expected from the Merger, including a potentially enhanced competitive and financial position, expansion of operations, and will instead be subject to all the risks we currently face as an independent company;

● we may experience negative reactions from the financial markets and our partners and employees;

● the Merger Agreement places certain restrictions on the conduct of our business prior to the completion of the Merger or the termination of the Merger Agreement. Such restrictions, the waiver of which is subject to the consent of AgEagle, may prevent us from making certain acquisitions, taking certain other specified actions or otherwise pursuing business opportunities during the pendency of the Merger; and

● matters relating to the Merger (including integration planning) may require substantial commitments of time and resources by our management, which would otherwise have been devoted to other opportunities that may have been beneficial to us as an independent company.

The Merger Agreement may be terminated in accordance with its terms and the Merger may not be completed.

The completion of the Merger is subject to various customary conditions, including, among other things: (a) the approval of the shareholders of the Company and AgEagle (which Company shareholder approval has been received to date); (b) the accuracy of the representations and warranties made by each of the Company and AgEagle and the compliance by each of the Company and AgEagle with their respective obligations under the Merger Agreement; (c) approval of the shareholders of the Company for the issuance of its common stock and any other securities (x) to the AgEagle shareholders in connection with the Merger and (y) in connection with the financing transactions contemplated by the Merger Agreement; (d) approval for the listing of shares of the Company’s common stock to be issued in the Merger and other related transactions on the NYSE American; and (e) that all of the Company’s assets as disclosed shall have been sold, transferred or otherwise disposed of and the corresponding debt and liabilities shall have been extinguished. The Company’s existing cash resources are insufficient to satisfy all of its outstanding liabilities. Accordingly, in order to satisfy the condition and consummate the Merger, the Company will be required to raise additional funding prior to the closing of the Merger, the failure of which could result in the Company’s failure to consummate the Merger Agreement. These conditions to the closing of the Merger may not be fulfilled and, accordingly, the Merger may not be completed. In addition, if the Merger is not completed by March 31, 2018, either we or AgEagle may choose not to proceed with the Merger, and the parties can mutually decide to terminate the Merger Agreement at any time, before or after shareholder approval. In addition, we or AgEagle may elect to terminate the Merger Agreement in certain other circumstances.

Termination of the Merger Agreement could negatively impact the Company.

In the event the Merger Agreement is terminated, our business may have been adversely impacted by our failure to pursue other beneficial opportunities due to the focus of management on the Merger, and the market price of our common stock might decline to the extent that the current market price reflects a market assumption that the Merger will be completed. If the Merger Agreement is terminated and our board of directors seek another business combination, our shareholders cannot be certain that we will be able to find a party willing to offer equivalent or more attractive consideration than the consideration provided for by the Merger. 

We will be subject to business uncertainties and contractual restrictions while the Merger is pending.

Uncertainty about the effect of the Merger on our partners may have an adverse effect on us. These uncertainties may impair our ability to attract, retain and motivate key personnel until the Merger is completed, and could cause partners and others that deal with us to seek to change existing business relationships, cease doing business with us or cause potential new partners to delay doing business with us until the Merger has been successfully completed. Retention of certain employees may be challenging during the pendency of the Merger, as certain employees may experience uncertainty about their future roles or compensation structure. If key employees depart because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the business, our business following the Merger could be negatively impacted. In addition, the Merger Agreement restricts us from making certain acquisitions and taking other specified actions until the Merger is completed or terminated without the consent of AgEagle. These restrictions may prevent us from pursuing attractive business opportunities that may arise prior to the completion of the Merger.

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We have substantial indebtedness which is secured by substantially all of our assets.

Our subsidiaries’ obligations under the credit agreement and note are non-recourse and are secured by a first-priority lien in the Company’s and the subsidiaries’ oil properties and assets located in Kansas. The Company was removed as a borrower under the Credit Agreement, but entered into a Guaranty of Recourse Carveouts, pursuant to which the Company guarantees the Subsidiaries’ payment of certain fees and expenses due under the Credit Agreement, and may be liable for certain conduct, such as fraud, bad faith, gross negligence, and waste of the Kansas oil properties or assets. In the event we fail to repay our debts our creditors may enforce their security interests and foreclose on our assets, which would likely cause any investment in the company to become worthless.

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.

We are subject to the Continued Listing Criteria of the NYSE American and our failure to satisfy these criteria may result in delisting of our common stock.

Our common stock is currently listed on the NYSE American. In order to maintain this listing, we must maintain certain share prices, financial and share distribution targets, including maintaining a minimum amount of shareholders’ equity and a minimum number of public shareholders. In addition to these objective standards, the NYSE American may delist the securities of any issuer if, in its opinion, the issuer’s financial condition and/or operating results appear unsatisfactory; if it appears that the extent of public distribution or the aggregate market value of the security has become so reduced as to make continued listing on the NYSE American inadvisable; if the issuer sells or disposes of principal operating assets or ceases to be an operating company; if an issuer fails to comply with the NYSE American’s listing requirements; if an issuer’s common stock sells at what the NYSE American considers a “low selling price” (generally trading below $0.20 per share for an extended period of time) and the issuer fails to correct this via a reverse split of shares after notification by the NYSE American (provided that issuers can also be delisted if any shares of the issuer trade below $0.06 per share); or if any other event occurs or any condition exists which makes continued listing on the NYSE American, in its opinion, inadvisable. As described below, the NYSE American has previously provided us a deficiency letter due to our common stock trading below $0.20 per share.

If the NYSE American delists our common stock, investors may face material adverse consequences, including, but not limited to, a lack of trading market for our securities, reduced liquidity, decreased analyst coverage of our securities, and an inability for us to obtain additional financing to fund our operations.

We are currently not in compliance with NYSE American continued listing standards and if we are unable to maintain compliance with NYSE American continued listing standards, our common stock may be delisted from the NYSE American equities market, which would likely cause the liquidity and market price of our common stock to decline.

Our common stock is currently listed on the NYSE American. The NYSE American will consider suspending dealings in, or delisting, securities of an issuer that does not meet its continued listing standards. If we cannot meet the NYSE American continued listing requirements, the NYSE American may delist our common stock, which could have an adverse impact on us and the liquidity and market price of our stock. 

We may be unable to comply with NYSE American continued listing standards. Our business has been and may continue to be affected by worldwide macroeconomic factors, which include uncertainties in the credit and capital markets. External factors that affect our stock price, such as liquidity requirements of our investors, as well as our performance, could impact our market capitalization, revenue and operating results, which, in turn, could affect our ability to comply with the NYSE American’s listing standards. The NYSE American has the ability to suspend trading in our common stock or remove our common stock from listing on the NYSE American if in the opinion of the exchange: (a) the financial condition and/or operating results of the Company appear to be unsatisfactory; or (b) it appears that the extent of public distribution or the aggregate market value of our common stock has become so reduced as to make further dealings on the exchange inadvisable; or (c) we have sold or otherwise disposed of our principal operating assets, or have ceased to be an operating company; or (d) we have failed to comply with our listing agreements with the exchange (which include that we receive additional listing approval from the exchange prior to us issuing any shares of common stock, something we have inadvertently failed to comply with in the past); or (e) any other event shall occur or any condition shall exist which makes further dealings on the exchange unwarranted.

 20

On October 19, 2017, the Company received notice from NYSE Regulation, Inc. that it is not in compliance with certain NYSE American (“NYSE American”) continued listing standards relating to stockholders’ equity. Specifically, the Company is not in compliance with Section 1003(a)(i) (requiring stockholders’ equity of $2.0 million or more if an issuer has reported losses from continuing operations and/or net losses in two of its three most recent fiscal years) of the NYSE American Company Guide (the “Company Guide”).

On November 20, 2017, the Company filed a plan of compliance with the proposed steps the Company will take to regain compliance with all applicable criteria for listing on the NYSE American and in particular Section 1003(a)(i). The plan was based in significant part upon the Merger and the associated financing.

On December 22, 2017, the Company was notified by the NYSE American that NYSE Regulation had accepted the Company’s plan to regain compliance with the NYSE American’s continued listing standards of the Company Guide by April 17, 2019, subject to periodic review by the NYSE American for compliance with the initiatives set forth in the plan. If the Company is not in compliance with the continued listing standards by April 17, 2019, or if the Company does not make progress consistent with the plan during the plan period, the NYSE Regulation staff may initiate delisting proceedings as appropriate.

Additionally, on February 28, 2018, the Company received notification (the “Deficiency Letter”) from the NYSE American that the Company’s shares of common stock have been selling for a low price per share for a substantial period of time. Pursuant to Section 1003(f)(v) of the Company Guide, the NYSE American staff determined that the Company’s continued listing is predicated on it effecting a reverse stock split of its common stock or otherwise demonstrating sustained price improvement within a reasonable period of time, which the staff determined to be until August 28, 2018. The Company’s common stock will continue to be listed on the NYSE American while it attempts to regain compliance with the Listing Standards, subject to the Company’s compliance with other continued listing requirements, as described above. The Deficiency Letter does not affect the Company’s business operations or its Securities and Exchange Commission reporting requirements. 

At the present time, the Company has obtained shareholder approval to effectuate a reverse stock split at a ratio of between one-for-two and one-for-twenty five with such ratio to be determined at the sole discretion of the Board of the Directors of the Company. The Company’s Board of Directors is currently assessing which ratio would best serve the Company’s stockholders while allowing the Company to remain compliant with the NYSE American continued listing requirements.

If we are unable to retain compliance with the NYSE American criteria for continued listing, our common stock would be subject to delisting. A delisting of our common stock could negatively impact us by, among other things, reducing the liquidity and market price of our common stock and reducing the number of investors willing to hold or acquire our common stock, which could negatively impact our ability to raise equity financing. In addition, delisting from the NYSE American might negatively impact our reputation and, as a consequence, our business. Additionally, if we were delisted from the NYSE American and we are not able to list our common stock on another national exchange we will no longer be eligible to use Form S-3 registration statements and will instead be required to file a Form S-1 registration statement for any primary or secondary offerings of our common stock, which would delay our ability to raise funds in the future, may limit the type of offerings of common stock we could undertake, and would increase the expenses of any offering, as, among other things, registration statements on Form S-1 are subject to SEC review and comments whereas take downs pursuant to a previously filed Form S-3 are not.

If we are delisted from the NYSE American, your ability to sell your shares of our common stock would also be limited by the penny stock restrictions, which could further limit the marketability of your shares.

If our common stock is delisted from the NYSE American, it would come within the definition of “penny stock” as defined in the Exchange Act and would be covered by Rule 15g-9 of the Exchange Act. That Rule imposes additional sales practice requirements on broker-dealers who sell securities to persons other than established customers and accredited investors. For transactions covered by Rule 15g-9, the broker-dealer must make a special suitability determination for the purchaser and receive the purchaser’s written agreement to the transaction prior to the sale. Consequently, Rule 15g-9, if it were to become applicable, would affect the ability or willingness of broker-dealers to sell our securities, and accordingly would affect the ability of shareholders to sell their securities in the public market. These additional procedures could also limit our ability to raise additional capital in the future.

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.  

While our bank sold its rights under our credit facility to the successor lender, and the successor lender has agreed to a transaction in which we can contribute certain of our assets, our shares in Oakridge Energy, and reduce our loan amount from $17,925,000 to a restated note in the original principal amount of $4,500,000, subject to a $1,200,000 discount provided that we repay the successor lender $3,300,000 prior to the original maturity date of November 1, 2017, which has been extended to March 23, 2018 and can be extended to April 30, 2018. In exchange we can retain our Kansas oil and gas assets. Unless and until this transaction closes (which is dependent on the approval of our stockholders), we will remain in default on our obligations, and the successor lender may enforce its rights as secured parties and we will likely lose all of our Kansas assets and may be forced to liquidate the Company.

 21

We are unable to fulfill our obligations under our credit facility which is adversely affecting our business.

As of December 31, 2017, we had total indebtedness of $4,457,347 under the credit facility. 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. At December 31, 2017, we were not in compliance with certain covenants. The Company has extended the restated secured note to March 23, 2018 and has an option to extend the maturity date of the restated secured note to April 30, 2018, upon payment of an extension fee of $50,000.    

Our 2017 oil and gas reserve report shows a material decline in our estimated reserves, which will have adverse implications to our business.

Our 2017 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.

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.

 22

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 depreciation, depletion and amortization (DD&A) in the statement of operations. The ceiling calculation is performed quarterly. For the year ended December 31, 2017, no impairment charges were recorded.

Future conditions might require us to make write-downs in our assets, which would adversely affect our balance sheet and results of operations.

We review our long-lived tangible and intangible assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. We also test our goodwill and indefinite-lived intangible assets for impairment at least annually on December 31 of each year, or when events or changes in the business environment indicate that the carrying value of a reporting unit may exceed its fair value. If conditions in any of the businesses in which we compete were to deteriorate, we could determine that certain of our assets were impaired and we would then be required to write-off all or a portion of our costs for such assets. Any such significant write-offs would adversely affect our balance sheet and results of operations.

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.

 23

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.   

 The threat and impact of terrorist attacks, cyber attacks or similar hostilities may adversely impact our operations.

We cannot assess the extent of either the threat or the potential impact of future terrorist attacks on the energy industry in general, and on us in particular, either in the short-term or in the long-term. Uncertainty surrounding such hostilities may affect our operations in unpredictable ways, including the possibility that infrastructure facilities, including pipelines and gathering systems, production facilities, processing plants and refineries, could be targets of, or indirect casualties of, an act of terror, a cyber attack or electronic security breach, or an act of war.

Improvements in or new discoveries of alternative energy technologies could have a material adverse effect on our financial condition and results of operations.

Because our operations depend on the demand for oil and used oil, any improvement in or new discoveries of alternative energy technologies (such as wind, solar, geothermal, fuel cells and biofuels) that increase the use of alternative forms of energy and reduce the demand for oil, gas and oil and gas related products could have a material adverse impact on our business, financial condition and results of operations.

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;

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• 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 85.3% of our total proved reserves as of December 31, 2017 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, 2017 was $1.5 million, versus $3.4 million as of December 31, 2016.  Of the 0.5 million BOE of total proved reserves, approximately 14.7% are classified as proved developed producing and approximately 85.3% 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. For further information please see the disclosures in “Note 14 - Supplemental Oil and Gas Reserve Information (Unaudited)” to the Financial Statements included herein.

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, 2017 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

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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.  

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.

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.

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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.

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 if 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.

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.

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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 Kansas. 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 sell oil to Coffeyville Resources. There are approximately six 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 are not the operator 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 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.

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.

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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 current operations are located in or near established fields in Kansas. 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 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.

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 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.

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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. 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.

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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 is traded on the NYSE American and our Series A preferred stock is traded on the OTC PINK, daily trading volumes are small making it difficult for investors to sell their shares.

Our common stock and our Series A preferred stock trade under the symbol “ENRJ,” and “ENRJP,” 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.

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. Furthermore, 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.

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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.

Shareholders may be diluted significantly through our efforts to obtain financing and satisfy obligations through the issuance of securities.

Wherever possible, our board of directors will attempt to use non-cash consideration to satisfy obligations. In many instances, we believe that the non-cash consideration will consist of shares of our common stock, preferred stock or warrants to purchase shares of our common stock. Our board of directors has authority, without action or vote of the shareholders, subject to the requirements of the NYSE American (which generally require shareholder approval for any transactions which would result in the issuance of more than 20% of our then outstanding shares of common stock or voting rights representing over 20% of our then outstanding shares of stock), to issue all or part of the authorized but unissued shares of common stock, preferred stock or warrants to purchase such shares of common stock. In addition, we may attempt to raise capital by selling shares of our common stock, possibly at a discount to market in the future. These actions will result in dilution of the ownership interests of existing shareholders and may further dilute common stock book value, and that dilution may be material. Such issuances may also serve to enhance existing management’s ability to maintain control of us, because the shares may be issued to parties or entities committed to supporting existing management.

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 2. PROPERTIES.

Facilities

Executive offices are maintained at 4040 Broadway, Suite 425, San Antonio, Texas 78209 under a month-to-month agreement. 

Oil and Gas Properties

Information regarding the Company’s oil and gas properties can be found in “Item 1. Business”, above and under “Note 14 - Supplemental Oil and Gas Reserve Information (Unaudited)” to the Financial Statements included herein.

ITEM 3. LEGAL PROCEEDINGS.

On September 23, 2016, the Company, American Standard Energy Corporation, Baylor Operating LLC, Bernard Given and Loeb & Loeb LLP were sued by Geronimo Holdings Corporation and Randal Capps in the 143rd Judicial District Court located in Pecos, Texas. The suit among other things, seeks damages for an alleged unlawful sale of properties in Crockett County Texas and for alleged unpaid royalties. The Company believes the suit is without merit and will vigorously defend itself. The Company has faith that it will prevail and at December 31, 2016 no reserve for potential losses arising from this matter has been recorded. Additionally, under its agreement with Baylor Operating LLC, Baylor has agreed to indemnify and defend the Company against all lawsuits and claims including this one.

On April 26, 2016, C&F Ranch, LLC sued the Company in Allen County Kansas for alleged breach of contract related to the rental of certain lands located on the C&F Ranch. During the first quarter of 2018, the Company settled this dispute for $9,000.

ITEM 4. MINE SAFETY DISCLOSURE

None.

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PART II

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

Market Information for Common Stock

Our common stock trades on the NYSE American under the symbol “ENRJ.” The following table lists the quotations for the high and low sales prices of our common stock for each quarter during the years ended December 31, 2016 and December 31, 2017. 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.  

Year Ended December 31, 2016	High		Low
Quarter ended March 31, 2016	$	0.59	$	0.17
Quarter ended June 30, 2016	$	0.49	$	0.22
Quarter ended September 30, 2016	$	0.83	$	0.26
Quarter ended December 31, 2016	$	0.46	$	0.24
Year Ended December 31, 2017
Quarter ended March 31, 2017	$	0.81	$	0.26
Quarter ended June 30, 2017	$	1.15	$	0.21
Quarter ended September 30, 2017	$	0.46	$	0.26
Quarter ended December 31, 2017	$	0.85	$	0.20

Holders

As of March 15, 2018, there were 333 holders of record of our common stock, 8 holders of record of our Series A preferred stock, and one holder of both our Series B preferred stock and Series C preferred stock.  

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 in aggregate annual dividends 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, any 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 a maximum rate of 15.0% 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. During 2017, cash dividends were not paid and the dividends accumulated at 15.0% per annum.

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 Preferred Stock, 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 the fiscal year ended December 31, 2017 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		15,332	$	7.63		700,158

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Recent Sales of Unregistered Securities

Except as discussed below, the Company has not issued, sold or granted any unregistered securities since September 30, 2017, other than those issuances, sales and grants which have previously been included in a Quarterly Report on Form 10-Q or in a Current Report on Form 8-K.

On July 14, 2017, July 28, 2017 and August 30, 2017, the Company entered into Secured Promissory Notes totaling $225,000 with Alpha Capital Anstalt, which have a maturity date of June 30, 2018, and accrue interest at a rate of 8% per annum. The amount due under the notes is secured by a security interest, subordinate to certain other security interests of the Company, in substantially all of the Company's assets. The amount due under the notes is convertible into shares of the Company's common stock, at the option of Alpha Capital Anstalt, on identical terms as the outstanding Series C Convertible Preferred Stock (i.e., an initial conversion price of $0.30 per share, a 9.9% ownership limitation and certain anti-dilution rights, which currently result in a conversion price of $0.0612 per share). As of December 31, 2017, the principal balance of $225,000 remained due.

As previously reported, on April 27, 2017, the Company entered into an Additional Issuance Agreement with Alpha Capital Anstalt, for the purchase of 300 restricted shares of the Company's then newly designated Series C Convertible Preferred Stock in consideration for $300,000, with an option to purchase an additional 200 shares of Series C Convertible Preferred Stock for an aggregate purchase price of $200,000. As of December 31, 2017, the Company had issued 300 shares of Series C Convertible Preferred Stock for an aggregate purchase price of $300,000. In addition, during the year ended December 31, 2017, the Company had received $200,000 from Alpha Capital Anstalt to purchase an additional 200 shares of Series C Convertible Preferred Stock, which shares had not been issued as of December 31, 2017, and which are reflected as Series C Convertible Preferred Stock Issuable on the balance sheet as of December 31, 2017, in the aggregate amount of $200,000.

On February 13, 2018, the Company issued Alpha Capital Anstalt the 200,000 shares of Series C Convertible Preferred Stock which it was due pursuant to the terms of the April 27, 2017, Additional Issuance Agreement, in consideration for the $200,000 paid during the year ended December 31, 2017.

We claim an exemption from registration pursuant to Section 4(a)(2) and/or Rule 506 of Regulation D of the Securities Act, since the transactions did not involve a public offering, the recipient was an “accredited investor”, and acquired the securities for investment only and not with a view towards, or for resale in connection with, the public sale or distribution thereof. The securities are subject to transfer restrictions, and the certificates evidencing the securities contain an appropriate legend stating that such securities have not been registered under the Securities Act and may not be offered or sold absent registration or pursuant to an exemption therefrom and are further subject to the terms of the escrow agreement. The securities were not registered under the Securities Act and such securities may not be offered or sold in the United States absent registration or an exemption from registration under the Securities Act and any applicable state securities laws.

Subsequent to December 31, 2017, Alpha Capital Anstalt converted (a) 343.671 shares of Series B Convertible Preferred Stock into 5,610,955 shares of common stock; and (b) 103.142 shares of Series C Convertible Preferred Stock into 1,683,944 shares of common stock, pursuant to the terms of such securities.

We claim an exemption from registration provided by Section 3(a)(9) of the Securities Act for such issuance, as the securities were exchanged by us with our existing security holder in a transaction where no commission or other remuneration was paid or given directly or indirectly for soliciting such exchange.

Issuer Purchases of Equity Securities

None.

ITEM 6. SELECTED FINANCIAL DATA.

Not applicable.

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 be read in conjunction with the other sections of this Annual Report on Form 10-K, including “Item 1 Business” and “Item 2. 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

Since the execution of the merger agreement on October 19, 2017, our primary business strategy has focused on achieving the requirements necessary to consummate the merger. We continue to move forward with this strategy with an anticipated closing prior to March 31, 2018. In the event the merger is not consummated, our intent is to refocus on the development of oil and gas properties. Our business activities are currently focused in Kansas.

Results of Operations

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

	Year Ended		Year Ended
	December 31,		December 31,
	2017		2016		Difference
Oil & gas revenues (1)
Crude oil revenues	$	1,309,496	$	2,390,024	$	(1,080,528	)
Average price per Bbl		41.04		40.75		0.29
Natural gas revenues		19,509		71,703		(52,194	)
Average price per Mcf		1.67		1.51		0.16
Expenses:
Lease operating expenses (2)		1,363,946		2,661,258		(1,297,312	)
Depreciation, depletion and amortization (3)		239,776		254,329		(14,553	)
Impairment of oil and gas properties		—		8,032,670		(8,032,670	)
Total production expenses		1,603,722		10,948,257		(9,344,535	)
Professional fees (4)		1,390,512		310,471		1,080,041
Salaries (5)		350,863		1,723,789		(1,372,926	)
Depreciation - other fixed assets		106,421		159,638		(53,217	)
Administrative expenses (6)		545,267		458,375		86,892
Total expenses	$	3,996,785	$	13,600,530	$	(9,603,745	)

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⁽¹⁾ 2017 crude oil revenues decreased $1.1 million or 45% to 1.3 million from $2.4 million in fiscal 2016.  This decrease was due to the decline in production. Realized oil prices increased $0.29 or 1% during 2017 from an average of $40.75 per bbl in 2016 to an average of $41.04 per bbl in 2017. Increasing prices offset the drop in crude oil revenues by approximately $17,000. A decrease in production volumes in 2017 accounted for substantially all of the $1.1 million decrease in revenues. Volumes decreased by approximately 26,700 bbls or 46% to 31,909 bbls in 2017 compared to production of 58,653 bbls in 2016.  2017 natural gas revenues decreased approximately $52,000 or 73% to $19,500 from $71,700 in 2016. The decrease was due to lower production in 2016. Natural gas prices increased $0.17 per mcf or 11% from an average price of $1.51 in 2016 to an average price of $1.67 in 2017. This increase in prices offset the decrease in revenue by $8,000. A decrease in production volumes accounted for $60,000 of the $52,000 decrease in revenues. Natural gas volumes decreased approximately 35,900 mcf or 76% in 2017 from 47,600 mcf in 2016 to 11,600 mcf in 2017.

⁽²⁾ 2017 lease operating expenses decreased $1.3 million or 49% to $1.4 million from $2.7 million in 2016. However, lease operating expenses per boe increased 1% or $0.32 to $40.29 in 2017 from $39.97 per boe in 2016.  

⁽³⁾ Depletion expense per boe increased 85% or $3.26 per boe from $3.82 per boe in 2016 to $7.08 per boe in 2017. During 2017, depletion expense decreased approximately $14,000 to approximately $240,000 from $254,000 in 2016.

⁽⁴⁾ Professional fees increased 348% or approximately $1.1 million from approximately $310,500 in 2016 to approximately $1,390,512 in 2017. The use of consultants, to replace the reduction in employees, accounted for $765,000 of this increase. In addition, legal fees increased by $309,000.

⁽⁵⁾ Salaries decreased 80% or approximately $1.4 million. The decrease was due primarily to decreased head counts following the LSA transaction.

⁽⁶⁾ Administrative expenses increased approximately $87,000 or 19%. The increase was due primarily to increased spending on SEC matters of $104,000.  

Reserves

	Year Ended		Year Ended
	December 31,		December 31,
Proved Reserves	2017		2016
Total proved PV10 (present value) of reserves	$	1,468,540	$	3,437,030
Total proved reserves (BOE)	$	455,790	$	1,587,690
Average Price (per bbl)	$	51.34	$	37.36
Average Price (per mcf)	$	2.97	$	1.65

Of the 0.5 million BOE of total proved reserves, approximately 14.7% are classified as proved developed producing and approximately 85.3% are classified as proved undeveloped.

The following table presents summary information regarding our estimated net proved reserves as of December 31, 2017. 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 14 to our audited financial statements for the fiscal year ended December 31, 2017.

Summary of Proved Oil and Gas Reserves 

December 31, 2017

	Gross								Net
			Natural Gas				Oil				Natural Gas				Oil
Proved Reserves	Crude Oil		Liquids		Natural Gas		Equivalents		Crude Oil		Liquids		Natural Gas		Equivalents		PV 10 (1)
Category	BBL’s		BBL’s		MCF’s		BOE’s		BBL’s		BBL’s		MCF’s		BOE’s		(before tax)
Proved, Developed		94,100		—		—		94,100		66,810		—		—		66,810		511,740
Proved, Undeveloped		525,100		—		—		525,100		388,980		—		—		388,980		956,800
Total Proved		619,200		—		—		619,200		455,800		—		—		455,800		1,468,540

In 2017 the Company invested approximately $4,600 in its oil and gas properties. These reduced expenditures were in response to extremely low commodity prices. At year end the Company’s review of proved undeveloped reserves revealed challenges but the Company maintains its belief that reserves will be 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 of its proved undeveloped reserves within the five year time frames required; utilizing its balance sheet, to borrow funds as needed and it 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,
	2017		2016
PV10 (before tax)	$	1,468,540	$	3,437,030
Future income taxes, net of 10% discount	$	—	$	—
Standardized measure of discounted future net cash flows	$	1,468,540	$	3,437,030

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. 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.

In conjunction with the anticipated merger, the Company will satisfy its long-term indebtedness with the sale of its assets to the existing lender and anticipates having sufficient liquidity post-merger to satisfy its other liabilities.

The following table summarizes total current assets, total current liabilities and working capital at the year ended December 31, 2017 compared to the year ended December 31, 2016.

	Year Ended			Year Ended
	December 31, 2017			December 31, 2016			Difference
Current Assets	$	1,045,383		$	1,678,967		$	(633,584	)
Current Liabilities	$	6,129,671		$	19,754,406		$	(13,624,789	)
Working Capital (deficit)	$	(5,084,288	)	$	(18,075,439	)	$	12,991,151

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 $19,500,000.

On September 30, 2013, we entered into a Fifth Amendment to the Amended and Restated Credit Agreement. The Fifth Amendment reflects the following changes: it (i) expanded the 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 a borrower party; (iv) added certain collateral and security interests in favor of the Bank; and (v) reduced the 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 Bank (i) re-determined the Borrowing Base based upon the 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 would 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 proceeds 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) suspended certain hedging requirements, and (iii) made certain other amendments to the Credit Agreement.  

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 payments on April 6, 2016 and May 2, 2016. On April 7, 2016, the Company 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 was to be used by the Company to pursue strategic alternatives.

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On April 28, 2016, the Bank informed the Company that it would extend the above Forbearance Agreement period to May 31, 2016 upon effecting a principal reduction of $125,000. In addition, the Company will receive an automatic extension to September 15, 2016 upon meeting certain terms and conditions specified by the Bank. On May 31, 2016, the Company and the Bank amended the Forbearance Agreement to extend the forbearance period to August 31, 2016. On July 29, 2016, the Company and the Bank amended the Forbearance Agreement to extend the forbearance period to October 1, 2016. 

On October 1, 2016, the Company and the Bank could not reach an agreement to extend the Third Amendment to the Forbearance Agreement. Following this outcome, the Company decided to discontinue payment of interest on its outstanding loan obligations with the Bank. The Company continued to evaluate plans to restructure, amend or refinance existing debt through private options.  

On February 10, 2017, the Company, TCB and IberiaBank (collectively, “Sellers”), and PWCM Investment Company IC LLC, and certain financial institutions (collectively, “Buyers”) entered into a Loan Sale Agreement (“LSA”), pursuant to which Sellers sold to Buyers, and Buyers purchased from Sellers, all of Sellers’ right, title and interest in, to and under the Credit Agreement and Loan Documents, in exchange for (i) a cash payment of $5,000,000 (the “Cash Purchase Price”), (ii) a Synthetic Equity Interest equal to 10% of the proceeds, after Buyer’s realization of a 150% return on the Cash Purchase Price within five (5) years of the closing date of the sale, with payment being distributed 65.78947368% to TCB and 34.21052632% to IberiaBank, and (iii) at any time prior to February 10, 2022, Buyer may acquire the interest in clause (ii) above. In connection with the LSA, the Company released Sellers and its successors as holders of the rights under the Credit Agreement and Loan Documents, including Buyers, from any and all claims under the Credit Agreement and Loan Documents. 

Also on February 10, 2017, the Company and its subsidiaries, and successor lender entered into a binding letter agreement dated February 10, 2017, which was subsequently amended on March 30, 2017 (as amended, the “letter agreement”) pursuant to which:

1. the successor lender agreed to forgive our existing secured loan in the approximate principal amount of $17,295,000, and in exchange entered into a secured promissory note (which we refer to as the “restated secured note”) in the original principal amount of $4,500,000.

2. we:

a. conveyed our oil and gas properties and associated performance and surety bonds in Colorado, Texas, and Nebraska;

b. conveyed all of our shares of Oakridge Energy, Inc. (together (a) and (b), the “conveyed oil and gas assets”); and

c. retained our assets in Kansas and continued as a going concern. The Kansas assets currently provide most of our current operating revenue.

The restated secured note:

a. is secured by a first-priority lien in the Company’s oil and gas producing assets situated in the State of Kansas,

b. evidences accrued interest on the $4,500,000 principal balance at a rate of 16% per annum,

c. bears interest from and after May 1, 2017, at a rate of 16.0% per annum,

d. is pre-payable in full at a discount at any time during the term of the restated secured note upon the Company paying $3,300,000 to successor lender, and

e. matures and is due and payable in full on November 1, 2017 (which date has been extended as discussed below).

The Company has extended the restated secured note to March 23, 2018. We have an option to extend the maturity date of the restated secured note to April 30, 2018, upon payment of an extension fee of $50,000.

So long as we repay the $3,300,000 in indebtedness on or prior to the maturity date, as extended, all other amounts payable under the restated secured note are to be forgiven.

The closing occurred on May 10, 2017. As part of the closing procedures and net settlement, we issued a promissory note to Pass Creek Resources LLC in the amount of $105,806. The promissory bears interest at 16% per annum and matured on June 9, 2017. The amount due was not paid on June 9, 2017, but the holder has not provided the Company a notice of default.

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In connection with the May 10, 2017 closing and in consideration of the satisfaction of $13,425,000 of the amount due under the Credit Agreement, as amended, the Company and certain of its subsidiaries transferred to PCR Holdings LLC, an affiliate of the successor lenders under the Credit Agreement, all of the Company’s oil and gas properties and assets located in Colorado, Texas, and Nebraska, as well as the Company’s shares of Oakridge Energy, Inc.

To evidence the Company’s remaining $4,500,000 of indebtedness to PWCM Investment Company IC LLC (“PWCM”), RES Investment Group, LLC (“RES”), Round Rock Development Partners, LP (“Round Rock”), and Cibolo Holdings, LLC (“Cibolo Holdings,” and together with PWCM, RES and Round Rock, “Successor Lenders”), the Company’s subsidiaries (except Kansas Holdings, LLC) entered into a Second Amended and Restated Credit Agreement with Cortland Capital Market Services LLC, as Administrative Agent, and the other financial institutions and banks parties thereto (the “New Credit Agreement”), and a related Amended and Restated Note (the “New Note”), in the amount of $3.3 million as described above. 

Our subsidiaries’ obligations under the credit agreement and note are non-recourse and are secured by a first-priority lien in the Company’s and its subsidiaries’ oil properties and assets located in Kansas. The Company was removed as a borrower under the Credit Agreement, but entered into a Guaranty of Recourse Carveouts, pursuant to which the Company guarantees its subsidiaries’ payment of certain fees and expenses due under the Credit Agreement, and may be liable for certain conduct, such as fraud, bad faith, gross negligence, and waste of the Kansas oil properties or assets.

On December 22, 2017, the Company entered into the First Amendment to the Second Amended and Restated Credit Agreement (the “Amendment) with Pass Creek Resources, LLC (“Pass Creek”) and Cortland Capital Market Services, LLC (“Administration Agent”). The Company, Pass Creek, and Administrative Agent are parties to the Second Amended and Restated Credit Agreement dated May 10, 2017. The Maturity Date of the Loan has been extended to the earlier of (i) February 15, 2018 or April 30, 2018, if (a) the Company provide notice to the Administrative Agent of their intent to extend the maturity date and (b) no later than the first Business Day following delivery of such notice pay a $100,000 extension fee, or (ii) the merger of AgEagle Merger Sub, Inc., a wholly-owned subsidiary of the Company and AgEagle Aerial Systems, Inc. pursuant to the Agreement and Plan of Merger dated as of October 19, 2017. At the closing of First Amendment, Company paid Pass Creek a $65,000 extension fee and $7,500 to the Administrative Agent for additional fees. The Company also paid the Administrative Agent an additional $45,000 upon the filing of a definitive proxy statement by the Company with the Securities and Exchange Commission. The Company also agreed to borrow Improvement Advances in an amount not to exceed $300,000. The Company has extended the restated secured note to March 23, 2018 and has the option to extend the maturity date of the restated secured note to April 30, 2018, upon payment of an extension fee of $50,000.

As of December 31, 2017, the principal balance of $4,457,347 along with accrued interest of $479,452 remained due under the Amended and Restated Credit Agreement. At December 31, 2017, the Company was not in compliance with certain covenants, and the loan may be called due by Pass Creek.

As of December 31, 2017, the principal balance of $80,805 along with accrued interest of $9,616 remained due under the promissory note with Pass Creek Resources LLC.  

On July 14, 2017, July 28, 2017 and August 30, 2017, the Company entered into Secured Promissory Notes totaling $225,000 with Alpha Capital Anstalt, which have a maturity date of June 30, 2018, and accrue interest at a rate of 8% per annum. The amount due under the notes is secured by a security interest, subordinate to certain other security interests of the Company, in substantially all of the Company's assets. The amount due under the notes is convertible into shares of the Company's common stock, at the option of Alpha Capital Anstalt, on identical terms as the outstanding Series C Convertible Preferred Stock (i.e., an initial conversion price of $0.30 per share, a 9.9% ownership limitation and certain anti-dilution rights, which currently result in a conversion price of $0.0612 per share). As of December 31, 2017, the principal balance of $225,000 remained due.

Satisfaction of our cash obligations for the next 12 months

In conjunction with the anticipated merger, the Company will satisfy its long-term indebtedness with the sale of its assets to the existing lender and anticipates having sufficient liquidity post-merger to satisfy its other liabilities.

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

In the event the merger is not consummated, 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 one full-time employee. 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, and general and administrative functions. 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.

 39

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.

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, 2016, impairment charges of $8,032,670 were recorded. For the year ended December 31, 2017, no impairment charges were recorded.

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.

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.

 40

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.

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.

 ITEM 9A. CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

Our Interim Chief Executive Officer, Louis G. Schott, and our Interim Chief Financial Officer, Robert Schleizer, evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Report pursuant to Exchange Act Rule 13a-15(b). Based on the evaluation, Mr. Schott and Mr. Schleizer concluded that our disclosure controls and procedures are not 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 Rules 13a-15(f) and 15d-15(f) of the Exchange Act. 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. 

 41

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 not effective as of December 31, 2017. Such conclusion reflects the termination of our financial reporting staff during 2017. Until we are able to remedy these weaknesses, we are relying on third party consultants to assist with financial reporting.

Changes in Internal Control over Financial Reporting

Effective August 17, 2017, Robert Schleizer was appointed as Interim Chief Financial Officer and principal accounting/financial officer of the Company. He replaced Douglas M. Wright who resigned to pursue other business opportunities.

Other than the above, 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.   

None.

 42

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

Information in response to this item is incorporated by reference from the registrant’s definitive proxy statement for its 2018 Annual Stockholder Meeting of Stockholders filed 120 days after December 31, 2017.

ITEM 11. EXECUTIVE COMPENSATION.

Information in response to this item is incorporated by reference from the registrant’s definitive proxy statement for its 2018 Annual Stockholder Meeting of Stockholders filed 120 days after December 31, 2017.

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

Information in response to this item is incorporated by reference from the registrant’s definitive proxy statement for its 2018 Annual Stockholder Meeting of Stockholders filed 120 days after December 31, 2017.

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

Information in response to this item is incorporated by reference from the registrant’s definitive proxy statement for its 2018 Annual Stockholder Meeting of Stockholders filed 120 days after December 31, 2017.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

Information in response to this item is incorporated by reference from the registrant’s definitive proxy statement for its 2018 Annual Stockholder Meeting of Stockholders filed 120 days after December 31, 2017.

 43

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

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

99. Financial Statements

	Page
Management Responsibility for Financial Information	44
Management’s Report on Internal Control Over Financial Reporting	45
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. (incorporated by reference to Exhibit 2.3 to Form 8-K 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)
2.3	Agreement and Plan of Merger and Reorganization, dated as of October 19, 2017, by and among EnerJex Resources, Inc., AgEagle Merger Sub, Inc., and AgEagle Aerial Systems, Inc. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed with the SEC on October 20, 2017).
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)

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)
3.7	Certificate of Designation of Series C Preferred Stock filed with the Nevada Secretary of State on April 27, 2017 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on April 28, 2018)
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)

 44

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).

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 (incorporated by reference to Exhibit 10.1 to Form 8-K filed June 3, 2016).

 45

10.29	Third Amendment to Forbearance Agreement dated July 29, 2016 (incorporated by reference to Exhibit 10.1 to Form 8-K filed on August 1, 2016.
10.30	Letter Agreement dated February 10, 2017, by and among Texas Capital Bank, N.A., Iberia Bank, PWCM Investment Company IC LLC, EnerJex Resources, Inc., EnerJex Kansas, Inc., Black Sable Energy, LLC, Black Raven Energy, Inc. and Adena, LLC (incorporated by reference to Exhibit 10.1 on Form 8-K filed February 14, 2017).
10.31	Loan Sale Agreement dated February 10, 2017, by and among Texas Capital Bank, N.A., Iberia Bank, PWCM Investment Company IC LLC, EnerJex Resources, Inc., EnerJex Kansas, Inc., Black Sable Energy, LLC, Black Raven Energy, Inc., and Adena, LLC (incorporated by reference to Exhibit 10.2 on Form 8-K filed February 14, 2017).
10.32	Consulting Agreement dated February 10, 2017, by and between Registrant and Douglas Wright (incorporated by reference to Exhibit 10.3 on Form 8-K filed February 14, 2017).
10.33	Employment Agreement dated February 10, 2017, by and between Registrant and Louis G. Schott (incorporated by reference to Exhibit 10.4 on Form 8-K filed February 14, 2017).
10.34	Separation and General Release Agreement dated February 10, 2017, by and between Registrant and Robert G. Watson, Jr. (incorporated by reference to Exhibit 10.34 on Form 10-K filed March 31, 2017).
10.35	Form of Additional Issuance Agreement among Enerjex Resources, Inc. and Alpha Capital Anstalt effective as of April 27, 2017 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 28, 2017).
10.36	Form of Services Agreement among EnerJex Resources, Inc., and Camber Energy, Inc. dated April 27, 2017 (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on April 28, 2017).
10.37	Second Amended and Restated Credit Agreement dated May 10, 2017, by and among the Registrant, EnerJex Kansas, Inc., Black Raven Energy, Inc., Black Sable Energy, LLC, Adena, LLC, Working Interest, LLC, Kansas Holdings, LLC and Cortland Capital Market Services LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on May 12, 2017).
10.38	Amended and Restated Note dated May 10, 2017, by and among the Registrant, EnerJex Kansas, Inc., Black Raven Energy, Inc., Black Sable Energy, LLC, Adena, LLC, Working Interest, LLC, Kansas Holdings, LLC and Cortland Capital Market Services LLC (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on May 12, 2017).
10.39	Guaranty of Recourse Carveouts dated May 10, 2017, by and between the Registrant and Cortland Capital Market Services LLC (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on May 12, 2017).
10.40	Secured Promissory Note dated July 14, 2017, by Registrant and Alpha Capital Anstalt (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on July 20, 2017).
10.41	Voting Agreement, dated as of October 19, 2017, by and among EnerJex Resources, Inc. and a principal stockholder of AgEagle (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the SEC on October 20, 2017).
10.42	Private Placement Commitment Letter Agreement dated November 21, 2017 by and among the Company and Alpha Capital Anstalt (incorporated by reference to Exhibit 10.41 to the Form S-4 Registration Statement filed with the SEC on November 22, 2017).
10.43	Private Placement Agreement dated as of November 21, 2017, by and among EnerJex Resources, Inc. and Alpha Capital Anstalt (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the SEC on November 27, 2017).
10.44	Stock Purchase Agreement dated as of December 20, 2017, by and between EnerJex Resources, Inc. and the Purchaser thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the SEC on December 22, 2017).
10.45	First Amendment to Second Amended and Restated Credit Agreement dated December 22, 2017 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the SEC on December 29, 2017).
10.46	Second Amended and Restated Note December 22, 2017 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the SEC on December 29, 2017).
10.47	Letter Agreement dated January 31, 2018 from EnerJex Resources, Inc. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the SEC on February 6, 2018).
21.1	Subsidiaries*
23.1	Consent of Cobb & Associates, Inc.*
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**
99.1	Cobb & Associates Letter Report dated*
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.

** Furnished herewith.

 46

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/ Louis G. Schott
	Louis G. Schott  Interim Chief Executive Officer  (Principal Executive Officer)
Date: March 23, 2018

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/ Louis G. Schott	Interim Chief Executive Officer,	March 23, 2018
Louis G. Schott	(Principal Executive Officer), Secretary
/s/ Robert Schleizer	Interim Chief Financial Officer	March 23, 2018
Robert Schleizer	(Principal Financial/Accounting Officer)
/s/ Ryan A. Lowe	Director	March 23, 2018
Ryan A. Lowe
/s/ Lance W. Helfert	Director	March 23, 2018
Lance Helfert
/s/ James G. Miller	Director	March 23, 2018
James G. Miller
/s/ Richard E. Menchaca	Director	March 23, 2018
Richard E. Menchaca

 47

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, 2017 and 2016	F-3
Consolidated Statements of Operations for the Years Ended December 31, 2017 and 2016	F-4
Consolidated Statement of Stockholders’ (Deficit) Equity for the Year Ended December 31, 2017 and 2016	F-5
Consolidated Statement of Cash Flows for the Years Ended December 31, 2017 and 2016	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. 

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of EnerJex Resources, Inc. (the “Company”), as of December 31, 2017 and 2016, and the related consolidated statements of operations, stockholders’ deficit and cash flows for each of the two years in the period ended December 31, 2017 and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

The Company's Ability to Continue as a Going Concern

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern. As discussed in Note 2 to the accompanying consolidated financial statements, the Company has suffered recurring losses from operations, generated negative cash flows from operating activities, has an accumulated deficit and has stated that substantial doubt exists about the Company’s ability to continue as a going concern. Management's evaluation of the events and conditions and management’s plans in regarding these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

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 are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of the Company’s internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting, 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.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

//s// RBSM, LLP 

New York, New York

March 23, 2018

We have served as the Company’s auditor since 2014

New York | Washington, DC | California | Nevada 

China | India | Greece 

Member ANTEA INTERNATIONAL with offices worldwide

 F-2

EnerJex Resources, Inc. and Subsidiaries 

Consolidated Balance Sheets

	December 31,
	2017			2016
Assets
Current Assets:
Cash unrestricted	$	677,936		$	128,035
Restricted cash		—			50,000
Accounts receivable		143,799			600,255
Derivative receivable		—			10,570
Inventory		—			185,733
Marketable securities		—			210,990
Deposits and prepaid expenses		223,648			493,384
Total current assets		1,045,383			1,678,967
Non-current assets:
Fixed assets, net of accumulated depreciation of $618,661 and $1,817,711		178,115			2,077,055
Oil & gas properties using full cost accounting, net of accumulated DD&A of $8,597,539 and $15,189,716		1,411,225			3,437,030
Other non-current assets		—			798,809
Total non-current assets		1,589,340			6,312,894
Total assets	$	2,634,723		$	7,991,861
Liabilities and Stockholders’ (Deficit)
Current liabilities:
Accounts payable	$	217,941		$	294,241
Accrued liabilities		1,034,827			1,535,165
Current portion of long term debt		4,876,903			17,925,000
Total current liabilities		6,129,671			19,754,406
Non-Current Liabilities:
Asset retirement obligation		1,611,845			3,314,191
Other long-term liabilities		6,919,579			3,401,149
Total non-current liabilities		8,531,424			6,715,340
Total liabilities		14,661,095			26,469,746
Commitments and Contingencies
Stockholders’ (Deficit):
10% Series A Cumulative Redeemable Perpetual Preferred Stock, $.001 par value, 25,000,000 shares authorized, 1,999,998 and 938,248 shares issued and outstanding, respectively		2,000			938
Series B Convertible Preferred stock, $.001 par value, 1,764 shares authorized, 352 and 1,764 issued and outstanding, respectively		1			2
Series C Convertible Preferred stock, $.001 par value, 500 shares authorized, 300 and 0 issued and outstanding, respectively		1			—
Series C Convertible Preferred stock issuable		200,000			—
Common stock, $0.001 par value, 250,000,000 shares authorized, 16,294,891 and 8,423,936 shares issued and outstanding, respectively		16,295			8,424
Paid in capital		74,185,091			69,090,613
Accumulated deficit		(86,429,760	)		(87,577,862	)
Total stockholders’ (deficit)		(12,026,372	)		(18,477,885	)
Total liabilities and stockholders’ (deficit)	$	2,634,723		$	7,991,861

See Notes to Consolidated Financial Statements.

 F-3

EnerJex Resources, Inc. and Subsidiaries 

Consolidated Statements of Operations

	Year Ended December 31,
	2017			2016
Crude oil revenues	$	1,309,496		$	2,390,024
Natural gas revenues		19,509			71,703
Total revenues		1,329,005			2,461,727
Expenses:
Direct operating costs		1,363,946			2,661,258
Depreciation, depletion and amortization		346,197			413,967
Impairment of oil and gas assets		—			8,032,670
Professional fees		1,390,512			310,471
Salaries		350,863			1,723,789
Administrative expense		545,267			458,375
Total expenses		3,996,785			13,600,530
Loss from operations		(2,667,780	)		(11,138,803	)
Other income (expense):
Interest expense		(1,250,191	)		(1,911,906	)
Gain on loan sale agreement		11,500,124			—
(Loss) on mark to market of derivative contracts		—			(2,531,401	)
Other income		692,879			2,406,340
Total other income (expense)		10,942,812			(2,036,967	)
Income (loss) before provision for income taxes		8,275,032			(13,175,770	)
Provision for income taxes		—			—
Net income (loss)	$	8,275,032		$	(13,175,770	)
Net income (loss)	$	8,275,032		$	(13,175,770	)
Beneficial Conversion on Series C Preferred Stock		(208,500	)		—
Deemed dividend for anti-dilution provision		(3,400,000	)		—
Preferred dividends		(3,518,430	)		(3,010,211	)
Net income (loss) attributable to common stockholders	$	1,148,102		$	(16,185,981	)
Net income (loss) per common share basic	$	0.11		$	(1.92	)
Weighted average shares basic		10,503,070			8,423,936
Net income (loss) per common share diluted	$	0.11		$	(1.92	)
Weighted average shares diluted		10,503,070			8,423,936

See Notes to Consolidated Financial Statements.

 F-4

EnerJex Resources, Inc. and Subsidiaries

Consolidated Statement of Stockholders’ (Deficit)

For the Years Ended December 31, 2017 and 2016

		10% Series A			Series B						Series C										Series C								Total
		Preferred Stock			Preferred Stock						Preferred Stock						Common Stock				Preferred Stock		Paid In			Retained			Stockholders’
	Shares		Amount		Shares			Amount			Shares			Amount			Shares		Amount		Issuable		Capital			Deficit			(Deficit)
Balance, January 1, 2016		938,248	$	938		1,764		$	2			—			$	—		8,423,936	$	8,424	$	—	$	68,848,944		$	(71,391,881	)	$	(2,533,573	)
Stock based compensation		—		—		—			—			—			—			—		—		—		241,669			—			241,669
Preferred stock dividends		—		—		—			—			—			—			—		—		—		—			(3,010,211	)		(3,010,211	)
Net loss for the year		—		—		—			—				—			—		—		—		—		—			(13,175,770	)		(13,175,770	)
Balance, December 31, 2016		938,248		938		1,764			2			—			—			8,423,936		8,424		—		69,090,613			(87,577,862	)		(18,477,885	)
Stock based compensation																								13,690						13,690
Preferred stock dividends																											(3,518,430	)		(3,518,430	)
Common stock issued for anti-dilution provision																		597,461		597				299,403			(300,000	)		—
Warrants exercised																		1,771,428		1,772				529,658						531,430
Sale of series A preferred stock		1,061,750		1,062																				648,729						649,791
Sale of series C preferred stock												300				1								299,999						300,000
Series C preferred stock issuable																						200,000								200,000
Conversion of series B preferred stock						(1,412	)		(1	)								5,502,066		5,502				(5,501	)					—
Beneficial conversion feature																								208,500			(208,500	)		—
Deemed dividend for anti-dilution provision																								3,100,000			(3,100,000	)		—
Net income for the year																											8,275,032			8,275,032
Balance, December 31, 2017		1,999,998	$	2,000		352		$	1			300			$	1		16,294,891	$	16,295	$	200,000	$	74,185,091		$	(86,429,760	)	$	(12,026,372	)

See Notes to Consolidated Financial Statements.

 F-5

EnerJex Resources, Inc. and Subsidiaries 

Consolidated Statements of Cash Flows

For the Years Ended December 31, 2017 and 2016

	Year Ended December 31,
	2017			2016
Cash flows from operating activities
Net income (loss)	$	8,275,032		$	(13,175,770	)
Adjustments to reconcile net income (loss) (used in) operating activities:
Depreciation, depletion and amortization		234,135			413,967
Write-off of inventory		71,982			—
Amortization of deferred financing costs		223,790
Impairment of oil and gas assets		—			8,032,670
Stock, options and warrants issued for services		13,690			241,669
Accretion of asset retirement obligation		112,062			225,480
Settlement of asset retirement obligations		—			(2,767	)
(Gain) loss on derivatives		—			2,520,831
Gain on loan sale agreement, net of cash		(11,500,124	)		—
Changes in current assets and liabilities
Accounts receivable		105,772			377,233
Inventory		(15,943	)		(41,406	)
Deposits and prepaid expenses		252,478			(246,059	)
Accounts payable		(94,783	)		(848,601	)
Accrued liabilities		1,080,420			404,108
Cash flows used in operating activities		(1,241,489	)		(2,098,645	)
Cash flows from investing activities
Purchase of fixed assets		—			(241,683	)
Oil and gas properties additions		(4,632	)		(17,089	)
Increase in restricted cash		—			(50,000	)
Cash flows (used in) investing activities		(4,632	)		(308,772	)
Cash flows from financing activities
Proceeds from sale of stock and warrant exercise		1,681,221			—
Proceeds from borrowings		225,000			—
Repayments of long-term debt		(67,653	)		(686,660	)
Bank account transfer on loan sale agreement		(92,546	)		—
Cash released from restricted cash		50,000			—
Deferred financing costs		—			120,430
Cash flows provided by (used in) financing activities		1,796,022			(566,230	)
(Decrease) increase in cash and cash equivalents		549,901			(2,973,647	)
Cash and cash equivalents, beginning		128,035			3,101,682
Cash and cash equivalents, end	$	677,936		$	128,035
Supplemental disclosures:
Interest paid	$	—		$	922,072
Income taxes paid	$	—		$	—
Non-cash investing and financing activities:
Beneficial conversion feature on Series C preferred stock accounted as preferred dividend	$	208,500			—
Common stock issued for anti-dilution provision	$	597			—
Conversion of Series B preferred stock into common stock	$	5,502			—
Share-based payments issued for services	$	13,690		$	241,669
Payroll liability converted to note payable	$	113,750			—
Non-cash note payable issued in conjunction with the LSA	$	105,806			—
Deemed dividend for anti-dilution provision	$	3,400,000			—
Preferred dividends payable	$	3,518,430		$	3,010,211
Loan settled and exchanged with assets including oil and gas properties and liabilities	$	13,425,000		$	—

See Notes to Consolidated Financial Statements.

 F-6

EnerJex Resources, Inc.

For the Years Ended December 31, 2017 and 2016

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.

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.

 F-7

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, 2017 and 2016. 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, 2017. 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, 2017 are the years ended December 31, 2014, 2015 and 2016. Tax years ending prior to 2014 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, 2017, Fixed Assets consisted of furniture and equipment of $773,707 and building and leasehold improvements of $23,069, as well as accumulated depreciation of furniture and fixtures of $597,692 and accumulated depreciation of building and leasehold improvements of $20,969.

At December 31, 2016, Fixed Assets consisted of vehicles $355,886, furniture and equipment of $795,563, building and leasehold improvements of $23,069 and gathering and compression systems of $2,720,247, as well as accumulated depreciation of vehicles of $336,083, accumulated depreciation of furniture and fixtures of $532,190, accumulated depreciation of building and leasehold improvements of $17,515 and accumulated depreciation of gathering and compression systems of $931,923. 

 F-8

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, 2016 impairment charges of $8,032,670 were recorded. For the year ended December 31, 2017, no impairment charges were recorded.

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.

On February 10, 2017, the Company and the other Sellers entered into and completed the transactions contemplated by the LSA, described in greater detail in “Note 2 – Going Concern” – “Financing Transactions”.

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.

 F-9

Major Purchasers

For the years ended December 31, 2017, and 2016 we sold our produced crude oil to ARM Energy Management, LLC, Coffeyville Resources Inc., 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 at December 31, 2016, the carrying value of this security was $210,990. During 2017 the security was transferred as part of the LSA transaction (described below).

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 and preferred stock 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, 2016, 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.

Reclassifications

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

Recent Accounting Pronouncements Adopted by the Company

In July 2017, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2017-11, “Earnings Per Share (Topic 260); Distinguishing Liabilities from Equity (Topic 480); Derivatives and Hedging (Topic 815): (Part 1) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Non-public Entities and Certain Mandatorily Redeemable Non-controlling Interests with a Scope Exception” (“ASU 2017-11”). Part I relates to the accounting for certain financial instruments with down round features in Subtopic 815-40, which is considered in determining whether an equity-linked financial instrument qualifies for a scope exception from derivative accounting. Down round features are features of certain equity-linked instruments (or embedded features) that result in the strike price being reduced based on the pricing of future equity offerings. An entity still is required to determine whether instruments would be classified as equity under the guidance in Subtopic 815-40 in determining whether they qualify for that scope exception. If they do qualify, freestanding instruments with down round features are no longer classified as liabilities. ASU 2017-11 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. Early adoption is permitted, including in an interim period. The Company early adopted ASU 2017-11 during the year ended December 31, 2017. The Company had no cumulative effect of the change in accounting principle on the Company’s Consolidated Balance Sheets as of the beginning of 2017.

Recent Accounting Pronouncements Applicable to the Company

In May 2014, the FASB issued (ASU) No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which supersedes nearly all existing revenue recognition guidance under GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five- step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing GAAP. The guidance is effective for annual and interim periods beginning after December 15, 2017. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The Company plans to adopt this guidance effective January 1, 2018 using the modified retrospective method applied to contracts that are not completed as of that date. The Company has not identified changes to its revenue recognition policies that would result in a material adjustment to the opening balance of retained earnings on January 1, 2018. Adopting this guidance will result in increased disclosures related to revenue recognition policies and disaggregation of revenue in future disclosures in the Company’s Consolidated Financial Statements. As allowed by the practical expedients under Topic 606, the Company does not plan to provide expanded disclosures with respect to the value of unsatisfied performance obligations for contracts with variable consideration or with an original term of one year or less.

F-10 

In February 2016, the FASB issued ASU 2016-02, a new lease standard requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous U.S. GAAP. The guidance is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company will be required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements. The Company is currently evaluating the impact of adopting this standard on its consolidated financial statements.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230). ASU 2016-15 seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The Company plans to adopt this guidance effective January 1, 2018. The Company has not identified any changes that upon adoption will have a material effect on its cash flows.

In May 2017, the FASB issued ASU 2017-09, “Compensation-Stock Compensation (Topic 718): Scope of Modification Accounting”, which provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. ASU 2017-09 is effective for annual periods beginning after December 15, 2017, with early adoption permitted, including adoption in any interim period for which financial statements have not yet been issued. The Company plans to adopt this guidance effective January 1, 2018. The Company has not identified any changes that upon adoption will have a material effect on its consolidated financial statements.

The FASB issued ASU 2017-05, “Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic: 610-20): Clarifying the Scope of Asset Derecognition Guidance and the Accounting for Partial Sales of Nonfinancial Assets,” which helps filers determine the guidance applicable for gain/loss recognition subsequent to the adoption of ASU 2014-09, Revenue from Contracts with Customers. The amendments also clarify that the derecognition of all businesses except those related to conveyances of oil and gas rights or contracts with customers should be accounted for in accordance with the derecognition and deconsolidation guidance in Topic 810, Consolidation. The Company adopted the ASU on January 1, 2018, using the modified retrospective transition method. Under this transition method the Company may elect to apply this guidance retrospectively either to all contracts at the date of initial application or only to contracts that are not completed contracts at the date of initial application. The Company elected to evaluate only contracts that are not completed contracts. As there were no not completed contracts at January 1, 2018, there was no impact to the Company’s consolidated financial statements and related disclosures upon adoption.

Recent Accounting Pronouncements Not Yet Adopted. The FASB issued ASU 2016-02, “Leases (Topic 842),” which requires companies to recognize the assets and liabilities for the rights and obligations of all leases with a term greater than 12 months (long-term) on the balance sheet. Leases to explore for or use minerals, oil and natural gas are not impacted by this guidance. In January 2018, the FASB issued ASU 2018-01, “Leases (Topic 842), Land Easement Practical Expedient for Transition to Topic 842.” This ASU permits an entity to continue to apply its current accounting policy for land easements that existed before the effective date of Topic 842. Once an entity adopts Topic 842, it would apply that Topic prospectively to all new (or modified) land easements to determine whether the arrangement contains a lease. Topic 842 requires adoption by application of a modified retrospective transition approach and is effective for the Company on January 1, 2019. Early adoption is permitted.

The Company is in the process of reviewing its portfolio of leased assets and related contracts to determine the impact that adoption will have on its consolidated financial statements and related disclosures. The Company is also assessing the impact of Topic 842 on its systems, processes and internal controls. The Company plans to elect certain practical expedients when implementing the new lease standard, which means the Company will not have to reassess the existence or classification of leases for contracts, including land easements that commenced prior to adoption. The Company anticipates upon adoption to recognize assets and liabilities for the rights and obligations of its existing long-term operating leases on its consolidated balance sheets and to utilize new systems, processes and internal controls to properly identify, classify, measure and recognize new (or modified) leases after the date of adoption. The Company will complete its evaluation during 2018 and will adopt Topic 842 on January 1, 2019, using a modified retrospective approach for all comparative periods presented.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. This new standard clarifies the definition of a business and provides a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This new standard will be effective for the Company on January 1, 2018; however, early adoption is permitted with prospective application to any business development transaction.

 F-11

Note 2 - Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates the realization of assets and liquidation of liabilities in the normal course of business. The Company had an accumulated deficit at December 31, 2017 of $86,429,760. Also, cash used in operations was $1,241,489 for the year ended December 31, 2017.  The ability of the Company to continue as a going concern is dependent upon its ability to successfully accomplish the plans described below. The accompanying consolidated financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern.

Merger Agreement

On October 19, 2017, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with AgEagle Aerial Systems, Inc., a Nevada corporation (“AgEagle”), which designs, develops, produces, and distributes technologically advanced small unmanned aerial vehicles (UAV or drones) that are supplied to the agriculture industry, and AgEagle Merger Sub, Inc., a Nevada corporation and wholly-owned subsidiary of the Company (“Merger Sub”). Pursuant to the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will be merged with and into AgEagle, Merger Sub will cease to exist and AgEagle will survive as a wholly-owned subsidiary of the Company (the “Merger”). The respective boards of directors of the Company and AgEagle have approved the Merger Agreement and the transactions contemplated thereby.

At the effective time of the Merger (the “Effective Time”), the shares of AgEagle capital stock will be automatically converted into the right to receive equal to 85% of the then issued and outstanding capital stock of the Company on a fully diluted basis. In addition, at the Effective Time all outstanding options and warrants to purchase shares of AgEagle common stock will be assumed by the Company and converted into options and warrants to purchase shares of Company common stock. No fractional shares of Company common stock will be issued in the Merger but will be rounded to the nearest whole share. Following the consummation of the Merger, former stockholders of AgEagle with respect to the Merger are expected to own 85% of the Company’s outstanding common stock (inclusive of the AgEagle assumed stock options and warrants), and current common and Series A Preferred stockholders of the Company are expected to own 15% of the Company, excluding shares of common stock that may be issued in connection with the conversion of the Company’s Series B Preferred Stock and Series C Preferred Stock, and not including any additional shares which may be issued in connection with the Company’s closing obligation to provide up to $4 million in new working capital and the elimination of all liabilities currently on the Company’s balance sheet.

In connection with the Merger, the Company will also file a proxy statement seeking stockholder approval to: (a) amend the terms of its Series A Preferred Stock (as discussed below); (b) approve the issuance of the Company’s shares in connection with the Merger to the AgEagle shareholders and new investors, in excess of 19.9% of the Company’s total issued and outstanding shares of common stock; (c) approve the issuance of shares to current Company management and directors in lieu of deferred salary and fees, a majority of which will be held in escrow to secure the Company’s indemnity obligations under the Merger Agreement; and (d) change the name of the Company to “AgEagle Aerial Resources, Inc.” 

The Merger Agreement provides that, immediately following the Effective Time, the existing board of directors and officers of the Company will resign and new directors and officers will be appointed by AgEagle.

The Company intends to dispose of its principal assets, consisting primarily of its Kansas oil and gas properties, concurrently with the closing of the Merger. In the event the Merger is not consummated, the Company does not have a present intention to dispose of the above described assets.

The completion of the Merger is subject to various customary conditions, including, among other things: (a) the approval of the stockholders of the Company and AgEagle (which Company shareholder approval has been received to date); (b) the accuracy of the representations and warranties made by each of the Company and AgEagle and the compliance by each of the Company and AgEagle with their respective obligations under the Merger Agreement; (c) approval of the stockholders of the Company for the issuance of its common stock and any other securities (x) to the AgEagle stockholders in connection with the Merger and (y) in connection with the financing transactions contemplated by the Merger Agreement; (d) approval for the listing of shares of the Company’s common stock to be issued in the Merger and other related transactions on the NYSE American; and (e) that all of the Company’s assets as disclosed shall have been sold, transferred or otherwise disposed of and the corresponding debt and liabilities shall have been extinguished. The Company’s existing cash resources are insufficient to satisfy all of its outstanding liabilities. Accordingly, in order to satisfy the condition and consummate the Merger, the Company will be required to raise additional funding prior to the closing of the Merger, the failure of which could result in the Company’s failure to consummate the Merger Agreement.

F-12

The Merger Agreement contains customary representations, warranties and covenants, including covenants obligating each of the Company and AgEagle to continue to conduct its respective business in the ordinary course, to provide reasonable access to each other’s information and to use reasonable best efforts to cooperate and coordinate to make any filings or submissions that are required to be made under any applicable laws or requested to be made by any government authority in connection with the Merger. The Merger Agreement also contains a customary “no solicitation” provision pursuant to which, prior to the earlier of January 31, 2018, or the completion or termination of the Merger, neither the Company nor AgEagle may solicit or engage in discussions with any third party regarding another acquisition proposal unless, in the Company’s case, it has received an unsolicited, bona fide written proposal that the recipient’s board of directors determines is or would reasonably be expected to result in a superior proposal. The Company has paid AgEagle a $50,000 non-refundable fee at the signing of the Merger Agreement. The Merger Agreement contains certain termination rights in favor of each of the Company and AgEagle.

In addition, the Merger Agreement contains provisions for indemnification in the event of any damages suffered by either party as a result of breaches of representations and warranties contained therein. The aggregate maximum indemnification obligation of any indemnifying party for damages with respect to breaches of representations and warranties set forth in the Merger Agreement shall not exceed, in the aggregate, $350,000, other than for fraud, intentional misrepresentation or willful breach. An indemnifying party shall satisfy its indemnification obligations with shares of Company common stock equal to the aggregate amount of losses of the indemnified party, calculated based upon the greater of (i) the value of the Company common stock as of the closing of the Merger; and (ii) the average closing price of the Company common stock on the NYSE American for the five trading days immediately prior to the date such a claim is made. The Company has agreed to deposit an aggregate of 1,215,278 shares of common stock to be issued to current officers and directors of the Company in lieu of deferred salary and fees into escrow to secure its indemnification obligations, the issuance of such shares requiring the approval of the Company’s common stockholders.

In connection with, and as a condition to the closing of the Merger, the Company is seeking the consent of the holder of its Series A Preferred Stock (“Series A Preferred Stock”) to amend the terms thereof to: (i) allow the Company to pay all accrued but unpaid dividends up to September 30, 2017 in additional shares of Series A Preferred Stock based on the value of the liquidation preference thereof, (ii) eliminate the right of the Series A Preferred Stock holders to receive any dividends accruing after September 30, 2017, and (iii) convert each share of Series A Preferred Stock into 10 shares of Company common stock. An affirmative vote of 66.7% of all shares of Series A Preferred Stock voting as a class as of the record date of the proxy statement is required to amend the terms of the Certificate of Designation to provide for these changes, as required under the Merger Agreement. As of September 30, 2017, the Series A Preferred Stock had accrued a total of $6,039,972 in accrued but unpaid dividends, which would result in an additional 241,599 shares of Series A Preferred Stock being issued by the Company to satisfy these accrued dividends.

The Merger Agreement provides either party the right to terminate the Merger if it has not been consummated by January 31, 2018, provided that if all of the conditions to closing shall have been satisfied or shall be capable of being satisfied at such time, the required closing date may be extended until March 31, 2018. On January 31, 2018, the Company extended the required closing date with AgEagle to March 31, 2018.

On November 21, 2017, Alpha Capital Anstalt (“Alpha”) signed a binding commitment letter with the Company to provide prior to or at the closing of the Merger, a minimum of $4 million in new equity capital at a pre-money valuation of between $16 million and $25 million (the “Private Placement”). Per the terms of this commitment letter, in the event any unaffiliated third parties of EnerJex participate in the Private Placement, Alpha’s obligations to fund the Private Placement shall be reduced by such aggregate gross dollar amount funded by such unaffiliated third parties. Alpha has also agreed to convert all notes they hold from the Company into equity at the closing of the Merger. For their funding commitment, Alpha will receive a fee equal to 2.5% of the Company’s outstanding common stock on a fully diluted basis payable at the closing of the Merger. Alpha’s obligations to fund the Private Placement shall terminate on the earlier to occur of (i) the consummation of the Merger, and (ii) March 31, 2018. The Company further agreed that, at no time from the date hereof until the consummation of the Merger, shall it provide or disclose to Alpha any “material non-public information” regarding itself, without the prior consent of Alpha. The funding of the Private Placement is subject to standard conditions such as accuracy of representations and warranties provided in the Merger Agreement, and other similar conditions.

Financing Transactions

On February 10, 2017, the Company, TCB and IberiaBank (collectively, “Sellers”), and PWCM Investment Company IC LLC, and certain financial institutions (collectively, “Buyers”) entered into a Loan Sale Agreement (“LSA”), pursuant to which Sellers sold to Buyers, and Buyers purchased from Sellers, all of Sellers’ right, title and interest in, to and under the Credit Agreement and Loan Documents, in exchange for (i) a cash payment of $5,000,000 (the “Cash Purchase Price”), (ii) a Synthetic Equity Interest equal to 10% of the proceeds, after Buyer’s realization of a 150% return on the Cash Purchase Price within five (5) years of the closing date of the sale, with payment being distributed 65.78947368% to TCB and 34.21052632% to IberiaBank, and (iii) at any time prior to February 10, 2022, Buyer may acquire the interest in clause (ii) above. In connection with the LSA, the Company released Sellers and its successors as holders of the rights under the Credit Agreement and Loan Documents, including Buyers, from any and all claims under the Credit Agreement and Loan Documents. 

 F-13

Also on February 10, 2017, the Company and its subsidiaries, and successor lender entered into a binding letter agreement dated February 10, 2017, which was subsequently amended on March 30, 2017 (as amended, the “letter agreement”) pursuant to which:

1. the successor lender agreed to forgive our existing secured loan in the approximate principal amount of $17,295,000, and in exchange entered into a secured promissory note (which we refer to as the “restated secured note”) in the original principal amount of $4,500,000.

2. we:

a. conveyed our oil and gas properties and associated performance and surety bonds in Colorado, Texas, and Nebraska;

b. conveyed all of our shares of Oakridge Energy, Inc. (together, the “conveyed oil and gas assets”); and

c. retained our assets in Kansas and continued as a going concern. The Kansas assets currently provide most of our current operating revenue.

The restated secured note:

a. is secured by a first-priority lien in the Company’s oil and gas producing assets situated in the State of Kansas,

b. evidences accrued interest on the $4,500,000 principal balance at a rate of 16% per annum,

c. bears interest from and after May 1, 2017, at a rate of 16.0% per annum,

d. is pre-payable in full at a discount at any time during the term of the restated secured note upon EnerJex paying $3,300,000 to successor lender, and

e. matures and is due and payable in full on November 1, 2017 (subject to the extension right described below).

The Company has extended the restated secured note to March 23, 2018. We have an option to extend the maturity date of the restated secured note to April 30, 2018, upon payment of an extension fee of $50,000.

So long as we repay the $3,300,000 in indebtedness on or prior to the maturity date, as extended, all other amounts payable under the restated secured note are to be forgiven.

The closing occurred on May 10, 2017. As part of the closing procedures and net settlement, we issued a promissory note to Pass Creek Resources LLC in the amount of $105,806. The promissory bears interest at 16% per annum and matured on June 9, 2017. The amount due was not paid on June 9, 2017, but the holder has not provided the Company a notice of default.

In connection with the May 10, 2017 closing and in consideration of the satisfaction of $13,425,000 of the amount due under the Credit Agreement, as amended, the Company and certain of its subsidiaries transferred to PCR Holdings LLC, an affiliate of the successor lenders under the Credit Agreement, all of the Company’s oil and gas properties and assets located in Colorado, Texas, and Nebraska, as well as the Company’s shares of Oakridge Energy, Inc.

To evidence the Company’s remaining $4,500,000 of indebtedness to PWCM Investment Company IC LLC (“PWCM”), RES Investment Group, LLC (“RES”), Round Rock Development Partners, LP (“Round Rock”), and Cibolo Holdings, LLC (“Cibolo Holdings,” and together with PWCM, RES and Round Rock, “Successor Lenders”), the Company’s subsidiaries (except Kansas Holdings, LLC) entered into a Second Amended and Restated Credit Agreement with Cortland Capital Market Services LLC, as Administrative Agent, and the other financial institutions and banks parties thereto (the “New Credit Agreement”), and a related Amended and Restated Note (the “New Note”), in the amount of $3.3 million as described above.

Our subsidiaries’ obligations under the credit agreement and note are non-recourse and are secured by a first-priority lien in the Company’s and its subsidiaries’ oil properties and assets located in Kansas. The Company was removed as a borrower under the Credit Agreement, but entered into a Guaranty of Recourse Carveouts, pursuant to which the Company guarantees its subsidiaries’ payment of certain fees and expenses due under the Credit Agreement, and may be liable for certain conduct, such as fraud, bad faith, gross negligence, and waste of the Kansas oil properties or assets.

 F-14

On December 22, 2017, the Company entered into the First Amendment to the Second Amended and Restated Credit Agreement (the “Amendment) with Pass Creek Resources, LLC (“Pass Creek”) and Cortland Capital Market Services, LLC (“Administration Agent”). The Company, Pass Creek, and Administrative Agent are parties to the Second Amended and Restated Credit Agreement dated May 10, 2017. The Maturity Date of the Loan has been extended to the earlier of (i) February 15, 2018 or April 30, 2018, if (a) the Company provide notice to the Administrative Agent of their intent to extend the maturity date and (b) no later than the first Business Day following delivery of such notice pay a $100,000 extension fee, or (ii) the merger of AgEagle Merger Sub, Inc., a wholly-owned subsidiary of the Company and AgEagle Aerial Systems, Inc. pursuant to the Agreement and Plan of Merger dated as of October 19, 2017. At the closing of the First Amendment, the Company paid Pass Creek a $65,000 extension fee and $7,500 to the Administrative Agent for additional fees. The Company also paid the Administrative Agent an additional $45,000 upon the filing of a definitive proxy statement by the Company with the Securities and Exchange Commission. The Company also agreed to borrow Improvement Advances in an amount not to exceed $300,000. The Company has extended the restated secured note to March 23, 2018 and has the option to extend the maturity date of the restated secured note to April 30, 2018, upon payment of an extension fee of $50,000.

These conditions raise substantial doubt about the Company’s ability to continue as a going concern for the next twelve months following the issuance of these financial statements. The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. Accordingly, the financial statements do not include any adjustments relating to the recoverability of assets and classification of liabilities that might be necessary should the Company be unable to continue as a going concern.

Note 3 - Equity Transactions

Stock transactions in the fiscal year ended December 31, 2017

We accrued dividends of $3,518,430 for our Series A Preferred Stock for the year ended December 31 2017. At December 31, 2017, aggregate accumulated dividends payable to the Series A Preferred Stock holders totaled $6,919,579.

On April 27, 2017, the Company entered into an Additional Issuance Agreement with Alpha Capital Anstalt, for the purchase of 300 restricted shares of its newly designated Series C Convertible Preferred Stock in consideration for $300,000, with an option to purchase an additional 200 shares of Series C Convertible Preferred Stock for an aggregate purchase price of $200,000. As of December 31, 2017, the Company had issued 300 shares of Series C Convertible Preferred Stock for an aggregate purchase price of $300,000. In addition, during the year ending December 31, 2017, the Company had received $200,000 from Alpha Capital Anstalt to purchase an additional 200 shares of Series C Convertible Preferred Stock. As of December 31, 2017, the additional 200 shares of Series C Convertible Preferred Stock have not been issued and are reflected as Series C Convertible Preferred Stock Issuable on the balance sheet in the aggregate amount of $200,000.

The Company recorded a beneficial conversion feature of $208,500 based on the fair value of the common stock and the conversion rate as of the date of issuance. This amount was recorded as a deemed distribution for the year ended December 31, 2017.

The Series C Convertible Preferred Stock (“Series C Preferred Stock”) is non-voting (except to the extent required by law and except for certain consent rights relating to amending the certificate of incorporation or bylaws, and the like), ranks senior to the common stock with respect to dividends and with respect to distributions upon a deemed dissolution, liquidation or winding-up of the Company, and ranks junior to the Company’s Series A preferred stock and Series B preferred stock with respect to dividends and with respect to distributions upon a deemed dissolution, liquidation or winding-up of the Company. Upon request of the holders, the Company can seek stockholder approval to remove the Issuance Limitation described therein and to allow for further adjustments related to anti-dilution protection, only if such stockholder approval is obtained. The Series C Convertible Preferred Stock has a liquidation preference of $1,000 per share, and is convertible at the option of the holder at a conversion price equal to $0.30 per share, or a ratio equal to approximately 3,333 shares of common stock for each one (1) share of Series C Convertible Preferred Stock, subject to customary adjustments. Dividends are payable on the shares of Series C Convertible Preferred Stock only if and to the extent that dividends are payable on the common stock into which the Series C Convertible Preferred Stock is convertible. The Series C Convertible 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 for the redemption price of $1,000 per share, as adjustable as provided in the designation of the Series C Preferred Stock.

The Series C Preferred Stock includes a beneficial ownership limitation preventing conversion of shares of Series C Preferred Stock into more than 9.99% of the number of shares of common stock outstanding immediately after giving effect to the issuance of shares of common stock upon conversion of the Series C Preferred Stock. In addition, the Company may not convert the Series C Preferred Stock into a number of shares of common stock which, when aggregated with any shares of common stock issued on or after the original issue date and prior to such conversion date in connection with any conversion of Series C Preferred Stock would exceed 1,683,944 shares of common stock (19.99% of the outstanding shares as of the original issue date), subject to adjustment for forward and reverse stock splits, recapitalizations and the like. In the event conversion of the Series C Preferred Stock is limited pursuant to these provisions, each holder shall be entitled to a pro rata portion of the issuable maximum.

Pursuant to the anti-dilutive provisions of the Securities Purchase Agreement dated as of March 11, 2015, which requires the Company to issue additional shares of common stock to adjust the purchase price paid by purchasers in the Company’s March 2015 offering, in the event any shares are sold (or convertible securities are sold), with a price per share less than the purchase price paid by the March 2015 purchasers subject to the terms of the Securities Purchase Agreement, Alpha Capital Anstalt received 597,461 shares of common stock, which the Company recorded as a $300,000 deemed distribution In addition, the Series B Convertible Preferred Stock conversion ratio equal to approximately 571 shares of common stock for each one (1) share of Preferred Stock reset to approximately 3,333 shares of common stock for each one (1) share of Series B Convertible Preferred Stock, to be consistent with the terms of the Series C Convertible Preferred Stock, pursuant to the anti-dilution requirements of the Series B Convertible Preferred Stock. The Company recorded a deemed distribution of $2,500,000 related to the down round triggering event of the Series B Convertible Preferred Stock. In addition, the warrants strike price of $2.75 reset to $0.30, to be consistent with the terms of the Series C Convertible Preferred Stock, pursuant to the anti-dilution requirements of the warrants. The Company recorded a deemed distribution of $500,000 related to the down round triggering event of the warrants.

 F-15

During, 2017, Alpha Capital Anstalt converted 1,412 shares of Series B Convertible Preferred Stock into 5,502,066 shares of common stock.

On October 23, 2017, Alpha Capital Anstalt exercised warrants to purchase 1,000,000 shares of our common stock for an aggregate exercise price of $300,000 (or $0.30 per share), pursuant to the terms of such warrants, and was issued 1,000,000 shares of common stock.

On November 6, 2017, Alpha Capital Anstalt exercised warrants to purchase 771,428 shares of our common stock for an aggregate exercise price of $231,429 (or $0.30 per share), pursuant to the terms of such warrants, and was issued 771,428 shares of common stock.

On December 20, 2017 the Company entered into a Stock Purchase Agreement for the sale of 1,061,750 shares of its Series A Preferred Stock. The Preferred Stock was sold to Alpha Capital Anstalt at $0.0612 per share or an aggregate of $649,791. Pursuant to the anti-dilutive provisions of the Series B Preferred Stock, the Series C Preferred Stock and the warrants, the conversion and strike price reset from $0.30 to $0.612. The Company recorded a deemed distribution of $100,000 related to the down round triggering event of the Series B Preferred Stock, the Series C Preferred Stock and the warrants, in the aggregate.

On February 13, 2018, the Company issued Alpha Capital Anstalt the 200,000 shares of Series C Convertible Preferred Stock which it was due pursuant to the terms of the April 27, 2017, Additional Issuance Agreement, in consideration for the $200,000 paid during the year ended December 31, 2017.

Subsequent to December 31, 2017, Alpha Capital Anstalt converted (a) 343.671 shares of Series B Convertible Preferred Stock into 5,610,955 shares of common stock; and (b) 103.142 shares of Series C Convertible Preferred Stock into 1,683,944 shares of common stock, pursuant to the terms of such securities.

Stock transactions in fiscal year ended December 31, 2016

There were no equity transactions for the year ended December 31, 2016.

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.

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 2017 and 2016, no options were granted to any employees or directors.

We expensed $13,690 and $241,669 for the years ended December 31, 2017 and December 31, 2016 respectively for options granted.

 F-16

A summary of stock options is as follows:

				Weighted Ave.						Weighted Ave.
	Options			Exercise Price			Warrants			Exercise Price
Outstanding January 1, 2016		288,331		$	10.17			1,904,286		$	2.75
Granted		—			—			—			—
Cancelled		(80,667	)		(7.15	)		—			—
Exercised		—			—			—			—
Outstanding December 31, 2016		207,664		$	9.69			1,904,286		$	2.75
Granted		—			—			—			—
Cancelled		—			—			—			—
Exercised		(192,332	)		(10.5	)		(1,771,428	)		0.30
Outstanding December 31, 2017		15,332		$	7.63			132,858		$	0.30

The number of options that were vested at December 31, 2017 was 15,332. The were no options that were not vested at December 31, 2017.

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, 2016	$	3,091,478
Liabilities incurred during the period		—
Liabilities settled during the year		(2,767	)
Accretion		225,480
Asset retirement obligations, December 31, 2016	$	3,314,191
Release of liabilities		(1,814,408	)
Liabilities incurred during the period		—
Liabilities settled during the year		—
Accretion		112,062
Asset retirement obligations, December 31, 2017	$	1,611,845

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 (collectively, “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 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 Amended and Restated 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.

 F-17

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, we entered into a Fifth Amendment to the Amended and Restated Credit Agreement. The Fifth Amendment reflects the following changes it: (i) expanded the 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 a borrower party; (iv) added certain collateral and security interests in favor of the Bank; and (v) reduced the 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 Bank (i) re-determined the Borrowing Base based upon the 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 would 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 an 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) suspended certain hedging requirements, and (iii) made certain other amendments to the Credit Agreement.

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 payments on April 6, 2016 and May 2, 2016. On April 7, 2016, the Company 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 was to be used by the Company to pursue strategic alternatives.

On April 28, 2016 the Bank informed the Company that it would extend the above Forbearance Agreement period to May 31, 2016 upon effecting a principal reduction of $125,000. In addition, the Company will receive an automatic extension to September 15, 2016 upon meeting certain terms and conditions specified by the Bank. On May 31, 2016, the Company and the Bank amended the Forbearance Agreement to extend the forbearance period to August 31, 2016. On July 29, 2016, the Company and the Bank amended the Forbearance Agreement to extend the forbearance period to October 1, 2016. 

 F-18

On October 1, 2016, the Company and the Bank could not reach an agreement to extend the Third Amendment to the Forbearance Agreement. Following this outcome, the Company decided to discontinue payment of interest on its outstanding loan obligations with the Bank. The Company continued to evaluate plans to restructure, amend or refinance existing debt through private options.

On February 10, 2017, the Company and the other Sellers entered into and completed the transactions contemplated by the LSA, described in greater detail in “Note 2 – Going Concern” – “Financing Transactions”.

Below is a table showing the reconciliation of the gain on LSA as set forth on the statement of operations for the year ended December 31, 2017:

Forgiveness of existing secured loan	$	17,925,000
Forgiveness of accrued interest		1,306,801
Issuance of secured promissory note		(4,500,000	)
Transfer of oil and gas properties		(1,902,726	)
Transfer of gas gathering system		(1,772,588	)
Transfer of shares of Oakridge Energy, Inc.		(210,990	)
Transfer of ARO liability		1,814,407
Transfer of other assets		(1,159,780	)
Gain on LSA	$	11,500,124

To evidence the Company’s remaining $4,500,000 of indebtedness to PWCM Investment Company IC LLC (“PWCM”), RES Investment Group, LLC (“RES”), Round Rock Development Partners, LP (“Round Rock”), and Cibolo Holdings, LLC (“Cibolo Holdings,” and together with PWCM, RES and Round Rock, “Successor Lenders”), the Company’s subsidiaries (except Kansas Holdings, LLC) entered into a Second Amended and Restated Credit Agreement with Cortland Capital Market Services LLC, as Administrative Agent, and the other financial institutions and banks parties thereto (the “New Credit Agreement”), and a related Amended and Restated Note (the “New Note”), in the amount of $3.3 million as described above under “Note 2 – Going Concern” – “Financing Transactions”.  

Our subsidiaries’ obligations under the credit agreement and note are non-recourse and are secured by a first-priority lien in the Company’s and the subsidiaries’ oil properties and assets located in Kansas. The Company was removed as a borrower under the Credit Agreement, but entered into a Guaranty of Recourse Carveouts, pursuant to which the Company guarantees the Subsidiaries’ payment of certain fees and expenses due under the Credit Agreement, and may be liable for certain conduct, such as fraud, bad faith, gross negligence, and waste of the Kansas oil properties or assets.

December 22, 2017, the Company entered into the First Amendment to the Second Amended and Restated Credit Agreement (the “Amendment) with Pass Creek Resources, LLC (“Pass Creek”) and Cortland Capital Market Services, LLC (“Administration Agent”). The Company, Pass Creek, and Administrative Agent are parties to the Second Amended and Restated Credit Agreement dated May 10, 2017. The Maturity Date of the Loan has been extended to the earlier of (i) February 15, 2018 or April 30, 2018, if (a) the Company provides notice to the Administrative Agent of their intent to extend the maturity date and (b) no later than the first Business Day following delivery of such notice pay a $100,000 extension fee, or (ii) the merger of AgEagle Merger Sub, Inc., a wholly-owned subsidiary of the Company and AgEagle Aerial Systems, Inc. pursuant to the Agreement and Plan of Merger dated as of October 19, 2017. At the closing of First Amendment, the Company paid Pass Creek a $65,000 extension fee and $7,500 to the Administrative Agent for additional fees. The Company also paid the Administrative Agent an additional $45,000 upon the filing of a definitive proxy statement by the Company with the Securities and Exchange Commission. The Company also agreed to borrow Improvement Advances in an amount not to exceed $300,000. The Company has extended the restated secured note to March 23, 2018 and has the option to extend the maturity date of the restated secured note to April 30, 2018, upon payment of an extension fee of $50,000.

As of December 31, 2017, the principal balance of $4,457,347 along with accrued interest of $479,452 remained due under the Amended and Restated Credit Agreement. At December 31, 2017, the Company was not in compliance with certain covenants, and the loan may be called due by Pass Creek. The note is in default.

As of December 31, 2017, the principal balance of $80,805 along with accrued interest of $9,616 remained due under the promissory note with Pass Creek Resources LLC. The note is in default.

On July 14, 2017, July 28, 2017 and August 30, 2017, the Company entered into Secured Promissory Notes totaling $225,000 with Alpha Capital Anstalt, which have a maturity date of June 30, 2018, and accrue interest at a rate of 8% per annum. The amount due under the notes is secured by a security interest, subordinate to certain other security interests of the Company, in substantially all of the Company's assets. The amount due under the notes is convertible into shares of the Company's common stock, at the option of Alpha Capital Anstalt, on identical terms as the outstanding Series C Convertible Preferred Stock (i.e., an initial conversion price of $0.30 per share, a 9.9% ownership limitation and certain anti-dilution rights, which currently result in a conversion price of $0.0612 per share). As of December 31, 2017, the principal balance of $225,000 remained due.

As of December 31, 2017, the principal balance of $113,750 along with accrued interest of $5,574, remained due under the promissory note with Robert Watson, the former CEO. The note is in default.

Note 6 - Commitments and Contingencies

Rent expense for the years ended December 31, 2017 and 2016 was approximately $69,000 and $148,000, respectively. Future non-cancellable minimum lease payments are approximately, $10,000 for 2018.

 F-19

As of December 31, 2017, 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.

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 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, 2017, we have no reserve for environmental remediation and are not aware of any environmental claims.

On September 23, 2016, the Company, American Standard Energy Corporation, Baylor Operating LLC, Bernard Given and Loeb & Loeb LLP were sued by Geronimo Holdings Corporation and Randal Capps in the 143rd Judicial District Court located in Pecos, Texas. The suit among other things, seeks damages for an alleged unlawful sale of properties in Crockett County Texas and for alleged unpaid royalties. The Company believes the suit is without merit and will vigorously defend itself. The Company has faith that it will prevail and at December 31, 2017 no reserve for potential losses arising from this matter has been recorded. Additionally under its agreement with Baylor Operating LLC, Baylor has agreed to indemnify and defend the Company against all lawsuits and claims including this one.

On April 26, 2016, C&F Ranch, LLC sued the Company in Allen County Kansas for alleged breach of contract related to the rental of certain lands located on the C&F Ranch. During the first quarter of 2018, the Company settled this dispute for $9,000.

Note 7 - Income Taxes

There was no current or deferred income tax expense (benefit) for the years ended December 31, 2017 and December 31, 2016.

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

	Year Ended December 31,
	2017			2016
Statutory tax rate		35.00	%		35.00	%
State tax rate, net of federal tax		2.01	%		1.78	%
Other permanent items		0.00	%		0.00	%
Change in valuation allowance		(37.01	)%		(36.78	)%
Effective tax rate		0.00	%		0.00	%

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

	Year Ended December 31,
	2017			2016
Non-current deferred tax asset:
Oil and gas costs and long-lived assets	$	4,764,420		$	11,500,697
Derivative instruments		—			—
Net operating loss carry-forward		21,547,347			35,815,113
Valuation allowance		(26,311,767	)		(47,315,809	)
Net deferred tax asset (liability)	$	—		$	—

On December 22, 2017, the Tax Cuts and Jobs Act (TCJA) was signed into law. The TCJA, among other things, includes the reduction of the federal tax rate for corporations from 35% to 21% and changes or limits certain tax deductions including the utilization of net operating losses. Under generally accepted accounting principles, the Company is required to revalue its deferred tax assets and liabilities during the period in which the new tax legislation is enacted. The impact of TCJA resulted in a decrease in the Company's deferred tax assets in the amount of $18 million. However, there is no impact of the revaluation to the current net income because it was fully offset by the release of the valuation allowance that was previously recorded against the deferred tax asset.

At December 31, 2017, we have a net operating loss carry forward of approximately $93 million expiring in 2021-2038 that is subject to certain limitations on an annual basis. Such limitation has not been determined, by Management. Management has determined that a 100% valuation allowance be established against net operating losses where it is more likely than not that such losses will expire or will not be available before they are utilized.

The Company incurred a change of control as defined by the Internal Revenue Code (IRC 382). 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. No assurance can be made, as to the availability of the net operating losses based upon Internal Revenue Code (IRC 382), as described, and such amounts of net operating losses available, based upon the limitations described. If there was or is other changes of ownership, the net operating losses may be a totally unavailable to offset taxable income.

Internal Revenue Code (IRC 108), Income from discharge of indebtedness has rules to determine amounts that are required to be included or excluded from taxable income, based upon certain circumstances. Management has determined that any discharge of indebtedness that has occurred is included in taxable income for this period, but is reviewing such amounts, as it applied to IRC 108.

 F-20

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, 2017.

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.

At December 31, 2016, our marketable securities had a value of $210,990. During 2017, as part of the LSA transaction described in “Note 2 – Going Concern” – “Financing Transactions”, we transferred the marketable securities. At December 31, 2017, we held no assets valued at Level 3.   

Note 9 - Derivative Instruments

We enter into 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, allowed 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 had 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 were not required to post additional collateral, including cash.

At December 31, 2017 all derivative contracts had expired and we did not enter into any derivative contracts during 2017. 

We recorded a loss related to the mark to market of our derivative contracts for the year ended December 31, 2016 of $2,531,401. No gain or loss was recorded in 2017. 

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.

 F-21

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, 2017, which were based on a West Texas Intermediate oil price of $51.34 per Bbl and a Henry Hub natural gas price of $2.97 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, 2017, was based on a West Texas Intermediate oil price of $42.46 per Bbl and a Henry Hub natural gas price of $2.63 per MMBtu (adjusted for basis and quality differentials), respectively. The twelve-month, unweighted-average first-day-of-the –month price as of June 30, 2017 was $42.46 per Bbl and $2.63per MMBtu The twelve-month, unweighted-average first-day-of-the –month price as of March 31, 2017 was $45.16 per Bbl and $2.40 per MMBtu (adjusted for basis and quality differentials), respectively. Utilizing these prices, the calculated ceiling amount was greater than the net capitalized cost of oil and natural gas properties as of December 31, 2017, and as a result, no write down was recorded. For the year ended December 31, 2016, the Company recorded an impairment charge of $8,032,670. 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, 2017 and December 31, 2016:

	Year ended December 31, 2017			Year ended December 31, 2016
Realized gain (loss) clearing of derivative contracts	$	—		$	2,382,184
Service Agreement with Camber Energy, Inc.		696,774			—
Miscellaneous income		72			24,124
Interest income		(3,967	)		32
Other income (loss)	$	692,879		$	2,406,340

On April 27, 2017, the Company entered into a Services Agreement (“Service Agreement”) with Camber Energy, Inc., to perform certain outsourced interim services for $150,000 per month. Effective December 4, 2017, the Company and Camber Energy, Inc. (“Camber”), mutually agreed to terminate the agreement between the parties effective November 30, 2017.

Note 13 - Subsequent Events

 On January 31, 2018, the Company extended the end date of its previously disclosed Agreement and Plan of with AgEagle Aerial Systems, Inc., a Nevada corporation (“AgEagle”) to March 31, 2018.

On February 20, 2018, the Company announced that it set the record date for the special meeting of its shareholders to, among other things, consider and vote on various proposals necessary to close the previously announced Agreement and Plan of Merger, dated October 19, 2017 (the “Merger Agreement”), with AgEagle Aerial Systems, Inc. Shareholders of record as of the close of business on February 20, 2018, will be entitled to vote at the special meeting on March 21, 2018. The Merger is subject to certain customary closing conditions and approval from our shareholders. The Merger is expected to close in the first quarter of 2018. 

As previously reported, on April 27, 2017, the Company entered into an Additional Issuance Agreement with Alpha Capital Anstalt, for the purchase of 300 restricted shares of the Company’s then newly designated Series C Convertible Preferred Stock in consideration for $300,000, with an option to purchase an additional 200 shares of Series C Convertible Preferred Stock for an aggregate purchase price of $200,000. As of December 31, 2017, the Company had issued 300 shares of Series C Convertible Preferred Stock for an aggregate purchase price of $300,000. In addition, during the year ended December 31, 2017, the Company had received $200,000 from Alpha Capital Anstalt to purchase an additional 200 shares of Series C Convertible Preferred Stock, which shares had not been issued as of December 31, 2017, and which are reflected as Series C Convertible Preferred Stock Issuable on the balance sheet as of December 31, 2017, in the aggregate amount of $200,000.

On February 13, 2018, the Company issued Alpha Capital Anstalt the 200,000 shares of Series C Convertible Preferred Stock which it was due pursuant to the terms of the April 27, 2017, Additional Issuance Agreement, in consideration for the $200,000 paid during the year ended December 31, 2017.

Subsequent to December 31, 2017, Alpha Capital Anstalt converted (a) 343.671 shares of Series B Convertible Preferred Stock into 5,610,955 shares of common stock; and (b) 103.142 shares of Series C Convertible Preferred Stock into 1,683,944 shares of common stock, pursuant to the terms of such securities.

At a special meeting of shareholders held on March 21, 2018, the Company’s shareholders approved (a) the issuance of the Company’s common stock to the shareholders of AgEagle in connection with and pursuant to the terms of the Merger Agreement in accordance with NYSE American Rules 712 and 713; (b) an amendment to the Company’s Articles of Incorporation to amend the 10% Series A Cumulative Redeemable Perpetual Preferred Stock to: (i) allow the Company to pay all accrued but unpaid dividends up to September 30, 2017 in additional shares of Series A Preferred Stock based on the value of the liquidation preference thereof, (ii) eliminate the right of the Series A Preferred Stock holders to receive any dividends accruing after September 30, 2017, (iii) convert each share of Series A Preferred Stock into 10 shares of common stock (subject to adjustment for a reverse stock split (discussed below)), and (iv) increase the number of Series A Preferred shares by 241,599 shares; (c) an amendment to the Company’s Articles of Incorporation to change the name of the Company to “AgEagle Aerial Systems, Inc.”; (d) the adoption of the EnerJex 2017 Omnibus Equity Incentive Plan (the “Plan”); (e) the issuance of 2,248,264 shares of common stock to current officers and directors in lieu of deferred salary and fees, a majority of which will be held in escrow to secure the Company’s obligations under the Merger Agreement; (f) the conversion of the Company’s Series C Convertible Preferred Stock into shares of common stock in order to comply with the listing rules of the NYSE American; (g) the conversion of the Company’s 10% Series A Cumulative Redeemable Perpetual Preferred Stock into shares of common stock in order to comply with the listing rules of the NYSE American; (h) the issuance of shares of the Company’s common stock, conversion of the Company’s Series C Preferred Stock and conversion of $425,000 owed under five promissory notes held by, Alpha Capital Anstalt, of which $200,000 of the notes have previously been converted into Series C Preferred Stock as of the date of this filing, into shares of common stock in order to comply with the listing rules of the NYSE American.

The Plan provides for the grant of up to 2,000,000 shares of common stock (such number based on a post-reverse split amount) as awards which may include incentive stock options (“ISOs”), non-qualified stock options (“NQSOs”), unrestricted shares, restricted shares, restricted stock units, performance stock, performance units, SARs, tandem stock appreciation rights, distribution equivalent rights, or any combination of the foregoing, to key management employees, non-employee directors, and non-employee consultants of the Company or any of its subsidiaries (however, solely Company employees or employees of the Company’s subsidiaries are eligible for incentive stock option awards).

Additionally, the Company plans to conduct a 1-for-25 reverse stock split of the Company’s outstanding common stock, which was approved by Company shareholders on April 27, 2017, prior to the closing of the Merger, which the Company anticipates occurring prior to March 31, 2018.

 F-22

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,
	2017			2016
Production revenues	$	1,329,005		$	2,461,727
Production costs		(1,363,946	)		(2,661,258	)
Depletion and depreciation		(127,713	)		(254,329	)
Income tax		56,929			158,851
Results of operations for producing activities	$	(105,725	)	$	(295,009	)

Capitalized costs

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

	Year Ended			Year Ended
	December 31,			December 31,
	2017			2016
Properties subject to amortization	$	10,008,764		$	18,626,746
Accumulated depletion		(8,597,539	)		(15,189,716	)
Net capitalized costs	$	1,411,225		$	3,437,030

Cost incurred in property acquisition, exploration and development activities

	Year Ended		Year Ended
	December 31,		December 31,
	2017		2016
Acquisition of properties	$	—	$	14,399
Exploration costs		—		—
Development costs		—		2,690
Net capitalized costs	$	—	$	17,089

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.

				December 31, 2017										December 31, 2016
Proved Reserves	Total Proved Developed				Proved Undeveloped			Total Proved			Total Proved Developed				Proved Undeveloped			Total Proved
Beginning
Crude Oil BBL’s		372,140				152,610			524,750			1,287,028				202,884			1,489,912
Natural Gas Liquids BBL’s		44,780				—			44,780			47,345				—			47,345
Natural Gas MCF’s		2,686,805				3,422,165			6,108,970			3,195,895				3,029,514			6,225,409
Oil Equivalents BOE’s		864,648				723,042			1,587,690			1,867,041				707,819			2,574,860
Revisions of previous estimates
Crude Oil BBL’s		(30,572	)			236,390			205,818			(856,765	)			(50,274	)		(907,039	)
Natural Gas Liquids BBL’s		1,870				—			1,870			(2,127	)			—			(2,127	)
Natural Gas MCF’s		(1,491	)			—			(1,491	)		(461,536	)			392,651			(68,885	)
Oil Equivalents BOE’s		(28,876	)			236,390			207,514			(935,815	)			15,169			(920,638	)
LSA Disposition
Crude Oil BBL’s		(242,924	)			—			(242,924	)		—				—			—
Natural Gas Liquids BBL’s		(44,709	)			—			(44,709	)		—				—			—
Natural Gas MCF’s		(2,684,865	)			(3,422,165	)		(6,107,030	)		—				—			—
Oil Equivalents BOE’s		(735,110	)			(570,432	)		(1,305,542	)		—				—			—
Production
Crude Oil BBL’s		—				—			—			—				—			—
Production
Crude Oil BBL’s		(31,834	)			—			(31,824	)		(58,123	)			—			(58,123	)
Natural Gas Liquids BBL’s		(1,941	)			—			(1,941	)		(528	)			—			(528	)
Natural Gas MCF’s		(449	)			—			(449	)		(47,554	)			—			(47,554	)
Oil Equivalents BOE’s		(33,851	)			—			(33,851	)		(66,578	)			—			(66,578	)
Ending
Crude Oil BBL’s		66,810				389,000			455,810			372,140				152,610			524,750
Natural Gas Liquids BBL’s		—				—			—			44,780				—			44,780
Natural Gas MCF’s		—				—			—			2,686,805				3,422,165			6,108,970
Oil Equivalents BOE’s		66,810				389,000			455,810			864,648				723,042			1,587,690

 F-23

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.

				December 31, 2017										December 31, 2016
Proved Reserves	Total Proved Developed				Proved Undeveloped			Total Proved			Total Proved Developed				Proved Undeveloped			Total Proved
Beginning
Crude Oil BBL’s		372,140				152,610			524,750			1,287,028				202,884			1,489,912
Natural Gas Liquids BBL’s		44,780				—			44,780			47,345				—			47,345
Natural Gas MCF’s		2,686,805				3,422,165			6,108,970			3,195,895				3,029,514			6,225,409
Oil Equivalents BOE’s		864,648				723,042			1,587,690			1,867,041				707,819			2,574,860
Revisions of previous estimates
Crude Oil BBL’s		(30,572	)			236,390			205,818			(856,765	)			(50,274	)		(907,039	)
Natural Gas Liquids BBL’s		1,870				—			1,870			(2,127	)			—			(2,127	)
Natural Gas MCF’s		(1,491	)			—			(1,491	)		(461,536	)			392,651			(68,885	)
Oil Equivalents BOE’s		(28,876	)			236,390			207,514			(935,815	)			15,169			(920,638	)
LSA Disposition
Crude Oil BBL’s		(242,924	)			—			(242,924	)		—				—			—
Natural Gas Liquids BBL’s		(44,709	)			—			(44,709	)		—				—			—
Natural Gas MCF’s		(2,684,865	)			(3,422,165	)		(6,107,030	)		—				—			—
Oil Equivalents BOE’s		(735,110	)			(570,432	)		(1,305,542	)		—				—			—
Production
Crude Oil BBL’s		—				—			—			—				—			—
Production
Crude Oil BBL’s		(31,834	)			—			(31,824	)		(58,123	)			—			(58,123	)
Natural Gas Liquids BBL’s		(1,941	)			—			(1,941	)		(528	)			—			(528	)
Natural Gas MCF’s		(449	)			—			(449	)		(47,554	)			—			(47,554	)
Oil Equivalents BOE’s		(33,851	)			—			(33,851	)		(66,578	)			—			(66,578	)
Ending
Crude Oil BBL’s		66,810				389,000			455,810			372,140				152,610			524,750
Natural Gas Liquids BBL’s		—				—			—			44,780				—			44,780
Natural Gas MCF’s		—				—			—			2,686,805				3,422,165			6,108,970
Oil Equivalents BOE’s		66,810				389,000			455,810			864,648				723,042			1,587,690

Proved developed reserves at December 31, 2016 consisted of approximately 42% oil and 58% natural gas and totaled 879.8 MBOEs. Proved developed reserves for December 31, 2017 consisted of approximately 100% oil and totaled 66.8 MBOEs. Proved undeveloped reserves for December 31, 2016 were 707.8 MBOEs. Proved undeveloped reserves at December 31, 2017 were 389.0 MBOEs.

The Company annually reviews its proved undeveloped reserves to ensure an appropriate plan for development exists. The Company books proved undeveloped reserves only if it plans to convert these reserves to proved developed producing reserves within five years from the date they were first booked. At December 31, 2017 proved undeveloped reserves were approximately 389.0 MBOE’s. The Company plans to develop all the remaining locations that comprise the 389.0 MBOE of proved undeveloped reserves within five years. However, the decision to deploy capital and the timing of those expenditures is contingent on many different factors. The Company estimates capital expenditures of approximately $5.0 million will be sufficient to develop these reserves. The development plans assume a continued improvement in commodity pricing and general market conditions within the oil and gas industry.  

The calculation of proved undeveloped reserves requires the Company to make predictions regarding future acquisitions and discoveries and the impact they may have on the Company’s overall development plan of properties it currently owns. The development plan is revised to reflect changes in the oil and gas industry, including changing markets and prices, and new investment opportunities, and such revisions will result in changes to our proved undeveloped reserves. Consequently, the exact timing of capital expenditures will be heavily dependent upon the Company’s interpretation of market opportunities which are deeply influenced by projections of future commodity prices. Each year we will review our five year development plan to maximize the value of our investment in oil and gas assets and in turn maximize shareholder value. At December 31, 2017 we believe the following best characterizes our development plan.

	Estimated Conversion of Proved Undeveloped Reserves
	CAPEX ($MM)		MBOE’s
2018		648.0		77.5
2019		965.9		93.5
2020		1,244.8		80.7
2021		563.8		37.5
2022		1550.6		99.7

For the year ended December 31, 2017 proved reserves decreased 1,131.9 MBOEs of which production accounted for 33.9 MBOEs or 3.0% of the decrease. The disposition of assets included in the Loan Sale Agreement (“LSA”) transaction resulted in a 1,305.5 MBOE decrease. An offsetting increase of 207.5 MBOEs, was due primarily to decreases in commodity prices. Crude oil prices increased $0.63 or 1%. Increased commodity pricing triggered positive revisions of 139.0 MBOEs of crude oil classified as proved undeveloped. In 2017 there were no material transfers from the proved undeveloped category of 6 reserves to the proved developed category.

 F-24

For the year ended December 31, 2016 proved reserves decreased 987.1 MBOEs of which production accounted for 66.6 MBOEs or 6.7% of the decrease. The remaining decrease of 920.6 MBOEs, was due primarily to decreases in commodity prices. Crude oil prices decreased $3.49 or 8% and natural gas prices declined 20% or $.37. Diminished commodity pricing triggered negative revisions of 898.9 MBOEs of crude oil classified as proved developed producing. Natural gas liquids decreased pricing resulted in decreases of 3.6 MBOEs to the proved developed producing category. Reduced natural gas prices also reduced amounts classified as proved developed producing by 108.6 MMCF’s. In 2016 there were no material transfers from the proved undeveloped category of 6 reserves to the proved developed category.

In 2017 the Company invested approximately $4,600 in its oil and gas properties. These reduced expenditures were in response to extremely low commodity prices. The Company has approximately $1.0 million of current asset on hand 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 challenges but the Company maintains its belief that reserves will be 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 its proved undeveloped reserves within the five year time frames required; utilizing its balance sheet, to borrow funds as needed. Additionally, the Company believes it 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,
	2017			2016
Future production revenue	$	20,714,780		$	30,085,550
Future production costs		(6,669,980	)		(15,278,990	)
Future development costs		(4,973,120	)		(4,703,230	)
Future cash flows before income tax		9,071,680			10,103,330
Future income taxes		—			—
Future net cash flows		9,071,680			10,103,330
10% annual discount for estimating of future cash flows		(7,603,140	)		(6,666,300	)
Standardized measure of discounted net cash flows	$	1,468,540		$	3,437,030

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,
	2017			2016
Balance beginning of year	$	3,437,030		$	8,769,970
Sales, net of production costs		34,942			199,531
Net change in pricing and production costs		16,312,304			(2,012,883	)
Net change in future estimated development costs		269,890			(1,198,430	)
Purchase of minerals in place		—			—
Extensions and discoveries		—			—
LSA Disposition		(1,902,726	)		—
Revisions		(17,693,233	)		(4,538,173	)
Accretion of discount		1,010,333			2,217,015
Change in income tax		—			—
Balance end of year	$	1,468,540		$	3,437,030

 F-25

EX-21.1

ENERJEX RESOURCES, INC. 10-K 

EXHIBIT 21.1

Subsidiaries of EnerJex Resources, Inc.

As of December 31, 2017

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

ENERJEX RESOURCES, INC. 10-K

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 2017 Form 10-K of EnerJex Resources, Inc. of our estimates of reserves as of December 31, 2017 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: March 23, 2018

EX-31.1

ENERJEX RESOURCES, INC. 10-K 

EXHIBIT 31.1

CERTIFICATION

I, Louis G. Schott, Interim 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: March 23, 2018

/s/  Louis G. Schott

Louis G. Schott

Interim Chief Executive Officer

(Principal Executive Officer)

EX-31.2

ENERJEX RESOURCES, INC. 10-K 

EXHIBIT 31.2

CERTIFICATION

I, Robert Schleizer, Interim 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: March 23, 2018

/s/  Robert Schleizer

Robert Schleizer

Chief Financial Officer

(Principal Financial/Accounting Officer)

EX-32.1

ENERJEX RESOURCES, INC. 10-K 

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, Louis G. Schott, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report of EnerJex Resources, Inc. on Form 10-K for the year ended December 31, 2017, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Form 10-K fairly presents, in all material respects, the financial condition and results of operations of EnerJex Resources, Inc.

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:      March 23, 2018

/s/ Louis G. Schott

Louis G. Schott

Interim Chief Executive Officer

(Principal Executive Officer)

EX-32.2

ENERJEX RESOURCES, INC. 10-K 

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, Robert Schleizer, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report of EnerJex Resources, Inc. on Form 10-K for the year ended December 31, 2017, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Form 10-K fairly presents, in all material respects, the financial condition and results of operations of EnerJex Resources, Inc.

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:      March 23, 2018

/s/ Robert Schleizer

Robert Schleizer

Interim Chief Financial Officer

(Principal Financial/Accounting Officer)

EX-99.1

ENERJEX RESOURCES, INC. 10-K 

Exhibit 99.1

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

February 20, 2018

Mr. Louis G. Schott, Interim CEO
EnerJex Resources, Inc. 

4040 Broadway, Suite 425
San Antonio, TX 78209 

Dear Mr. Schott:

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, 2018. This reserve report was independently prepared Cobb & Associates based upon information furnished by EnerJex and supplemented with information available from public sources.

During 2017, EnerJex divested its assets located in Colorado and Texas while retaining assets located in Greenwood and Woodson Counties, Kansas, which are evaluated in this report. It is our understanding the proved reserves associated with the Kansas properties represents all of the proved resources owned by EnerJex as of January 1, 2018.

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.

Mr. Louis G. Schott
February 20, 2018

Page 2

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, 2018. 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) and proved undeveloped (PUD) in this report.

TABLE 1

ENERJEX RESOURCES, INC.
TOTAL PROVED RESERVES
AS OF JANUARY 1, 2018

	Net Reserves					Net Costs				Future Net Cash Flow
Reserve Category	Oil (MBBL)		Gas (MMCF)	Future Net Income M$		OPEX & Taxes M$		Investment M$		Undiscounted M$		Discounted at 10% M$
PDP		66.8	—		3,036		2,242		-0-		794		512
PUD		389.0	—		17,679		4,428		4,973		8,278		957
Total		455.8	—		20,715		6,670		4,973		9,072		1,469

Note: Columns may not add due to rounding.

Oil volumes, which include condensate, 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 2017. Oil and gas prices are referenced to NYMEX West Texas Intermediate (WTI) and NYMEX Henry Hub (HH) pricing, respectively. The SEC oil price is $51.34 per barrel while the SEC gas price is $2.98 per MMBTU. Product prices used in the revenue forecasts have been adjusted for quality, location, and BTU content based on EnerJex’s lease revenue statements. Prices after adjustments are shown in Table 2. It should be noted that EnerJex’s Kansas properties have no proved gas reserves. Net Commodity prices have been held constant in this evaluation.

TABLE 2

ENERJEX RESOURCES, INC.

AVERAGE NET PRODUCT PRICING

AS OF JANUARY 1, 2018

	Oil Price		Gas Price
State	$/BBL		$/MCF
Kansas		45.45		—

Mr. Louis G. Schott
February 20, 2018

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. 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, 2018.

Mr. Louis G. Schott
February 20, 2018

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 title 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 35 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 022018

XML

Document And Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Mar. 15, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Entity Registrant Name	EnerJex Resources, Inc.
Entity Central Index Key	0000008504
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
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
Trading Symbol	ENRJ
Entity Public Float			$ 2
Entity Common Stock, Shares Outstanding		23,589,790

XML

Consolidated Balance Sheets - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Current Assets:
Cash unrestricted	$ 677,936	$ 128,035
Restricted cash		50,000
Accounts receivable	143,799	600,255
Derivative receivable		10,570
Inventory		185,733
Marketable securities		210,990
Deposits and prepaid expenses	223,648	493,384
Total current assets	1,045,383	1,678,967
Non-current assets:
Fixed assets, net of accumulated depreciation of $618,661 and $1,817,711	178,115	2,077,055
Oil & gas properties using full-cost accounting, net of accumulated DD&A of $8,597,539 and $15,189,716	1,411,225	3,437,030
Other non-current assets		798,809
Total non-current assets	1,589,340	6,312,894
Total assets	2,634,723	7,991,861
Current liabilities:
Accounts payable	217,941	294,241
Accrued liabilities	1,034,827	1,535,165
Current portion of long term debt	4,876,903	17,925,000
Total current liabilities	6,129,671	19,754,406
Non-Current Liabilities:
Asset retirement obligation	1,611,845	3,314,191
Other long-term liabilities	6,919,579	3,401,149
Total non-current liabilities	8,531,424	6,715,340
Total liabilities	14,661,095	26,469,746
Commitments and Contingencies
Stockholders' (Deficit):
Common stock, $0.001 par value, 250,000,000 shares authorized, 16,294,891 and 8,423,936 shares issued and outstanding, respectively.	16,295	8,424
Paid in capital	74,185,091	69,090,613
Accumulated deficit	(86,429,760)	(87,577,862)
Total stockholders' (deficit)	(12,026,372)	(18,477,885)
Total liabilities and stockholders' (deficit)	2,634,723	7,991,861
Series A Preferred Stock [Member]
Stockholders' (Deficit):
Preferred stock value	2,000	938
Series B Preferred Stock [Member]
Stockholders' (Deficit):
Preferred stock value	1	$ 2
Series C Convertible Preferred Stock [Member]
Stockholders' (Deficit):
Preferred stock value	1
Series C Convertible Preferred stock issuable	$ 200,000

XML

Consolidated Balance Sheets (Parenthetical) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Accumulated depreciation, fixed assets	$ 618,661	$ 1,817,711
Oil and gas propertie full-cost method depletion	$ 8,597,539	$ 15,189,716
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	250,000,000	250,000,000
Common stock, shares issued	16,294,891	8,423,936
Common stock, shares outstanding	16,294,891	8,423,936
Series A 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	1,999,998	938,248
Preferred Stock, shares outstanding	1,999,998	938,248
Series B Preferred Stock [Member]
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, shares authorized	1,764	1,764
Preferred stock, shares issued	352	1,764
Preferred Stock, shares outstanding	352	1,764
Series C Convertible Preferred Stock [Member]
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, shares authorized	500	500
Preferred stock, shares issued	300
Preferred Stock, shares outstanding	300

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Consolidated Statements of Operations - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Income Statement [Abstract]
Crude oil revenues	$ 1,309,496	$ 2,390,024
Natural gas revenues	19,509	71,703
Total revenues	1,329,005	2,461,727
Expenses:
Direct operating costs	1,363,946	2,661,258
Depreciation, depletion and amortization	346,197	413,967
Impairment of oil and gas assets		8,032,670
Professional fees	1,390,512	310,471
Salaries	350,863	1,723,789
Administrative expense	545,267	458,375
Total expenses	3,996,785	13,600,530
Loss from operations	(2,667,780)	(11,138,803)
Other income (expense):
Interest expense	(1,250,191)	(1,911,906)
Gain on loan sale agreement	11,500,124
(Loss) on mark to market of derivative contracts		(2,531,401)
Other income	692,879	2,406,340
Total other income (expense)	10,942,812	(2,036,967)
Income (loss) before provision for income taxes	8,275,032	(13,175,770)
Net income (loss)	8,275,032	(13,175,770)
Beneficial Conversion on Series C Preferred Stock	(208,500)
Deemed dividend for anti-dilution provision	(3,400,000)
Preferred dividends	(3,518,430)	(3,010,211)
Net income (loss) attributable to common stockholders	$ 1,148,102	$ (16,185,981)
Net income (loss) per common share basic	$ .11	$ (1.92)
Weighted average shares basic	10,503,070	8,423,936
Net (loss) per common share diluted	$ .11	$ (1.92)
Weighted average shares diluted	10,503,070	8,423,936

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Consolidated Statement of Stockholders' (Deficit) - USD ($)	Series A Preferred Stock [Member]	Series B Preferred Stock [Member]	Series C Preferred Stock [Member]	Common Stock [Member]	Series C Preferred Stock Issuable [Member]	Paid-In Capital [Member]	Retained Deficit [Member]	Total
Balance, beginning at Dec. 31, 2015	$ 938	$ 2		$ 8,424		$ 68,848,944	$ (71,391,881)	$ (2,533,573)
Balance, beginning (shares) at Dec. 31, 2015	938,248	1,764		8,423,936
Stock based compensation						241,669		241,669
Preferred stock dividends							(3,010,211)	(3,010,211)
Net income (loss) for the year							(13,175,770)	(13,175,770)
Balance, ending at Dec. 31, 2016	$ 938	$ 2		$ 8,424		69,090,613	(87,577,862)	(18,477,885)
Balance, ending (shares) at Dec. 31, 2016	938,248	1,764		8,423,936
Stock based compensation						13,690		13,690
Preferred stock dividends							(3,518,430)	(3,518,430)
Common stock issued for anti-dilution provision				$ 597		299,403	(300,000)
Common stock issued for anti-dilution provision (in shares)				597,461
Warrants exercised				$ 1,772		529,658		531,430
Warrants exercised (shares)				1,771,428
Sale of series preferred stock	$ 1,062		$ 1			$ 948,728		949,791
Sale of series preferred stock (shares)	1,061,750		300
Series C preferred stock issuable					$ 200,000			200,000
Conversion of series B preferred stock		$ (1)		$ 5,502
Conversion of series B preferred stock (shares)		(1,412)		5,502,066		(5,501)
Beneficial conversion feature						$ 208,500	(208,500)
Deemed dividend for anti-dilution provision						3,100,000	(3,100,000)
Net income (loss) for the year							8,275,032	8,275,032
Balance, ending at Dec. 31, 2017	$ 2,000	$ 1	$ 1	$ 16,295	$ 200,000	$ 74,185,091	$ (86,429,760)	$ (12,026,372)
Balance, ending (shares) at Dec. 31, 2017	1,999,998	352	300	16,294,891

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Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities
Net income (loss)	$ 8,275,032	$ (13,175,770)
Adjustments to reconcile net income (loss) (used in) operating activities:
Depreciation, depletion and amortization	234,135	413,967
Write-off of inventory	71,982
Amortization of deferred financing costs	223,790
Impairment of oil and gas assets		8,032,670
Stock, options and warrants issued for services	13,690	241,669
Accretion of asset retirement obligation	112,062	225,480
Settlement of asset retirement obligations		(2,767)
(Gain) loss on derivatives		2,520,831
Gain on loan sale agreement, net of cash	(11,500,124)
Changes in current assets and liabilities
Accounts receivable	105,772	377,233
Inventory	(15,943)	(41,406)
Deposits and prepaid expenses	252,478	(246,059)
Accounts payable	(94,783)	(848,601)
Accrued liabilities	1,080,420	404,108
Cash flows used in operating activities	(1,241,489)	(2,098,645)
Cash flows from investing activities
Purchase of fixed assets		(241,683)
Oil and gas properties additions	(4,632)	(17,089)
Increase in restricted cash		(50,000)
Cash flows (used in) investing activities	(4,632)	(308,772)
Cash flows from financing activities
Proceeds from sale of stock and warrant exercises	1,681,221
Proceeds from borrowings	225,000
Repayments of long-term debt	(67,653)	(686,660)
Bank account transfer on loan sale agreement	(92,546)
Cash released from restricted cash	50,000
Deferred financing costs		120,430
Cash flows provided by (used in) financing activities	1,796,022	(566,230)
(Decrease) increase in cash and cash equivalents	549,901	(2,973,647)
Cash and cash equivalents, beginning	128,035	3,101,682
Cash and cash equivalents, end	677,936	128,035
Supplemental disclosures:
Interest paid		922,072
Non-cash investing and financing activities:
Beneficial conversion feature on Series C preferred stock accounted as preferred dividend	208,500
Common stock issued for anti-dilution provision	597
Conversion of Series B preferred stock into common stock	5,502
Share-based payments issued for services	13,690	241,669
Payroll liability converted to note payable	113,750
Non-cash note payable issued in conjunction with the LSA	105,806
Deemed dividend for anti-dilution provision	3,400,000
Preferred dividends payable	3,518,430	$ 3,010,211
Loan settled and exchanged with assets including oil and gas properties and liabilities	$ 13,425,000

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Summary of Accounting Policies

12 Months Ended

Dec. 31, 2017

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.

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, 2017 and 2016. 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, 2017. 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, 2017 are the years ended December 31, 2014, 2015 and 2016. Tax years ending prior to 2014 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, 2017, Fixed Assets consisted of furniture and equipment of $773,707 and building and leasehold improvements of $23,069, as well as accumulated depreciation of furniture and fixtures of $597,692 and accumulated depreciation of building and leasehold improvements of $20,969.

At December 31, 2016, Fixed Assets consisted of vehicles $355,886, furniture and equipment of $795,563, building and leasehold improvements of $23,069 and gathering and compression systems of $2,720,247, as well as accumulated depreciation of vehicles of $336,083, accumulated depreciation of furniture and fixtures of $532,190, accumulated depreciation of building and leasehold improvements of $17,515 and accumulated depreciation of gathering and compression systems of $931,923.   

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, 2016 impairment charges of $8,032,670 were recorded. For the year ended December 31, 2017, no impairment charges were recorded.

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.

On February 10, 2017, the Company and the other Sellers entered into and completed the transactions contemplated by the LSA, described in greater detail in “Note 2 – Going Concern” – “Financing Transactions”.

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, 2017, and 2016 we sold our produced crude oil to ARM Energy Management, LLC, Coffeyville Resources Inc., 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 at December 31, 2016, the carrying value of this security was $210,990. During 2017 the security was transferred as part of the LSA transaction (described below).

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 and preferred stock 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, 2016, 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.

Reclassifications

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

Recent Accounting Pronouncements Adopted by the Company

In July 2017, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2017-11, “Earnings Per Share (Topic 260); Distinguishing Liabilities from Equity (Topic 480); Derivatives and Hedging (Topic 815): (Part 1) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Non-public Entities and Certain Mandatorily Redeemable Non-controlling Interests with a Scope Exception” (“ASU 2017-11”). Part I relates to the accounting for certain financial instruments with down round features in Subtopic 815-40, which is considered in determining whether an equity-linked financial instrument qualifies for a scope exception from derivative accounting. Down round features are features of certain equity-linked instruments (or embedded features) that result in the strike price being reduced based on the pricing of future equity offerings. An entity still is required to determine whether instruments would be classified as equity under the guidance in Subtopic 815-40 in determining whether they qualify for that scope exception. If they do qualify, freestanding instruments with down round features are no longer classified as liabilities. ASU 2017-11 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. Early adoption is permitted, including in an interim period. The Company early adopted ASU 2017-11 during the year ended December 31, 2017. The Company had no cumulative effect of the change in accounting principle on the Company’s Consolidated Balance Sheets as of the beginning of 2017.

Recent Accounting Pronouncements Applicable to the Company

In May 2014, the FASB issued (ASU) No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which supersedes nearly all existing revenue recognition guidance under GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five- step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing GAAP. The guidance is effective for annual and interim periods beginning after December 15, 2017. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The Company plans to adopt this guidance effective January 1, 2018 using the modified retrospective method applied to contracts that are not completed as of that date. The Company has not identified changes to its revenue recognition policies that would result in a material adjustment to the opening balance of retained earnings on January 1, 2018. Adopting this guidance will result in increased disclosures related to revenue recognition policies and disaggregation of revenue in future disclosures in the Company’s Consolidated Financial Statements. As allowed by the practical expedients under Topic 606, the Company does not plan to provide expanded disclosures with respect to the value of unsatisfied performance obligations for contracts with variable consideration or with an original term of one year or less. 

In February 2016, the FASB issued ASU 2016-02, a new lease standard requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous U.S. GAAP. The guidance is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company will be required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements. The Company is currently evaluating the impact of adopting this standard on its consolidated financial statements.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230). ASU 2016-15 seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The Company plans to adopt this guidance effective January 1, 2018. The Company has not identified any changes that upon adoption will have a material effect on its cash flows.

In May 2017, the FASB issued ASU 2017-09, “Compensation-Stock Compensation (Topic 718): Scope of Modification Accounting”, which provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. ASU 2017-09 is effective for annual periods beginning after December 15, 2017, with early adoption permitted, including adoption in any interim period for which financial statements have not yet been issued. The Company plans to adopt this guidance effective January 1, 2018. The Company has not identified any changes that upon adoption will have a material effect on its consolidated financial statements.

The FASB issued ASU 2017-05, “Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic: 610-20): Clarifying the Scope of Asset Derecognition Guidance and the Accounting for Partial Sales of Nonfinancial Assets,” which helps filers determine the guidance applicable for gain/loss recognition subsequent to the adoption of ASU 2014-09, Revenue from Contracts with Customers. The amendments also clarify that the derecognition of all businesses except those related to conveyances of oil and gas rights or contracts with customers should be accounted for in accordance with the derecognition and deconsolidation guidance in Topic 810, Consolidation. The Company adopted the ASU on January 1, 2018, using the modified retrospective transition method. Under this transition method the Company may elect to apply this guidance retrospectively either to all contracts at the date of initial application or only to contracts that are not completed contracts at the date of initial application. The Company elected to evaluate only contracts that are not completed contracts. As there were no not completed contracts at January 1, 2018, there was no impact to the Company’s consolidated financial statements and related disclosures upon adoption.

Recent Accounting Pronouncements Not Yet Adopted. The FASB issued ASU 2016-02, “Leases (Topic 842),” which requires companies to recognize the assets and liabilities for the rights and obligations of all leases with a term greater than 12 months (long-term) on the balance sheet. Leases to explore for or use minerals, oil and natural gas are not impacted by this guidance. In January 2018, the FASB issued ASU 2018-01, “Leases (Topic 842), Land Easement Practical Expedient for Transition to Topic 842.” This ASU permits an entity to continue to apply its current accounting policy for land easements that existed before the effective date of Topic 842. Once an entity adopts Topic 842, it would apply that Topic prospectively to all new (or modified) land easements to determine whether the arrangement contains a lease. Topic 842 requires adoption by application of a modified retrospective transition approach and is effective for the Company on January 1, 2019. Early adoption is permitted.

The Company is in the process of reviewing its portfolio of leased assets and related contracts to determine the impact that adoption will have on its consolidated financial statements and related disclosures. The Company is also assessing the impact of Topic 842 on its systems, processes and internal controls. The Company plans to elect certain practical expedients when implementing the new lease standard, which means the Company will not have to reassess the existence or classification of leases for contracts, including land easements that commenced prior to adoption. The Company anticipates upon adoption to recognize assets and liabilities for the rights and obligations of its existing long-term operating leases on its consolidated balance sheets and to utilize new systems, processes and internal controls to properly identify, classify, measure and recognize new (or modified) leases after the date of adoption. The Company will complete its evaluation during 2018 and will adopt Topic 842 on January 1, 2019, using a modified retrospective approach for all comparative periods presented.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. This new standard clarifies the definition of a business and provides a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This new standard will be effective for the Company on January 1, 2018; however, early adoption is permitted with prospective application to any business development transaction.

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Going Concern

12 Months Ended

Dec. 31, 2017

Going Concern Disclosure [Abstract]

Going Concern

Note 2 - Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates the realization of assets and liquidation of liabilities in the normal course of business. The Company had an accumulated deficit at December 31, 2017 of $86,429,760. Also, cash used in operations was $1,241,489 for the year ended December 31, 2017.  The ability of the Company to continue as a going concern is dependent upon its ability to successfully accomplish the plans described below. The accompanying consolidated financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern.

Merger Agreement

On October 19, 2017, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with AgEagle Aerial Systems, Inc., a Nevada corporation (“AgEagle”), which designs, develops, produces, and distributes technologically advanced small unmanned aerial vehicles (UAV or drones) that are supplied to the agriculture industry, and AgEagle Merger Sub, Inc., a Nevada corporation and wholly-owned subsidiary of the Company (“Merger Sub”). Pursuant to the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will be merged with and into AgEagle, Merger Sub will cease to exist and AgEagle will survive as a wholly-owned subsidiary of the Company (the “Merger”). The respective boards of directors of the Company and AgEagle have approved the Merger Agreement and the transactions contemplated thereby.

At the effective time of the Merger (the “Effective Time”), the shares of AgEagle capital stock will be automatically converted into the right to receive equal to 85% of the then issued and outstanding capital stock of the Company on a fully diluted basis. In addition, at the Effective Time all outstanding options and warrants to purchase shares of AgEagle common stock will be assumed by the Company and converted into options and warrants to purchase shares of Company common stock. No fractional shares of Company common stock will be issued in the Merger but will be rounded to the nearest whole share. Following the consummation of the Merger, former stockholders of AgEagle with respect to the Merger are expected to own 85% of the Company’s outstanding common stock (inclusive of the AgEagle assumed stock options and warrants), and current common and Series A Preferred stockholders of the Company are expected to own 15% of the Company, excluding shares of common stock that may be issued in connection with the conversion of the Company’s Series B Preferred Stock and Series C Preferred Stock, and not including any additional shares which may be issued in connection with the Company’s closing obligation to provide up to $4 million in new working capital and the elimination of all liabilities currently on the Company’s balance sheet.

In connection with the Merger, the Company will also file a proxy statement seeking stockholder approval to: (a) amend the terms of its Series A Preferred Stock (as discussed below); (b) approve the issuance of the Company’s shares in connection with the Merger to the AgEagle shareholders and new investors, in excess of 19.9% of the Company’s total issued and outstanding shares of common stock; (c) approve the issuance of shares to current Company management and directors in lieu of deferred salary and fees, a majority of which will be held in escrow to secure the Company’s indemnity obligations under the Merger Agreement; and (d) change the name of the Company to “AgEagle Aerial Resources, Inc.” 

The Merger Agreement provides that, immediately following the Effective Time, the existing board of directors and officers of the Company will resign and new directors and officers will be appointed by AgEagle.

The Company intends to dispose of its principal assets, consisting primarily of its Kansas oil and gas properties, concurrently with the closing of the Merger. In the event the Merger is not consummated, the Company does not have a present intention to dispose of the above described assets.

The completion of the Merger is subject to various customary conditions, including, among other things: (a) the approval of the stockholders of the Company and AgEagle (which Company shareholder approval has been received to date); (b) the accuracy of the representations and warranties made by each of the Company and AgEagle and the compliance by each of the Company and AgEagle with their respective obligations under the Merger Agreement; (c) approval of the stockholders of the Company for the issuance of its common stock and any other securities (x) to the AgEagle stockholders in connection with the Merger and (y) in connection with the financing transactions contemplated by the Merger Agreement; (d) approval for the listing of shares of the Company’s common stock to be issued in the Merger and other related transactions on the NYSE American; and (e) that all of the Company’s assets as disclosed shall have been sold, transferred or otherwise disposed of and the corresponding debt and liabilities shall have been extinguished. The Company’s existing cash resources are insufficient to satisfy all of its outstanding liabilities. Accordingly, in order to satisfy the condition and consummate the Merger, the Company will be required to raise additional funding prior to the closing of the Merger, the failure of which could result in the Company’s failure to consummate the Merger Agreement. 

The Merger Agreement contains customary representations, warranties and covenants, including covenants obligating each of the Company and AgEagle to continue to conduct its respective business in the ordinary course, to provide reasonable access to each other’s information and to use reasonable best efforts to cooperate and coordinate to make any filings or submissions that are required to be made under any applicable laws or requested to be made by any government authority in connection with the Merger. The Merger Agreement also contains a customary “no solicitation” provision pursuant to which, prior to the earlier of January 31, 2018, or the completion or termination of the Merger, neither the Company nor AgEagle may solicit or engage in discussions with any third party regarding another acquisition proposal unless, in the Company’s case, it has received an unsolicited, bona fide written proposal that the recipient’s board of directors determines is or would reasonably be expected to result in a superior proposal. The Company has paid AgEagle a $50,000 non-refundable fee at the signing of the Merger Agreement. The Merger Agreement contains certain termination rights in favor of each of the Company and AgEagle.

In addition, the Merger Agreement contains provisions for indemnification in the event of any damages suffered by either party as a result of breaches of representations and warranties contained therein. The aggregate maximum indemnification obligation of any indemnifying party for damages with respect to breaches of representations and warranties set forth in the Merger Agreement shall not exceed, in the aggregate, $350,000, other than for fraud, intentional misrepresentation or willful breach. An indemnifying party shall satisfy its indemnification obligations with shares of Company common stock equal to the aggregate amount of losses of the indemnified party, calculated based upon the greater of (i) the value of the Company common stock as of the closing of the Merger; and (ii) the average closing price of the Company common stock on the NYSE American for the five trading days immediately prior to the date such a claim is made. The Company has agreed to deposit an aggregate of 1,215,278 shares of common stock to be issued to current officers and directors of the Company in lieu of deferred salary and fees into escrow to secure its indemnification obligations, the issuance of such shares requiring the approval of the Company’s common stockholders.

In connection with, and as a condition to the closing of the Merger, the Company is seeking the consent of the holder of its Series A Preferred Stock (“Series A Preferred Stock”) to amend the terms thereof to: (i) allow the Company to pay all accrued but unpaid dividends up to September 30, 2017 in additional shares of Series A Preferred Stock based on the value of the liquidation preference thereof, (ii) eliminate the right of the Series A Preferred Stock holders to receive any dividends accruing after September 30, 2017, and (iii) convert each share of Series A Preferred Stock into 10 shares of Company common stock. An affirmative vote of 66.7% of all shares of Series A Preferred Stock voting as a class as of the record date of the proxy statement is required to amend the terms of the Certificate of Designation to provide for these changes, as required under the Merger Agreement. As of September 30, 2017, the Series A Preferred Stock had accrued a total of $6,039,972 in accrued but unpaid dividends, which would result in an additional 241,599 shares of Series A Preferred Stock being issued by the Company to satisfy these accrued dividends.

The Merger Agreement provides either party the right to terminate the Merger if it has not been consummated by January 31, 2018, provided that if all of the conditions to closing shall have been satisfied or shall be capable of being satisfied at such time, the required closing date may be extended until March 31, 2018. On January 31, 2018, the Company extended the required closing date with AgEagle to March 31, 2018.

On November 21, 2017, Alpha Capital Anstalt (“Alpha”) signed a binding commitment letter with the Company to provide prior to or at the closing of the Merger, a minimum of $4 million in new equity capital at a pre-money valuation of between $16 million and $25 million (the “Private Placement”). Per the terms of this commitment letter, in the event any unaffiliated third parties of EnerJex participate in the Private Placement, Alpha’s obligations to fund the Private Placement shall be reduced by such aggregate gross dollar amount funded by such unaffiliated third parties. Alpha has also agreed to convert all notes they hold from the Company into equity at the closing of the Merger. For their funding commitment, Alpha will receive a fee equal to 2.5% of the Company’s outstanding common stock on a fully diluted basis payable at the closing of the Merger. Alpha’s obligations to fund the Private Placement shall terminate on the earlier to occur of (i) the consummation of the Merger, and (ii) March 31, 2018. The Company further agreed that, at no time from the date hereof until the consummation of the Merger, shall it provide or disclose to Alpha any “material non-public information” regarding itself, without the prior consent of Alpha. The funding of the Private Placement is subject to standard conditions such as accuracy of representations and warranties provided in the Merger Agreement, and other similar conditions.

Financing Transactions

On February 10, 2017, the Company, TCB and IberiaBank (collectively, “Sellers”), and PWCM Investment Company IC LLC, and certain financial institutions (collectively, “Buyers”) entered into a Loan Sale Agreement (“LSA”), pursuant to which Sellers sold to Buyers, and Buyers purchased from Sellers, all of Sellers’ right, title and interest in, to and under the Credit Agreement and Loan Documents, in exchange for (i) a cash payment of $5,000,000 (the “Cash Purchase Price”), (ii) a Synthetic Equity Interest equal to 10% of the proceeds, after Buyer’s realization of a 150% return on the Cash Purchase Price within five (5) years of the closing date of the sale, with payment being distributed 65.78947368% to TCB and 34.21052632% to IberiaBank, and (iii) at any time prior to February 10, 2022, Buyer may acquire the interest in clause (ii) above. In connection with the LSA, the Company released Sellers and its successors as holders of the rights under the Credit Agreement and Loan Documents, including Buyers, from any and all claims under the Credit Agreement and Loan Documents. 

Also on February 10, 2017, the Company and its subsidiaries, and successor lender entered into a binding letter agreement dated February 10, 2017, which was subsequently amended on March 30, 2017 (as amended, the “letter agreement”) pursuant to which:

1. the successor lender agreed to forgive our existing secured loan in the approximate principal amount of $17,295,000, and in exchange entered into a secured promissory note (which we refer to as the “restated secured note”) in the original principal amount of $4,500,000.

2. we:

a. conveyed our oil and gas properties and associated performance and surety bonds in Colorado, Texas, and Nebraska;

b. conveyed all of our shares of Oakridge Energy, Inc. (together, the “conveyed oil and gas assets”); and

c. retained our assets in Kansas and continued as a going concern. The Kansas assets currently provide most of our current operating revenue.

The restated secured note:

a. is secured by a first-priority lien in the Company’s oil and gas producing assets situated in the State of Kansas,

b. evidences accrued interest on the $4,500,000 principal balance at a rate of 16% per annum,

c. bears interest from and after May 1, 2017, at a rate of 16.0% per annum,

d. is pre-payable in full at a discount at any time during the term of the restated secured note upon EnerJex paying $3,300,000 to successor lender, and

e. matures and is due and payable in full on November 1, 2017 (subject to the extension right described below).

The Company has extended the restated secured note to March 23, 2018. We have an option to extend the maturity date of the restated secured note to April 30, 2018, upon payment of an extension fee of $50,000.

So long as we repay the $3,300,000 in indebtedness on or prior to the maturity date, as extended, all other amounts payable under the restated secured note are to be forgiven.

The closing occurred on May 10, 2017. As part of the closing procedures and net settlement, we issued a promissory note to Pass Creek Resources LLC in the amount of $105,806. The promissory bears interest at 16% per annum and matured on June 9, 2017. The amount due was not paid on June 9, 2017, but the holder has not provided the Company a notice of default.

In connection with the May 10, 2017 closing and in consideration of the satisfaction of $13,425,000 of the amount due under the Credit Agreement, as amended, the Company and certain of its subsidiaries transferred to PCR Holdings LLC, an affiliate of the successor lenders under the Credit Agreement, all of the Company’s oil and gas properties and assets located in Colorado, Texas, and Nebraska, as well as the Company’s shares of Oakridge Energy, Inc.

To evidence the Company’s remaining $4,500,000 of indebtedness to PWCM Investment Company IC LLC (“PWCM”), RES Investment Group, LLC (“RES”), Round Rock Development Partners, LP (“Round Rock”), and Cibolo Holdings, LLC (“Cibolo Holdings,” and together with PWCM, RES and Round Rock, “Successor Lenders”), the Company’s subsidiaries (except Kansas Holdings, LLC) entered into a Second Amended and Restated Credit Agreement with Cortland Capital Market Services LLC, as Administrative Agent, and the other financial institutions and banks parties thereto (the “New Credit Agreement”), and a related Amended and Restated Note (the “New Note”), in the amount of $3.3 million as described above.

Our subsidiaries’ obligations under the credit agreement and note are non-recourse and are secured by a first-priority lien in the Company’s and its subsidiaries’ oil properties and assets located in Kansas. The Company was removed as a borrower under the Credit Agreement, but entered into a Guaranty of Recourse Carveouts, pursuant to which the Company guarantees its subsidiaries’ payment of certain fees and expenses due under the Credit Agreement, and may be liable for certain conduct, such as fraud, bad faith, gross negligence, and waste of the Kansas oil properties or assets. 

On December 22, 2017, the Company entered into the First Amendment to the Second Amended and Restated Credit Agreement (the “Amendment) with Pass Creek Resources, LLC (“Pass Creek”) and Cortland Capital Market Services, LLC (“Administration Agent”). The Company, Pass Creek, and Administrative Agent are parties to the Second Amended and Restated Credit Agreement dated May 10, 2017. The Maturity Date of the Loan has been extended to the earlier of (i) February 15, 2018 or April 30, 2018, if (a) the Company provide notice to the Administrative Agent of their intent to extend the maturity date and (b) no later than the first Business Day following delivery of such notice pay a $100,000 extension fee, or (ii) the merger of AgEagle Merger Sub, Inc., a wholly-owned subsidiary of the Company and AgEagle Aerial Systems, Inc. pursuant to the Agreement and Plan of Merger dated as of October 19, 2017. At the closing of the First Amendment, the Company paid Pass Creek a $65,000 extension fee and $7,500 to the Administrative Agent for additional fees. The Company also paid the Administrative Agent an additional $45,000 upon the filing of a definitive proxy statement by the Company with the Securities and Exchange Commission. The Company also agreed to borrow Improvement Advances in an amount not to exceed $300,000. The Company has extended the restated secured note to March 23, 2018 and has the option to extend the maturity date of the restated secured note to April 30, 2018, upon payment of an extension fee of $50,000.

These conditions raise substantial doubt about the Company’s ability to continue as a going concern for the next twelve months following the issuance of these financial statements. The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. Accordingly, the financial statements do not include any adjustments relating to the recoverability of assets and classification of liabilities that might be necessary should the Company be unable to continue as a going concern.

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Equity Transactions

12 Months Ended

Dec. 31, 2017

Equity [Abstract]

Equity Transactions

Note 3 - Equity Transactions

Stock transactions in the fiscal year ended December 31, 2017

We accrued dividends of $3,518,430 for our Series A Preferred Stock for the year ended December 31 2017. At December 31, 2017, aggregate accumulated dividends payable to the Series A Preferred Stock holders totaled $6,919,579.

On April 27, 2017, the Company entered into an Additional Issuance Agreement with Alpha Capital Anstalt, for the purchase of 300 restricted shares of its newly designated Series C Convertible Preferred Stock in consideration for $300,000, with an option to purchase an additional 200 shares of Series C Convertible Preferred Stock for an aggregate purchase price of $200,000. As of December 31, 2017, the Company had issued 300 shares of Series C Convertible Preferred Stock for an aggregate purchase price of $300,000. In addition, during the year ending December 31, 2017, the Company had received $200,000 from Alpha Capital Anstalt to purchase an additional 200 shares of Series C Convertible Preferred Stock. As of December 31, 2017, the additional 200 shares of Series C Convertible Preferred Stock have not been issued and are reflected as Series C Convertible Preferred Stock Issuable on the balance sheet in the aggregate amount of $200,000.

The Company recorded a beneficial conversion feature of $208,500 based on the fair value of the common stock and the conversion rate as of the date of issuance. This amount was recorded as a deemed distribution for the year ended December 31, 2017.

The Series C Convertible Preferred Stock (“Series C Preferred Stock”) is non-voting (except to the extent required by law and except for certain consent rights relating to amending the certificate of incorporation or bylaws, and the like), ranks senior to the common stock with respect to dividends and with respect to distributions upon a deemed dissolution, liquidation or winding-up of the Company, and ranks junior to the Company’s Series A preferred stock and Series B preferred stock with respect to dividends and with respect to distributions upon a deemed dissolution, liquidation or winding-up of the Company. Upon request of the holders, the Company can seek stockholder approval to remove the Issuance Limitation described therein and to allow for further adjustments related to anti-dilution protection, only if such stockholder approval is obtained. The Series C Convertible Preferred Stock has a liquidation preference of $1,000 per share, and is convertible at the option of the holder at a conversion price equal to $0.30 per share, or a ratio equal to approximately 3,333 shares of common stock for each one (1) share of Series C Convertible Preferred Stock, subject to customary adjustments. Dividends are payable on the shares of Series C Convertible Preferred Stock only if and to the extent that dividends are payable on the common stock into which the Series C Convertible Preferred Stock is convertible. The Series C Convertible 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 for the redemption price of $1,000 per share, as adjustable as provided in the designation of the Series C Preferred Stock.

The Series C Preferred Stock includes a beneficial ownership limitation preventing conversion of shares of Series C Preferred Stock into more than 9.99% of the number of shares of common stock outstanding immediately after giving effect to the issuance of shares of common stock upon conversion of the Series C Preferred Stock. In addition, the Company may not convert the Series C Preferred Stock into a number of shares of common stock which, when aggregated with any shares of common stock issued on or after the original issue date and prior to such conversion date in connection with any conversion of Series C Preferred Stock would exceed 1,683,944 shares of common stock (19.99% of the outstanding shares as of the original issue date), subject to adjustment for forward and reverse stock splits, recapitalizations and the like. In the event conversion of the Series C Preferred Stock is limited pursuant to these provisions, each holder shall be entitled to a pro rata portion of the issuable maximum.

Pursuant to the anti-dilutive provisions of the Securities Purchase Agreement dated as of March 11, 2015, which requires the Company to issue additional shares of common stock to adjust the purchase price paid by purchasers in the Company’s March 2015 offering, in the event any shares are sold (or convertible securities are sold), with a price per share less than the purchase price paid by the March 2015 purchasers subject to the terms of the Securities Purchase Agreement, Alpha Capital Anstalt received 597,461 shares of common stock, which the Company recorded as a $300,000 deemed distribution In addition, the Series B Convertible Preferred Stock conversion ratio equal to approximately 571 shares of common stock for each one (1) share of Preferred Stock reset to approximately 3,333 shares of common stock for each one (1) share of Series B Convertible Preferred Stock, to be consistent with the terms of the Series C Convertible Preferred Stock, pursuant to the anti-dilution requirements of the Series B Convertible Preferred Stock. The Company recorded a deemed distribution of $2,500,000 related to the down round triggering event of the Series B Convertible Preferred Stock. In addition, the warrants strike price of $2.75 reset to $0.30, to be consistent with the terms of the Series C Convertible Preferred Stock, pursuant to the anti-dilution requirements of the warrants. The Company recorded a deemed distribution of $500,000 related to the down round triggering event of the warrants. 

During, 2017, Alpha Capital Anstalt converted 1,412 shares of Series B Convertible Preferred Stock into 5,502,066 shares of common stock.

On October 23, 2017, Alpha Capital Anstalt exercised warrants to purchase 1,000,000 shares of our common stock for an aggregate exercise price of $300,000 (or $0.30 per share), pursuant to the terms of such warrants, and was issued 1,000,000 shares of common stock.

On November 6, 2017, Alpha Capital Anstalt exercised warrants to purchase 771,428 shares of our common stock for an aggregate exercise price of $231,429 (or $0.30 per share), pursuant to the terms of such warrants, and was issued 771,428 shares of common stock.

On December 20, 2017 the Company entered into a Stock Purchase Agreement for the sale of 1,061,750 shares of its Series A Preferred Stock. The Preferred Stock was sold to Alpha Capital Anstalt at $0.612 per share or an aggregate of $649,791. Pursuant to the anti-dilutive provisions of the Series B Preferred Stock, the Series C Preferred Stock and the warrants, the conversion and strike price reset from $0.30 to $0.0612. The Company recorded a deemed distribution of $100,000 related to the down round triggering event of the Series B Preferred Stock, the Series C Preferred Stock and the warrants, in the aggregate.

On February 13, 2018, the Company issued Alpha Capital Anstalt the 200,000 shares of Series C Convertible Preferred Stock which it was due pursuant to the terms of the April 27, 2017, Additional Issuance Agreement, in consideration for the $200,000 paid during the year ended December 31, 2017.

Subsequent to December 31, 2017, Alpha Capital Anstalt converted (a) 343.671 shares of Series B Convertible Preferred Stock into 5,610,955 shares of common stock; and (b) 103.142 shares of Series C Convertible Preferred Stock into 1,683,944 shares of common stock, pursuant to the terms of such securities.

Stock transactions in fiscal year ended December 31, 2016

There were no equity transactions for the year ended December 31, 2016.

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.

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 2017 and 2016, no options were granted to any employees or directors.

We expensed $13,690 and $241,669 for the years ended December 31, 2017 and December 31, 2016 respectively for options granted. 

A summary of stock options is as follows:

				Weighted Ave.						Weighted Ave.
	Options			Exercise Price			Warrants			Exercise Price
Outstanding January 1, 2016		288,331		$	10.17			1,904,286		$	2.75
Granted		—			—			—			—
Cancelled		(80,667	)		(7.15	)		—			—
Exercised		—			—			—			—
Outstanding December 31, 2016		207,664		$	9.69			1,904,286		$	2.75
Granted		—			—			—			—
Cancelled		—			—			—			—
Exercised		(192,332	)		(10.5	)		(1,771,428	)		0.30
Outstanding December 31, 2017		15,332		$	7.63			132,858		$	0.30

The number of options that were vested at December 31, 2017 was 15,332. The were no options that were not vested at December 31, 2017.

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Asset Retirement Obligation

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [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, 2016	$	3,091,478
Liabilities incurred during the period		—
Liabilities settled during the year		(2,767	)
Accretion		225,480
Asset retirement obligations, December 31, 2016	$	3,314,191
Release of liabilities		(1,814,408	)
Liabilities incurred during the period		—
Liabilities settled during the year		—
Accretion		112,062
Asset retirement obligations, December 31, 2017	$	1,611,845

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Long-Term Debt

12 Months Ended

Dec. 31, 2017

Debt Disclosure [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 (collectively, “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 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 Amended and Restated 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, we entered into a Fifth Amendment to the Amended and Restated Credit Agreement. The Fifth Amendment reflects the following changes it: (i) expanded the 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 a borrower party; (iv) added certain collateral and security interests in favor of the Bank; and (v) reduced the 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 Bank (i) re-determined the Borrowing Base based upon the 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 would 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 an 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) suspended certain hedging requirements, and (iii) made certain other amendments to the Credit Agreement.

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 payments on April 6, 2016 and May 2, 2016. On April 7, 2016, the Company 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 was to be used by the Company to pursue strategic alternatives.

On April 28, 2016 the Bank informed the Company that it would extend the above Forbearance Agreement period to May 31, 2016 upon effecting a principal reduction of $125,000. In addition, the Company will receive an automatic extension to September 15, 2016 upon meeting certain terms and conditions specified by the Bank. On May 31, 2016, the Company and the Bank amended the Forbearance Agreement to extend the forbearance period to August 31, 2016. On July 29, 2016, the Company and the Bank amended the Forbearance Agreement to extend the forbearance period to October 1, 2016.  

On October 1, 2016, the Company and the Bank could not reach an agreement to extend the Third Amendment to the Forbearance Agreement. Following this outcome, the Company decided to discontinue payment of interest on its outstanding loan obligations with the Bank. The Company continued to evaluate plans to restructure, amend or refinance existing debt through private options.

On February 10, 2017, the Company and the other Sellers entered into and completed the transactions contemplated by the LSA, described in greater detail in “Note 2 – Going Concern” – “Financing Transactions”.

Below is a table showing the reconciliation of the gain on LSA as set forth on the statement of operations for the year ended December 31, 2017:

Forgiveness of existing secured loan	$	17,925,000
Forgiveness of accrued interest		1,306,801
Issuance of secured promissory note		(4,500,000	)
Transfer of oil and gas properties		(1,902,726	)
Transfer of gas gathering system		(1,772,588	)
Transfer of shares of Oakridge Energy, Inc.		(210,990	)
Transfer of ARO liability		1,814,407
Transfer of other assets		(1,159,780	)
Gain on LSA	$	11,500,124

To evidence the Company’s remaining $4,500,000 of indebtedness to PWCM Investment Company IC LLC (“PWCM”), RES Investment Group, LLC (“RES”), Round Rock Development Partners, LP (“Round Rock”), and Cibolo Holdings, LLC (“Cibolo Holdings,” and together with PWCM, RES and Round Rock, “Successor Lenders”), the Company’s subsidiaries (except Kansas Holdings, LLC) entered into a Second Amended and Restated Credit Agreement with Cortland Capital Market Services LLC, as Administrative Agent, and the other financial institutions and banks parties thereto (the “New Credit Agreement”), and a related Amended and Restated Note (the “New Note”), in the amount of $3.3 million as described above under “Note 2 – Going Concern” – “Financing Transactions”.  

Our subsidiaries’ obligations under the credit agreement and note are non-recourse and are secured by a first-priority lien in the Company’s and the subsidiaries’ oil properties and assets located in Kansas. The Company was removed as a borrower under the Credit Agreement, but entered into a Guaranty of Recourse Carveouts, pursuant to which the Company guarantees the Subsidiaries’ payment of certain fees and expenses due under the Credit Agreement, and may be liable for certain conduct, such as fraud, bad faith, gross negligence, and waste of the Kansas oil properties or assets.

December 22, 2017, the Company entered into the First Amendment to the Second Amended and Restated Credit Agreement (the “Amendment) with Pass Creek Resources, LLC (“Pass Creek”) and Cortland Capital Market Services, LLC (“Administration Agent”). The Company, Pass Creek, and Administrative Agent are parties to the Second Amended and Restated Credit Agreement dated May 10, 2017. The Maturity Date of the Loan has been extended to the earlier of (i) February 15, 2018 or April 30, 2018, if (a) the Company provides notice to the Administrative Agent of their intent to extend the maturity date and (b) no later than the first Business Day following delivery of such notice pay a $100,000 extension fee, or (ii) the merger of AgEagle Merger Sub, Inc., a wholly-owned subsidiary of the Company and AgEagle Aerial Systems, Inc. pursuant to the Agreement and Plan of Merger dated as of October 19, 2017. At the closing of First Amendment, the Company paid Pass Creek a $65,000 extension fee and $7,500 to the Administrative Agent for additional fees. The Company also paid the Administrative Agent an additional $45,000 upon the filing of a definitive proxy statement by the Company with the Securities and Exchange Commission. The Company also agreed to borrow Improvement Advances in an amount not to exceed $300,000. The Company has extended the restated secured note to March 23, 2018 and has the option to extend the maturity date of the restated secured note to April 30, 2018, upon payment of an extension fee of $50,000.

As of December 31, 2017, the principal balance of $4,457,347 along with accrued interest of $479,452 remained due under the Amended and Restated Credit Agreement. At December 31, 2017, the Company was not in compliance with certain covenants, and the loan may be called due by Pass Creek. The note is in default.

As of December 31, 2017, the principal balance of $80,805 along with accrued interest of $9,616 remained due under the promissory note with Pass Creek Resources LLC. The note is in default.

On July 14, 2017, July 28, 2017 and August 30, 2017, the Company entered into Secured Promissory Notes totaling $225,000 with Alpha Capital Anstalt, which have a maturity date of June 30, 2018, and accrue interest at a rate of 8% per annum. The amount due under the notes is secured by a security interest, subordinate to certain other security interests of the Company, in substantially all of the Company's assets. The amount due under the notes is convertible into shares of the Company's common stock, at the option of Alpha Capital Anstalt, on identical terms as the outstanding Series C Convertible Preferred Stock (i.e., an initial conversion price of $0.30 per share, a 9.9% ownership limitation and certain anti-dilution rights, which currently result in a conversion price of $0.0612 per share). As of December 31, 2017, the principal balance of $225,000 remained due.

As of December 31, 2017, the principal balance of $113,750 along with accrued interest of $5,574, remained due under the promissory note with Robert Watson, the former CEO. The note is in default.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 6 - Commitments and Contingencies

Rent expense for the years ended December 31, 2017 and 2016 was approximately $69,000 and $148,000, respectively. Future non-cancellable minimum lease payments are approximately, $10,000 for 2018.

As of December 31, 2017, 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.

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 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, 2017, we have no reserve for environmental remediation and are not aware of any environmental claims.

On September 23, 2016, the Company, American Standard Energy Corporation, Baylor Operating LLC, Bernard Given and Loeb & Loeb LLP were sued by Geronimo Holdings Corporation and Randal Capps in the 143rd Judicial District Court located in Pecos, Texas. The suit among other things, seeks damages for an alleged unlawful sale of properties in Crockett County Texas and for alleged unpaid royalties. The Company believes the suit is without merit and will vigorously defend itself. The Company has faith that it will prevail and at December 31, 2017 no reserve for potential losses arising from this matter has been recorded. Additionally under its agreement with Baylor Operating LLC, Baylor has agreed to indemnify and defend the Company against all lawsuits and claims including this one.

On April 26, 2016, C&F Ranch, LLC sued the Company in Allen County Kansas for alleged breach of contract related to the rental of certain lands located on the C&F Ranch. During the first quarter of 2018, the Company settled this dispute for $9,000.

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Income Taxes

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

Note 7 - Income Taxes

There was no current or deferred income tax expense (benefit) for the years ended December 31, 2017 and December 31, 2016.

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

	Year Ended December 31,
	2017			2016
Statutory tax rate		35.00	%		35.00	%
State tax rate, net of federal tax		2.01	%		1.78	%
Other permanent items		0.00	%		0.00	%
Change in valuation allowance		(37.01	)%		(36.78	)%
Effective tax rate		0.00	%		0.00	%

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

	Year Ended December 31,
	2017			2016
Non-current deferred tax asset:
Oil and gas costs and long-lived assets	$	4,764,420		$	11,500,697
Derivative instruments		—			—
Net operating loss carry-forward		21,547,347			35,815,113
Valuation allowance		(26,311,767	)		(47,315,809	)
Net deferred tax asset (liability)	$	—		$	—

On December 22, 2017, the Tax Cuts and Jobs Act (TCJA) was signed into law. The TCJA, among other things, includes the reduction of the federal tax rate for corporations from 35% to 21% and changes or limits certain tax deductions including the utilization of net operating losses. Under generally accepted accounting principles, the Company is required to revalue its deferred tax assets and liabilities during the period in which the new tax legislation is enacted. The impact of TCJA resulted in a decrease in the Company's deferred tax assets in the amount of $18 million. However, there is no impact of the revaluation to the current net income because it was fully offset by the release of the valuation allowance that was previously recorded against the deferred tax asset.

At December 31, 2017, we have a net operating loss carry forward of approximately $93 million expiring in 2021-2038 that is subject to certain limitations on an annual basis. Such limitation has not been determined, by Management. Management has determined that a 100% valuation allowance be established against net operating losses where it is more likely than not that such losses will expire or will not be available before they are utilized.

The Company incurred a change of control as defined by the Internal Revenue Code (IRC 382). 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. No assurance can be made, as to the availability of the net operating losses based upon Internal Revenue Code (IRC 382), as described, and such amounts of net operating losses available, based upon the limitations described. If there was or is other changes of ownership, the net operating losses may be a totally unavailable to offset taxable income.

Internal Revenue Code (IRC 108), Income from discharge of indebtedness has rules to determine amounts that are required to be included or excluded from taxable income, based upon certain circumstances. Management has determined that any discharge of indebtedness that has occurred is included in taxable income for this period, but is reviewing such amounts, as it applied to IRC 108.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [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, 2017.

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.

At December 31, 2016, our marketable securities had a value of $210,990. During 2017, as part of the LSA transaction described in “Note 2 – Going Concern” – “Financing Transactions”, we transferred the marketable securities. At December 31, 2017, we held no assets valued at Level 3.

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Derivative Instruments

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

Note 9 - Derivative Instruments

We enter into 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, allowed 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 had 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 were not required to post additional collateral, including cash.

At December 31, 2017 all derivative contracts had expired and we did not enter into any derivative contracts during 2017.  

We recorded a loss related to the mark to market of our derivative contracts for the year ended December 31, 2016 of $2,531,401. No gain or loss was recorded in 2017.

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Net Income Per Common Share

12 Months Ended

Dec. 31, 2017

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, 2017

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, 2017, which were based on a West Texas Intermediate oil price of $51.34 per Bbl and a Henry Hub natural gas price of $2.97 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, 2017, was based on a West Texas Intermediate oil price of $42.46 per Bbl and a Henry Hub natural gas price of $2.63 per MMBtu (adjusted for basis and quality differentials), respectively. The twelve-month, unweighted-average first-day-of-the –month price as of June 30, 2017 was $42.46 per Bbl and $2.63per MMBtu The twelve-month, unweighted-average first-day-of-the –month price as of March 31, 2017 was $45.16 per Bbl and $2.40 per MMBtu (adjusted for basis and quality differentials), respectively. Utilizing these prices, the calculated ceiling amount was greater than the net capitalized cost of oil and natural gas properties as of December 31, 2017, and as a result, no write down was recorded. For the year ended December 31, 2016, the Company recorded an impairment charge of $8,032,670. 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, 2017

Other Income and Expenses [Abstract]

Other Income

Note 12 - Other Income

The following table depicts the components of other income for the years ended December 31, 2017 and December 31, 2016:

	Year ended December 31, 2017			Year ended December 31, 2016
Realized gain (loss) clearing of derivative contracts	$	—		$	2,382,184
Service Agreement with Camber Energy, Inc.		696,774			—
Miscellaneous income		72			24,124
Interest income		(3,967	)		32
Other income (loss)	$	692,879		$	2,406,340

On April 27, 2017, the Company entered into a Services Agreement (“Service Agreement”) with Camber Energy, Inc., to perform certain outsourced interim services for $150,000 per month. Effective December 4, 2017, the Company and Camber Energy, Inc. (“Camber”), mutually agreed to terminate the agreement between the parties effective November 30, 2017.

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Subsequent Events

12 Months Ended

Dec. 31, 2017

Subsequent Events [Abstract]

Subsequent Events

Note 13 - Subsequent Events

 On January 31, 2018, the Company extended the end date of its previously disclosed Agreement and Plan of with AgEagle Aerial Systems, Inc., a Nevada corporation (“AgEagle”) to March 31, 2018.

On February 20, 2018, the Company announced that it set the record date for the special meeting of its shareholders to, among other things, consider and vote on various proposals necessary to close the previously announced Agreement and Plan of Merger, dated October 19, 2017 (the “Merger Agreement”), with AgEagle Aerial Systems, Inc. Shareholders of record as of the close of business on February 20, 2018, will be entitled to vote at the special meeting on March 21, 2018. The Merger is subject to certain customary closing conditions and approval from our shareholders. The Merger is expected to close in the first quarter of 2018. 

As previously reported, on April 27, 2017, the Company entered into an Additional Issuance Agreement with Alpha Capital Anstalt, for the purchase of 300 restricted shares of the Company’s then newly designated Series C Convertible Preferred Stock in consideration for $300,000, with an option to purchase an additional 200 shares of Series C Convertible Preferred Stock for an aggregate purchase price of $200,000. As of December 31, 2017, the Company had issued 300 shares of Series C Convertible Preferred Stock for an aggregate purchase price of $300,000. In addition, during the year ended December 31, 2017, the Company had received $200,000 from Alpha Capital Anstalt to purchase an additional 200 shares of Series C Convertible Preferred Stock, which shares had not been issued as of December 31, 2017, and which are reflected as Series C Convertible Preferred Stock Issuable on the balance sheet as of December 31, 2017, in the aggregate amount of $200,000.

On February 13, 2018, the Company issued Alpha Capital Anstalt the 200,000 shares of Series C Convertible Preferred Stock which it was due pursuant to the terms of the April 27, 2017, Additional Issuance Agreement, in consideration for the $200,000 paid during the year ended December 31, 2017.

Subsequent to December 31, 2017, Alpha Capital Anstalt converted (a) 343.671 shares of Series B Convertible Preferred Stock into 5,610,955 shares of common stock; and (b) 103.142 shares of Series C Convertible Preferred Stock into 1,683,944 shares of common stock, pursuant to the terms of such securities.

At a special meeting of shareholders held on March 21, 2018, the Company’s shareholders approved (a) the issuance of the Company’s common stock to the shareholders of AgEagle in connection with and pursuant to the terms of the Merger Agreement in accordance with NYSE American Rules 712 and 713; (b) an amendment to the Company’s Articles of Incorporation to amend the 10% Series A Cumulative Redeemable Perpetual Preferred Stock to: (i) allow the Company to pay all accrued but unpaid dividends up to September 30, 2017 in additional shares of Series A Preferred Stock based on the value of the liquidation preference thereof, (ii) eliminate the right of the Series A Preferred Stock holders to receive any dividends accruing after September 30, 2017, (iii) convert each share of Series A Preferred Stock into 10 shares of common stock (subject to adjustment for a reverse stock split (discussed below)), and (iv) increase the number of Series A Preferred shares by 241,599 shares; (c) an amendment to the Company’s Articles of Incorporation to change the name of the Company to “AgEagle Aerial Systems, Inc.”; (d) the adoption of the EnerJex 2017 Omnibus Equity Incentive Plan (the “Plan”); (e) the issuance of 2,248,264 shares of common stock to current officers and directors in lieu of deferred salary and fees, a majority of which will be held in escrow to secure the Company’s obligations under the Merger Agreement; (f) the conversion of the Company’s Series C Convertible Preferred Stock into shares of common stock in order to comply with the listing rules of the NYSE American; (g) the conversion of the Company’s 10% Series A Cumulative Redeemable Perpetual Preferred Stock into shares of common stock in order to comply with the listing rules of the NYSE American; (h) the issuance of shares of the Company’s common stock, conversion of the Company’s Series C Preferred Stock and conversion of $425,000 owed under five promissory notes held by, Alpha Capital Anstalt, of which $200,000 of the notes have previously been converted into Series C Preferred Stock as of the date of this filing, into shares of common stock in order to comply with the listing rules of the NYSE American.

The Plan provides for the grant of up to 2,000,000 shares of common stock (such number based on a post-reverse split amount) as awards which may include incentive stock options (“ISOs”), non-qualified stock options (“NQSOs”), unrestricted shares, restricted shares, restricted stock units, performance stock, performance units, SARs, tandem stock appreciation rights, distribution equivalent rights, or any combination of the foregoing, to key management employees, non-employee directors, and non-employee consultants of the Company or any of its subsidiaries (however, solely Company employees or employees of the Company’s subsidiaries are eligible for incentive stock option awards).

Additionally, the Company plans to conduct a 1-for-25 reverse stock split of the Company’s outstanding common stock, which was approved by Company shareholders on April 27, 2017, prior to the closing of the Merger, which the Company anticipates occurring prior to March 31, 2018.

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Supplemental Oil and Gas Reserve Information (Unaudited)

12 Months Ended

Dec. 31, 2017

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,
	2017			2016
Production revenues	$	1,329,005		$	2,461,727
Production costs		(1,363,946	)		(2,661,258	)
Depletion and depreciation		(127,713	)		(254,329	)
Income tax		56,929			158,851
Results of operations for producing activities	$	(105,725	)	$	(295,009	)

Capitalized costs

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

	Year Ended			Year Ended
	December 31,			December 31,
	2017			2016
Properties subject to amortization	$	10,008,764		$	18,626,746
Accumulated depletion		(8,597,539	)		(15,189,716	)
Net capitalized costs	$	1,411,225		$	3,437,030

Cost incurred in property acquisition, exploration and development activities

	Year Ended		Year Ended
	December 31,		December 31,
	2017		2016
Acquisition of properties	$	—	$	14,399
Exploration costs		—		—
Development costs		—		2,690
Net capitalized costs	$	—	$	17,089

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.

				December 31, 2017										December 31, 2016
Proved Reserves	Total Proved Developed				Proved Undeveloped			Total Proved			Total Proved Developed				Proved Undeveloped			Total Proved
Beginning
Crude Oil BBL’s		372,140				152,610			524,750			1,287,028				202,884			1,489,912
Natural Gas Liquids BBL’s		44,780				—			44,780			47,345				—			47,345
Natural Gas MCF’s		2,686,805				3,422,165			6,108,970			3,195,895				3,029,514			6,225,409
Oil Equivalents BOE’s		864,648				723,042			1,587,690			1,867,041				707,819			2,574,860
Revisions of previous estimates
Crude Oil BBL’s		(30,572	)			236,390			205,818			(856,765	)			(50,274	)		(907,039	)
Natural Gas Liquids BBL’s		1,870				—			1,870			(2,127	)			—			(2,127	)
Natural Gas MCF’s		(1,491	)			—			(1,491	)		(461,536	)			392,651			(68,885	)
Oil Equivalents BOE’s		(28,876	)			236,390			207,514			(935,815	)			15,169			(920,638	)
LSA Disposition
Crude Oil BBL’s		(242,924	)			—			(242,924	)		—				—			—
Natural Gas Liquids BBL’s		(44,709	)			—			(44,709	)		—				—			—
Natural Gas MCF’s		(2,684,865	)			(3,422,165	)		(6,107,030	)		—				—			—
Oil Equivalents BOE’s		(735,110	)			(570,432	)		(1,305,542	)		—				—			—
Production
Crude Oil BBL’s		—				—			—			—				—			—
Production
Crude Oil BBL’s		(31,834	)			—			(31,824	)		(58,123	)			—			(58,123	)
Natural Gas Liquids BBL’s		(1,941	)			—			(1,941	)		(528	)			—			(528	)
Natural Gas MCF’s		(449	)			—			(449	)		(47,554	)			—			(47,554	)
Oil Equivalents BOE’s		(33,851	)			—			(33,851	)		(66,578	)			—			(66,578	)
Ending
Crude Oil BBL’s		66,810				389,000			455,810			372,140				152,610			524,750
Natural Gas Liquids BBL’s		—				—			—			44,780				—			44,780
Natural Gas MCF’s		—				—			—			2,686,805				3,422,165			6,108,970
Oil Equivalents BOE’s		66,810				389,000			455,810			864,648				723,042			1,587,690

Proved developed reserves at December 31, 2016 consisted of approximately 42% oil and 58% natural gas and totaled 879.8 MBOEs. Proved developed reserves for December 31, 2017 consisted of approximately 100% oil and totaled 66.8 MBOEs. Proved undeveloped reserves for December 31, 2016 were 707.8 MBOEs. Proved undeveloped reserves at December 31, 2017 were 389.0 MBOEs.

The Company annually reviews its proved undeveloped reserves to ensure an appropriate plan for development exists. The Company books proved undeveloped reserves only if it plans to convert these reserves to proved developed producing reserves within five years from the date they were first booked. At December 31, 2017 proved undeveloped reserves were approximately 389.0 MBOE’s. The Company plans to develop all the remaining locations that comprise the 389.0 MBOE of proved undeveloped reserves within five years. However, the decision to deploy capital and the timing of those expenditures is contingent on many different factors. The Company estimates capital expenditures of approximately $5.0 million will be sufficient to develop these reserves. The development plans assume a continued improvement in commodity pricing and general market conditions within the oil and gas industry.  

The calculation of proved undeveloped reserves requires the Company to make predictions regarding future acquisitions and discoveries and the impact they may have on the Company’s overall development plan of properties it currently owns. The development plan is revised to reflect changes in the oil and gas industry, including changing markets and prices, and new investment opportunities, and such revisions will result in changes to our proved undeveloped reserves. Consequently, the exact timing of capital expenditures will be heavily dependent upon the Company’s interpretation of market opportunities which are deeply influenced by projections of future commodity prices. Each year we will review our five year development plan to maximize the value of our investment in oil and gas assets and in turn maximize shareholder value. At December 31, 2017 we believe the following best characterizes our development plan.

	Estimated Conversion of Proved Undeveloped Reserves
	CAPEX ($MM)		MBOE’s
2018		648.0		77.5
2019		965.9		93.5
2020		1,244.8		80.7
2021		563.8		37.5
2022		1550.6		99.7

For the year ended December 31, 2017 proved reserves decreased 1,131.9 MBOEs of which production accounted for 33.9 MBOEs or 3.0% of the decrease. The disposition of assets included in the Loan Sale Agreement (“LSA”) transaction resulted in a 1,305.5 MBOE decrease. An offsetting increase of 207.5 MBOEs, was due primarily to decreases in commodity prices. Crude oil prices increased $0.63 or 1%. Increased commodity pricing triggered positive revisions of 139.0 MBOEs of crude oil classified as proved undeveloped. In 2017 there were no material transfers from the proved undeveloped category of 6 reserves to the proved developed category

For the year ended December 31, 2016 proved reserves decreased 987.1 MBOEs of which production accounted for 66.6 MBOEs or 6.7% of the decrease. The remaining decrease of 920.6 MBOEs, was due primarily to decreases in commodity prices. Crude oil prices decreased $3.49 or 8% and natural gas prices declined 20% or $.37. Diminished commodity pricing triggered negative revisions of 898.9 MBOEs of crude oil classified as proved developed producing. Natural gas liquids decreased pricing resulted in decreases of 3.6 MBOEs to the proved developed producing category. Reduced natural gas prices also reduced amounts classified as proved developed producing by 108.6 MMCF’s. In 2016 there were no material transfers from the proved undeveloped category of 6 reserves to the proved developed category

In 2017 the Company invested approximately $4,600 in its oil and gas properties. These reduced expenditures were in response to extremely low commodity prices. The Company has approximately $1.0 million of current asset on hand 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 challenges but the Company maintains its belief that reserves will be 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 its proved undeveloped reserves within the five year time frames required; utilizing its balance sheet, to borrow funds as needed. Additionally, the Company believes it 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,
	2017			2016
Future production revenue	$	20,714,780		$	30,085,550
Future production costs		(6,669,980	)		(15,278,990	)
Future development costs		(4,973,120	)		(4,703,230	)
Future cash flows before income tax		9,071,680			10,103,330
Future income taxes		—			—
Future net cash flows		9,071,680			10,103,330
10% annual discount for estimating of future cash flows		(7,603,140	)		(6,666,300	)
Standardized measure of discounted net cash flows	$	1,468,540		$	3,437,030

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,
	2017			2016
Balance beginning of year	$	3,437,030		$	8,769,970
Sales, net of production costs		34,942			199,531
Net change in pricing and production costs		16,312,304			(2,012,883	)
Net change in future estimated development costs		269,890			(1,198,430	)
Purchase of minerals in place		—			—
Extensions and discoveries		—			—
LSA Disposition		(1,902,726	)		—
Revisions		(17,693,233	)		(4,538,173	)
Accretion of discount		1,010,333			2,217,015
Change in income tax		—			—
Balance end of year	$	1,468,540		$	3,437,030

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Summary of Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

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.

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, 2017 and 2016. 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, 2017. 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, 2017 are the years ended December 31, 2014, 2015 and 2016. Tax years ending prior to 2014 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, 2017, Fixed Assets consisted of furniture and equipment of $773,707 and building and leasehold improvements of $23,069, as well as accumulated depreciation of furniture and fixtures of $597,692 and accumulated depreciation of building and leasehold improvements of $20,969.

At December 31, 2016, Fixed Assets consisted of vehicles $355,886, furniture and equipment of $795,563, building and leasehold improvements of $23,069 and gathering and compression systems of $2,720,247, as well as accumulated depreciation of vehicles of $336,083, accumulated depreciation of furniture and fixtures of $532,190, accumulated depreciation of building and leasehold improvements of $17,515 and accumulated depreciation of gathering and compression systems of $931,923. 

 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, 2016 impairment charges of $8,032,670 were recorded. For the year ended December 31, 2017, no impairment charges were recorded.

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.

On February 10, 2017, the Company and the other Sellers entered into and completed the transactions contemplated by the LSA, described in greater detail in “Note 2 – Going Concern” – “Financing Transactions”.

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, 2017, and 2016 we sold our produced crude oil to ARM Energy Management, LLC, Coffeyville Resources Inc., 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 at December 31, 2016, the carrying value of this security was $210,990. During 2017 the security was transferred as part of the LSA transaction (described below).

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 and preferred stock 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, 2016, 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.

Reclassifications

Reclassifications

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

Recent Accounting Pronouncements

Recent Accounting Pronouncements Adopted by the Company

In July 2017, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2017-11, “Earnings Per Share (Topic 260); Distinguishing Liabilities from Equity (Topic 480); Derivatives and Hedging (Topic 815): (Part 1) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Non-public Entities and Certain Mandatorily Redeemable Non-controlling Interests with a Scope Exception” (“ASU 2017-11”). Part I relates to the accounting for certain financial instruments with down round features in Subtopic 815-40, which is considered in determining whether an equity-linked financial instrument qualifies for a scope exception from derivative accounting. Down round features are features of certain equity-linked instruments (or embedded features) that result in the strike price being reduced based on the pricing of future equity offerings. An entity still is required to determine whether instruments would be classified as equity under the guidance in Subtopic 815-40 in determining whether they qualify for that scope exception. If they do qualify, freestanding instruments with down round features are no longer classified as liabilities. ASU 2017-11 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. Early adoption is permitted, including in an interim period. The Company early adopted ASU 2017-11 during the year ended December 31, 2017. The Company had no cumulative effect of the change in accounting principle on the Company’s Consolidated Balance Sheets as of the beginning of 2017.

Recent Accounting Pronouncements Applicable to the Company

In May 2014, the FASB issued (ASU) No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which supersedes nearly all existing revenue recognition guidance under GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five- step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing GAAP. The guidance is effective for annual and interim periods beginning after December 15, 2017. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The Company plans to adopt this guidance effective January 1, 2018 using the modified retrospective method applied to contracts that are not completed as of that date. The Company has not identified changes to its revenue recognition policies that would result in a material adjustment to the opening balance of retained earnings on January 1, 2018. Adopting this guidance will result in increased disclosures related to revenue recognition policies and disaggregation of revenue in future disclosures in the Company’s Consolidated Financial Statements. As allowed by the practical expedients under Topic 606, the Company does not plan to provide expanded disclosures with respect to the value of unsatisfied performance obligations for contracts with variable consideration or with an original term of one year or less. 

In February 2016, the FASB issued ASU 2016-02, a new lease standard requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous U.S. GAAP. The guidance is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company will be required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements. The Company is currently evaluating the impact of adopting this standard on its consolidated financial statements.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230). ASU 2016-15 seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The Company plans to adopt this guidance effective January 1, 2018. The Company has not identified any changes that upon adoption will have a material effect on its cash flows.

In May 2017, the FASB issued ASU 2017-09, “Compensation-Stock Compensation (Topic 718): Scope of Modification Accounting”, which provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. ASU 2017-09 is effective for annual periods beginning after December 15, 2017, with early adoption permitted, including adoption in any interim period for which financial statements have not yet been issued. The Company plans to adopt this guidance effective January 1, 2018. The Company has not identified any changes that upon adoption will have a material effect on its consolidated financial statements.

The FASB issued ASU 2017-05, “Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic: 610-20): Clarifying the Scope of Asset Derecognition Guidance and the Accounting for Partial Sales of Nonfinancial Assets,” which helps filers determine the guidance applicable for gain/loss recognition subsequent to the adoption of ASU 2014-09, Revenue from Contracts with Customers. The amendments also clarify that the derecognition of all businesses except those related to conveyances of oil and gas rights or contracts with customers should be accounted for in accordance with the derecognition and deconsolidation guidance in Topic 810, Consolidation. The Company adopted the ASU on January 1, 2018, using the modified retrospective transition method. Under this transition method the Company may elect to apply this guidance retrospectively either to all contracts at the date of initial application or only to contracts that are not completed contracts at the date of initial application. The Company elected to evaluate only contracts that are not completed contracts. As there were no not completed contracts at January 1, 2018, there was no impact to the Company’s consolidated financial statements and related disclosures upon adoption.

Recent Accounting Pronouncements Not Yet Adopted. The FASB issued ASU 2016-02, “Leases (Topic 842),” which requires companies to recognize the assets and liabilities for the rights and obligations of all leases with a term greater than 12 months (long-term) on the balance sheet. Leases to explore for or use minerals, oil and natural gas are not impacted by this guidance. In January 2018, the FASB issued ASU 2018-01, “Leases (Topic 842), Land Easement Practical Expedient for Transition to Topic 842.” This ASU permits an entity to continue to apply its current accounting policy for land easements that existed before the effective date of Topic 842. Once an entity adopts Topic 842, it would apply that Topic prospectively to all new (or modified) land easements to determine whether the arrangement contains a lease. Topic 842 requires adoption by application of a modified retrospective transition approach and is effective for the Company on January 1, 2019. Early adoption is permitted.

The Company is in the process of reviewing its portfolio of leased assets and related contracts to determine the impact that adoption will have on its consolidated financial statements and related disclosures. The Company is also assessing the impact of Topic 842 on its systems, processes and internal controls. The Company plans to elect certain practical expedients when implementing the new lease standard, which means the Company will not have to reassess the existence or classification of leases for contracts, including land easements that commenced prior to adoption. The Company anticipates upon adoption to recognize assets and liabilities for the rights and obligations of its existing long-term operating leases on its consolidated balance sheets and to utilize new systems, processes and internal controls to properly identify, classify, measure and recognize new (or modified) leases after the date of adoption. The Company will complete its evaluation during 2018 and will adopt Topic 842 on January 1, 2019, using a modified retrospective approach for all comparative periods presented.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. This new standard clarifies the definition of a business and provides a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This new standard will be effective for the Company on January 1, 2018; however, early adoption is permitted with prospective application to any business development transaction.

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Equity Transactions (Tables)

12 Months Ended

Dec. 31, 2017

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, 2016		288,331		$	10.17			1,904,286		$	2.75
Granted		—			—			—			—
Cancelled		(80,667	)		(7.15	)		—			—
Exercised		—			—			—			—
Outstanding December 31, 2016		207,664		$	9.69			1,904,286		$	2.75
Granted		—			—			—			—
Cancelled		—			—			—			—
Exercised		(192,332	)		10.5			(1,771,428	)		0.30
Outstanding December 31, 2017		15,332		$	7.63			132,858		$	0.30

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Asset Retirement Obligation (Tables)

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Changes in Asset Retirement Obligations

The following shows the changes in asset retirement obligations:

Asset retirement obligations, January 1, 2016	$	3,091,478
Liabilities incurred during the period		—
Liabilities settled during the year		(2,767	)
Accretion		225,480
Asset retirement obligations, December 31, 2016	$	3,314,191
Release of liabilities		(1,814,408	)
Liabilities incurred during the period		—
Liabilities settled during the year		—
Accretion		112,062
Asset retirement obligations, December 31, 2017	$	1,611,845

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Schedule of the reconciliation of the gain on LSA to statement of operations

Below is a table showing the reconciliation of the gain on LSA as set forth on the statement of operations for the year ended December 31, 2017:

Forgiveness of existing secured loan	$	17,925,000
Forgiveness of accrued interest		1,306,801
Issuance of secured promissory note		(4,500,000	)
Transfer of oil and gas properties		(1,902,726	)
Transfer of gas gathering system		(1,772,588	)
Transfer of shares of Oakridge Energy, Inc.		(210,990	)
Transfer of ARO liability		1,814,407
Transfer of other assets		(1,159,780	)
Gain on LSA	$	11,500,124

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

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,
	2017			2016
Statutory tax rate		35.00	%		35.00	%
State tax rate, net of federal tax		2.01	%		1.78	%
Other permanent items		0.00	%		0.00	%
Change in valuation allowance		(37.01	)%		(36.78	)%
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,
	2017			2016
Non-current deferred tax asset:
Oil and gas costs and long-lived assets	$	4,764,420		$	11,500,697
Derivative instruments		—			—
Net operating loss carry-forward		21,547,347			35,815,113
Valuation allowance		(26,311,767	)		(47,315,809	)
Net deferred tax asset (liability)	$	—		$	—

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Other Income (Tables)

12 Months Ended

Dec. 31, 2017

Other Income and Expenses [Abstract]

Schedule of components of other income

The following table depicts the components of other income for the years ended December 31, 2017 and December 31, 2016:

	Year ended December 31, 2017			Year ended December 31, 2016
Realized gain (loss) clearing of derivative contracts	$	—		$	2,382,184
Service Agreement with Camber Energy, Inc.		696,774			—
Miscellaneous income		72			24,124
Interest income		(3,967	)		32
Other income (loss)	$	692,879		$	2,406,340

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Supplemental Oil and Gas Reserve Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2017

Supplemental Oil Reserve Information [Abstract]

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.  

	Year Ended			Year Ended
	December 31,			December 31,
	2017			2016
Production revenues	$	1,329,005		$	2,461,727
Production costs		(1,363,946	)		(2,661,258	)
Depletion and depreciation		(127,713	)		(254,329	)
Income tax		56,929			158,851
Results of operations for producing activities	$	(105,725	)	$	(295,009	)

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,
	2017			2016
Properties subject to amortization	$	10,008,764		$	18,626,746
Accumulated depletion		(8,597,539	)		(15,189,716	)
Net capitalized costs	$	1,411,225		$	3,437,030

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,
	2017		2016
Acquisition of properties	$	—	$	14,399
Exploration costs		—		—
Development costs		—		2,690
Net capitalized costs	$	—	$	17,089

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.

				December 31, 2017										December 31, 2016
Proved Reserves	Total Proved Developed				Proved Undeveloped			Total Proved			Total Proved Developed				Proved Undeveloped			Total Proved
Beginning
Crude Oil BBL’s		372,140				152,610			524,750			1,287,028				202,884			1,489,912
Natural Gas Liquids BBL’s		44,780				—			44,780			47,345				—			47,345
Natural Gas MCF’s		2,686,805				3,422,165			6,108,970			3,195,895				3,029,514			6,225,409
Oil Equivalents BOE’s		864,648				723,042			1,587,690			1,867,041				707,819			2,574,860
Revisions of previous estimates
Crude Oil BBL’s		(30,572	)			236,390			205,818			(856,765	)			(50,274	)		(907,039	)
Natural Gas Liquids BBL’s		1,870				—			1,870			(2,127	)			—			(2,127	)
Natural Gas MCF’s		(1,491	)			—			(1,491	)		(461,536	)			392,651			(68,885	)
Oil Equivalents BOE’s		(28,876	)			236,390			207,514			(935,815	)			15,169			(920,638	)
LSA Disposition
Crude Oil BBL’s		(242,924	)			—			(242,924	)		—				—			—
Natural Gas Liquids BBL’s		(44,709	)			—			(44,709	)		—				—			—
Natural Gas MCF’s		(2,684,865	)			(3,422,165	)		(6,107,030	)		—				—			—
Oil Equivalents BOE’s		(735,110	)			(570,432	)		(1,305,542	)		—				—			—
Production
Crude Oil BBL’s		—				—			—			—				—			—
Production
Crude Oil BBL’s		(31,834	)			—			(31,824	)		(58,123	)			—			(58,123	)
Natural Gas Liquids BBL’s		(1,941	)			—			(1,941	)		(528	)			—			(528	)
Natural Gas MCF’s		(449	)			—			(449	)		(47,554	)			—			(47,554	)
Oil Equivalents BOE’s		(33,851	)			—			(33,851	)		(66,578	)			—			(66,578	)
Ending
Crude Oil BBL’s		66,810				389,000			455,810			372,140				152,610			524,750
Natural Gas Liquids BBL’s		—				—			—			44,780				—			44,780
Natural Gas MCF’s		—				—			—			2,686,805				3,422,165			6,108,970
Oil Equivalents BOE’s		66,810				389,000			455,810			864,648				723,042			1,587,690

Schedule of plan for developing undeveloped oil and gas properties

At December 31, 2017 we believe the following best characterizes our development plan.

	Estimated Conversion of Proved Undeveloped Reserves
	CAPEX ($MM)		MBOE’s
2018		648.0		77.5
2019		965.9		93.5
2020		1,244.8		80.7
2021		563.8		37.5
2022		1550.6		99.7

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,
	2017			2016
Future production revenue	$	20,714,780		$	30,085,550
Future production costs		(6,669,980	)		(15,278,990	)
Future development costs		(4,973,120	)		(4,703,230	)
Future cash flows before income tax		9,071,680			10,103,330
Future income taxes		—			—
Future net cash flows		9,071,680			10,103,330
10% annual discount for estimating of future cash flows		(7,603,140	)		(6,666,300	)
Standardized measure of discounted net cash flows	$	1,468,540		$	3,437,030

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.

	Year Ended			Year Ended
	December 31,			December 31,
	2017			2016
Balance beginning of year	$	3,437,030		$	8,769,970
Sales, net of production costs		34,942			199,531
Net change in pricing and production costs		16,312,304			(2,012,883	)
Net change in future estimated development costs		269,890			(1,198,430	)
Purchase of minerals in place		—			—
Extensions and discoveries		—			—
LSA Disposition		(1,902,726	)		—
Revisions		(17,693,233	)		(4,538,173	)
Accretion of discount		1,010,333			2,217,015
Change in income tax		—			—
Balance end of year	$	1,468,540		$	3,437,030

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Summary of Accounting Policies - (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Summary Of Accounting Policies [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		298,664
Property, Plant and Equipment, Gross, Total	$ 178,115	$ 2,077,055
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	618,661	1,817,711
Asset Impairment Charges, Total		8,032,670
Cash and Cash Equivalents, at Carrying Value, Total	$ 677,936	128,035	$ 3,101,682
Minimum [Member]
Summary Of Accounting Policies [Line Items]
Property, Plant and Equipment, Useful Life	3 years
Maximum [Member]
Summary Of Accounting Policies [Line Items]
Property, Plant and Equipment, Useful Life	15 years
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
Furniture And Equipment [Member]
Summary Of Accounting Policies [Line Items]
Property, Plant and Equipment, Gross, Total	$ 773,707	795,563
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	597,692	532,190
Building And leasehold Imrovement [Member]
Summary Of Accounting Policies [Line Items]
Property, Plant and Equipment, Gross, Total	23,069	23,069
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	$ 20,969	17,515
Gas Gathering and Processing Equipment [Member]
Summary Of Accounting Policies [Line Items]
Property, Plant and Equipment, Gross, Total		2,720,247
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment		931,923
Vehicles [Member]
Summary Of Accounting Policies [Line Items]
Property, Plant and Equipment, Gross, Total		355,886
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment		336,083
Available-for-sale Securities [Member]
Summary Of Accounting Policies [Line Items]
Cash and Cash Equivalents, at Carrying Value, Total		$ 210,990

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Going Concern (Details Narrative) - USD ($)			1 Months Ended	12 Months Ended
	Dec. 22, 2017	Nov. 21, 2017	Feb. 10, 2017	Dec. 31, 2017	Dec. 31, 2016	Sep. 30, 2017	May 10, 2017	May 01, 2017
Accumulated Deficit				$ (86,429,760)	$ (87,577,862)
Cash flows used in operating activities				$ (1,241,489)	$ (2,098,645)
Percentage of converted right				85.00%
Amount of new equity capital issued			$ 5,000,000
Amount of fraud intentional misrepresentation				$ 350,000
Approved of investors issued and outstanding				19.90%
Face amount			$ 17,295,000
Number of days from closing			5 days
Return on cash purchase price (percent)			150.00%
Series A Preferred Stock [Member]
Accrued unpaid dividends				$ 3,518,430		$ 6,039,972
Accrued of dividends				6,919,579		$ 241,599
Merger Agreement [Member]
Amount of working capital				4,000,000
Payment of non-refundable fee				50,000
Common stock of deposit				$ 1,215,278
Merger Agreement [Member] | Series A Preferred Stock [Member]
Percentage of converted right				15.00%
Percent of voting right				66.70%
Pass Creek Resources LLC [Member] | First Amendment Restated Credit Agreement [Member]
Administrative agent additional fees	$ 7,500
Extension fee	65,000
Debt Instrument fees	300,000
Pass Creek Resources LLC [Member] | Second Amendment Restated Credit Agreement [Member]
Administrative agent additional fees	45,000
Extension fee	$ 50,000
Cortland Capital Market Services LLC [Member] | Second Amended and Restated Credit Agreement [Member]
Amount of indebtedness							$ 4,500,000
Alpha Capital Anstalt [Member] | Merger Agreement [Member] | Private Placement [Member] | Maximum [Member]
Pre-money valuation of new equity capital issued		$ 25,000,000
Alpha Capital Anstalt [Member] | Merger Agreement [Member] | Private Placement [Member] | Minimum [Member]
Amount of new equity capital issued		4,000,000
Pre-money valuation of new equity capital issued		$ 16,000,000
Restated Secured Note [Member]
Face amount			$ 4,500,000
Debt Instrument, Interest Rate, Stated Percentage			16.00%					16.00%
Unamortized discount			$ 3,300,000
Debt Instrument fees			$ 50,000
16% Promissory Note Due on June 9 2017[Member] | Pass Creek Resources LLC [Member]
Face amount							105,806
New Note [Member] | New Credit Agreement [Member]
Face amount							$ 3,300,000
IberiaBank [Member]
Percent of payment allocation (percent)			34.21053%
TCB [Member]
Percent of payment allocation (percent)			65.78947%

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Equity Transactions (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Options
Options Outstanding, Beginning Balance	207,664	288,331
Options Exercised	(192,332)	(80,667)
Options Outstanding, Ending Balance	15,332	207,664
Weighted Avg. Exercise Price
Weighted Avg. Exercise Price Outstanding, Beginning Balance	$ 9.69	$ 10.17
Weighted Avg. Exercise Price Cancelled	(10.5)	(7.15)
Weighted Avg. Exercise Price Outstanding, Ending balance	$ 7.63	$ 9.69
Warrants
Warrants Outstanding, Beginning Balance	1,904,286	1,904,286
Warrants Exercised	(1,771,428)
Warrants Outstanding, Ending Balance	132,858	1,904,286
Weighted Avg. Exercise Price
Weighted Avg. Exercise Price Outstanding, Beginning Balance	$ 2.75	$ 2.75
Weighted Avg. Exercise Price Cancelled	0.30
Weighted Avg. Exercise Price Outstanding, Ending balance	$ 0.30	$ 2.75

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Equity Transactions (Details Narrative) - USD ($)					3 Months Ended	12 Months Ended
	Mar. 21, 2018	Feb. 13, 2018	Dec. 20, 2017	Apr. 27, 2017	Mar. 21, 2018	Dec. 31, 2017	Nov. 06, 2017	Oct. 23, 2017	Sep. 30, 2017	Dec. 31, 2016	Mar. 11, 2015
Issuance of stock						$ 949,791
Deemed distribution for beneficial conversion of preferred stock						208,500
Deemed dividend for anti-dilution provision						$ (3,400,000)
Series B Convertible Preferred Stock [Member]
Preferred Stock, shares outstanding						352				1,764
Series B Convertible Preferred Stock [Member] | Securities Purchase Agreement [Member]
Convertible shares						3,333					571
Preferred stock converted (shares)						1,412
Deemed dividend for anti-dilution provision						$ 2,500,000
Series C Convertible Preferred Stock [Member]
Issuance of stock (shares)						300
Issuance of stock						$ 300,000
Series C convertible preferred stock issuable						$ 200,000
Preferred stock, shares issuable						200
Preferred Stock, shares outstanding						300
Liquidation preference value						$ 1,000
Conversion price						0.30
Redemption price						$ 1,000
Beneficial ownership limitation (percent)						9.99%
Convertible shares						3,333
Series C Convertible Preferred Stock [Member] | Maximum [Member]
Preferred Stock, shares outstanding						1,683,944
Series A Preferred Stock [Member]
Preferred Stock, shares outstanding						1,999,998				938,248
Accumulated dividends						$ 6,919,579			$ 241,599
Dividends declared						3,518,430
Accrued dividend payable						$ 3,518,430			$ 6,039,972
Alpha Capital Anstalt [Member] | Common Stock [Member]
Stock issued upon conversion of preferred stock (shares)						5,502,066
Alpha Capital Anstalt [Member] | Warrant [Member]
Convertible shares							771,428	1,000,000
Number of warrant issued							771,428	1,000,000
Exercise price							$ 0.30	$ 0.30
Aggregate exercise price of warrant issued							$ 231,429	$ 300,000
Alpha Capital Anstalt [Member] | Stock Purchase Agreement [Member]
Issuance of stock (shares)			1,061,750
Issuance of stock			$ 649,791
Conversion price			$ 0.0612
Deemed dividend for anti-dilution provision			$ 100,000
Alpha Capital Anstalt [Member] | Series C Convertible Preferred Stock [Member]
Issuance of stock (shares)						150
Issuance of stock						$ 200,000
Beneficial conversion feature of preferred stock						$ 208,500
Alpha Capital Anstalt [Member] | Series C Convertible Preferred Stock [Member] | Additional Issuance Agreement - Option [Member]
Option to purchase stock				$ 200
Option to purchase stock (shares)				200,000
Alpha Capital Anstalt [Member] | Series C Convertible Preferred Stock [Member] | Additional Issuance Agreement [Member]
Issuance of stock (shares)				300
Issuance of stock				$ 300,000
Alpha Capital Anstalt [Member] | Common Stock [Member] | Securities Purchase Agreement [Member]
Issuance of stock (shares)						597,461
Deemed dividend for anti-dilution provision						$ 300,000
Subsequent Event [Member] | Series A Preferred Stock [Member]
Stock issued upon conversion of preferred stock (shares)	10
Preferred stock converted (shares)	1
Subsequent Event [Member] | Alpha Capital Anstalt [Member] | Series B Convertible Preferred Stock [Member]
Stock issued upon conversion of preferred stock (shares)					5,610,955
Preferred stock converted (shares)					343.671
Subsequent Event [Member] | Alpha Capital Anstalt [Member] | Series C Convertible Preferred Stock [Member]
Stock issued upon conversion of preferred stock (shares)					1,683,944
Preferred stock converted (shares)					103.142
Subsequent Event [Member] | Alpha Capital Anstalt [Member] | Series C Convertible Preferred Stock [Member] | Additional Issuance Agreement - Option [Member]
Issuance of stock (shares)		200,000
Issuance of stock		$ 200,000

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Equity Transactions (Details Narrative 1) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Oct. 14, 2008	Sep. 30, 2007	Aug. 01, 2002
Payments of Stock Issuance Costs	$ 13,690
Stock Incentive Plans [Member]
Common Stock, Capital Shares Reserved for Future Issuance	333,300
Stock Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized			83,333
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
Officer [Member]
Share Based Compensation Arrangements By Share Based Payment Award Options Amount Recognized As Expenses	$ 0	$ 0
Employee Stock Option [Member]
Payments of Stock Issuance Costs		$ 241,669

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Asset Retirement Obligation (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations, Beginning	$ 3,314,191	$ 3,091,478
Liabilities incurred during the period
Release of liabilities	(1,814,408)
Liabilities settled during the year		(2,767)
Accretion	112,062	225,480
Asset retirement obligations, Ending	$ 1,611,845	$ 3,314,191

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Long-Term Debt (Details)	12 Months Ended
	Dec. 31, 2017 USD ($)
Debt Disclosure [Abstract]
Forgiveness of existing secured loan	$ 17,925,000
Forgiveness of accrued interest	1,306,801
Issuance of secured promissory note	(4,500,000)
Transfer of oil and gas properties	(1,902,726)
Transfer of gas gathering system	(1,772,588)
Transfer of shares of Oakridge Energy, Inc.	(210,990)
Transfer of ARO liability	1,814,407
Transfer of other assets	(1,159,780)
Gain on LSA	$ 11,500,124

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Long-Term Debt (Details Narrative) - USD ($)			1 Months Ended		2 Months Ended	12 Months Ended
	Dec. 22, 2017	Aug. 12, 2015	May 22, 2014	Sep. 30, 2013	Aug. 30, 2017	Dec. 31, 2017	May 10, 2017	May 01, 2017	Feb. 10, 2017	May 01, 2015	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												$ 19,500,000
Proceeds from potential future securities offering unencumbered by Banks' Liens										$ 1,000,000
Face amount									$ 17,295,000
Federal Funds Rate [Member] | Line Of Credit [Member]
Debt Instrument [Line Items]
Debt instrument interest rate, margin						0.50%
Base Rate [Member] | Line Of Credit [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt instrument interest rate, margin						0.75%
Base Rate [Member] | Line Of Credit [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt instrument interest rate, margin						0.00%
Floating Rate [Member] | Line Of Credit [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt instrument interest rate, margin						3.00%
Floating Rate [Member] | Line Of Credit [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt instrument interest rate, margin						2.25%
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
Seven Amendment [Member] | Series A Cumulative Redeemable Perpetual Preferred Stock [Member]
Debt Instrument [Line Items]
Percentage of dividend rate			10.00%
Preferred stock shares issued			850,000
Fifth Amendment [Member]
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity				$ 100,000,000
Line of credit facility, current borrowing capacity				$ 38,000,000
Fifth Amendment [Member] | Federal Funds Rate [Member] | Line Of Credit [Member]
Debt Instrument [Line Items]
Debt instrument interest rate, margin				3.30%
Eight amendment [Member] | Maximum [Member]
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity											$ 40,000,000
Eight amendment [Member] | Minimum [Member]
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity											$ 38,000,000
Third Amendment [Member]
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity													$ 12,150,000
Second Amendment [Member]
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity														$ 7,000,000
Second Amendment [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage														3.75%
Rantoul Partners [Member] | First Amendment [Member]
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity															$ 50,000,000
Cortland Capital Market Services LLC [Member] | Second Amended and Restated Credit Agreement [Member]
Debt Instrument [Line Items]
Amount of indebtedness							$ 4,500,000
Pass Creek Resources LLC [Member] | First Amendment Restated Credit Agreement [Member]
Debt Instrument [Line Items]
Administrative agent additional fees	$ 7,500
Extension fee	65,000
Debt Instrument fees	300,000
Pass Creek Resources LLC [Member] | Second Amendment Restated Credit Agreement [Member]
Debt Instrument [Line Items]
Administrative agent additional fees	45,000
Extension fee	$ 50,000
Pass Creek Resources LLC [Member] | Amendment Restated Credit Agreement [Member]
Debt Instrument [Line Items]
Amount of interest payment						$ 479,452
Promissory Note [Member] | Pass Creek Resources LLC [Member] | Amendment Restated Credit Agreement [Member]
Debt Instrument [Line Items]
Amount of interest payment						9,616
Promissory Note [Member] | Robert Watson [Member]
Debt Instrument [Line Items]
Carrying amount						113,750
Accrued interest						5,574
Promissory Notes [Member] | Alpha Capital Anstalt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage					8.00%
Face amount					$ 225,000
Carrying amount						$ 225,000
Maturity date					Jun. 30, 2018
Conversion price of debt					$ 0.0612
Restated Secured Note [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage								16.00%	16.00%
Face amount									$ 4,500,000
Debt Instrument fees									$ 50,000
New Note [Member] | New Credit Agreement [Member]
Debt Instrument [Line Items]
Face amount							$ 3,300,000

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Commitments & Contingencies (Details Narrative) - USD ($)		12 Months Ended
	Apr. 26, 2016	Dec. 31, 2017	Dec. 31, 2016
Commitments and Contingencies Disclosure [Line Items]
Operating Leases, Rent Expense		$ 69,000	$ 148,000
Operating Leases, Future Minimum Payments, Remainder of Fiscal Year		10,000
Texas Railroad Commission [Member]
Commitments and Contingencies Disclosure [Line Items]
Letters of Credit Outstanding, Amount		$ 50,000
CAndF Ranch LLC [Member]
Commitments and Contingencies Disclosure [Line Items]
Dispute settlement of breach of contract related to rental lands	$ 9,000

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Income Taxes (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Statutory tax rate	35.00%	35.00%
State tax rate, net of federal tax	2.01%	1.78%
Other permanent items	0.00%
Change in valuation allowance	(37.01%)	(36.78%)
Effective tax rate	0.00%	0.00%

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Income Taxes (Details 1) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Non-current deferred tax asset:
Oil and gas costs and long-lived assets	$ 4,764,420	$ 11,500,697
Derivative instruments	0
Net operating loss carry-forward	21,547,347	35,815,113
Valuation allowance	(26,311,767)	(47,315,809)
Net deferred tax asset (liability)

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Income Taxes (Details Narrative) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 22, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Loss Carryforwards		$ 93,000,000
Limitations On Use Operating Loss Carryforwards		$ 40,900,000
Statutory tax rate		35.00%	35.00%
Deferred tax assets		$ 18,000,000
Subsequent Event [Member]
Statutory tax rate	21.00%

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Fair Value Measurements (Details Narrative) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Marketable Securities		$ 210,990
Fair Value Inputs Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Marketable Securities	$ 0

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Derivative Instruments (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Loss on Derivative Instruments, Pretax	$ 0	$ 2,531,401

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Impairment of Oil and Gas Properties (Details Narrative)	3 Months Ended	6 Months Ended	9 Months Ended	12 Months Ended
	Mar. 31, 2017 bbl	Jun. 30, 2017 bbl	Sep. 30, 2017 bbl	Dec. 31, 2017 USD ($) bbl	Dec. 31, 2016 USD ($)
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil Price Per Barrel	45.16	42.46	42.46	51.34
Natural Gas Price Per MMBtu	2.40	2.63	2.63	2.97
Write-down of oil and gas properties | $					$ 8,032,670

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Other Income (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Other Income and Expenses [Abstract]
Realized gain (loss) clearing of derivative contracts		$ 2,382,184
Service Agreement with Camber Energy, Inc.	$ 696,774
Miscellaneous income	72	24,124
Interest income	(3,967)	32
Other Income (loss)	$ 692,879	$ 2,406,340

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Other Income (Details Narrative)	Apr. 27, 2017 USD ($)
Service Agreement [Member]
Interest And Other Income [Line Items]
Interim services per month	$ 150,000

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Subsequent Events (Details Narrative)			3 Months Ended	12 Months Ended
	Mar. 21, 2018 USD ($) shares	Feb. 13, 2018 USD ($) shares	Mar. 21, 2018 shares	Dec. 31, 2017 USD ($) shares
Issuance of stock | $				$ 949,791
Conversion of debt amount | $				$ 113,750
Series C Convertible Preferred Stock [Member]
Issuance of stock (shares)				300
Issuance of stock | $				$ 300,000
Alpha Capital Anstalt [Member] | Series C Convertible Preferred Stock [Member]
Issuance of stock (shares)				150
Issuance of stock | $				$ 200,000
Subsequent Event [Member]
Issuance of common stock to officers and directors	2,248,264
Reverse stock split	.04
Subsequent Event [Member] | EnerJex 2017 Equity Incentive Plan[Member]
Shares authorized under plan	2,000,000		2,000,000
Subsequent Event [Member] | Series A Preferred Stock [Member]
Common stock issued upon conversion of preferred stock (shares)	10
Preferred stock converted (shares)	1
Additional shares authorized	241,599
Subsequent Event [Member] | Alpha Capital Anstalt [Member] | Promissory Notes [Member]
Conversion of debt amount | $	$ 425,000
Subsequent Event [Member] | Alpha Capital Anstalt [Member] | Series C Convertible Preferred Stock [Member]
Common stock issued upon conversion of preferred stock (shares)			1,683,944
Preferred stock converted (shares)			103.142
Subsequent Event [Member] | Alpha Capital Anstalt [Member] | Series B Convertible Preferred Stock [Member]
Common stock issued upon conversion of preferred stock (shares)			5,610,955
Preferred stock converted (shares)			343.671
Subsequent Event [Member] | Alpha Capital Anstalt [Member] | Additional Issuance Agreement - Option [Member] | Series C Convertible Preferred Stock [Member]
Issuance of stock (shares)		200,000
Issuance of stock | $		$ 200,000

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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, 2017	Dec. 31, 2016
Supplemental Oil Reserve Information [Abstract]
Production revenues	$ 1,329,005	$ 2,461,727
Production costs	(1,363,946)	(2,661,258)
Depletion and depreciation	(127,713)	(254,329)
Income tax	56,929	158,851
Results of operations for producing activities	$ (105,725)	$ (295,009)

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Supplemental Oil and Gas Reserve Information (Unaudited) (Details 1) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Supplemental Oil Reserve Information [Abstract]
Properties subject to amortization	$ 10,008,764	$ 18,626,746
Accumulated depletion	(8,597,539)	(15,189,716)
Net capitalized costs	$ 1,411,225	$ 3,437,030

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Supplemental Oil and Gas Reserve Information (Unaudited) (Details 2)	12 Months Ended
	Dec. 31, 2016 USD ($)
Supplemental Oil Reserve Information [Abstract]
Acquisition of properties	$ 14,399
Development costs	2,690
Net capitalized costs	$ 17,089

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Supplemental Oil and Gas Reserve Information (Unaudited) (Details 3)	12 Months Ended
	Dec. 31, 2017 Boe bbl Mcf	Dec. 31, 2016 Boe bbl Mcf
Production	(33.9)	(66.6)
Crude Oil BBLs [Member]
Beginning	524,750	1,489,912
Revisions of previous estimates	205,818	(907,039)
LSA Disposition	(242,924)
Production	(31,824)	(58,123)
Ending	455,810	524,750
Crude Oil BBLs [Member] | Proved Developed Reserves [Member]
Beginning	372,140	1,287,028
Revisions of previous estimates	(30,572)	(856,765)
LSA Disposition	(242,924)
Production	(31,834)	(58,123)
Ending	66,810	372,140
Crude Oil BBLs [Member] | Proved Undeveloped Reserve [Member]
Beginning	152,610	202,884
Revisions of previous estimates	236,390	(50,274)
Ending	389,000	152,610
Natural Gas Liquids BBLs [Member]
Beginning	44,780	47,345
Revisions of previous estimates	1,870	(2,127)
LSA Disposition	(44,709)
Production	(1,941)	(528)
Ending		44,780
Natural Gas Liquids BBLs [Member] | Proved Developed Reserves [Member]
Beginning	44,780	47,345
Revisions of previous estimates	1,870	(2,127)
LSA Disposition	(44,709)
Production	(1,941)	(528)
Ending		44,780
Natural Gas MCFs [Member]
Beginning | Mcf	6,108,970	6,225,409
Revisions of previous estimates | Mcf	(1,491)	(68,885)
LSA Disposition | Mcf	(6,107,030)
Production | Mcf	(449)	(47,554)
Ending | Mcf		6,108,970
Natural Gas MCFs [Member] | Proved Developed Reserves [Member]
Beginning | Mcf	2,686,805	3,195,895
Revisions of previous estimates | Mcf	(1,491)	(461,536)
LSA Disposition | Mcf	(2,684,865)
Production | Mcf	(449)	(47,554)
Ending | Mcf		2,686,805
Natural Gas MCFs [Member] | Proved Undeveloped Reserve [Member]
Beginning | Mcf	3,422,165	3,029,514
Revisions of previous estimates | Mcf		392,651
LSA Disposition | Mcf	(3,422,165)
Ending | Mcf		3,422,165
Oil Equivalents BOEs [Member]
Beginning | Boe	207,514	2,574,860
Revisions of previous estimates | Boe	1,305,542	920,638
LSA Disposition | Boe	(33,851)
Production | Boe	(455,810)	66,578
Ending | Boe	1,587,690	207,514
Oil Equivalents BOEs [Member] | Proved Developed Reserves [Member]
Beginning | Boe	(28,876)	1,867,041
Revisions of previous estimates | Boe	735,110	935,815
LSA Disposition | Boe	(33,851)
Production | Boe	(66,810)	66,578
Ending | Boe	864,648	(28,876)
Oil Equivalents BOEs [Member] | Proved Undeveloped Reserve [Member]
Beginning | Boe	236,390	707,819
Revisions of previous estimates | Boe	570,432	(15,169)
Production | Boe	(389,000)
Ending | Boe	723,042	236,390

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Supplemental Oil and Gas Reserve Information (Unaudited) (Details 4)	Dec. 31, 2017 USD ($) bbl
Supplemental Oil Reserve Information [Abstract]
CAPEX 2018 | $	$ 648
CAPEX 2019 | $	965.9
CAPEX 2020 | $	1,244.8
CAPEX 2021 | $	563.8
CAPEX 2022 | $	$ 1,550.6
MBOE's 2018 | bbl	77.5
MBOE's 2019 | bbl	93.5
MBOE's 2020 | bbl	80.7
MBOE's 2021 | bbl	37.5
MBOE's 2022 | bbl	99.7

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Supplemental Oil and Gas Reserve Information (Unaudited) (Details 5) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Supplemental Oil Reserve Information [Abstract]
Future production revenue	$ 20,714,780	$ 30,085,550
Future production costs	(6,669,980)	(15,278,990)
Future development costs	(4,973,120)	(4,703,230)
Future cash flows before income tax	9,071,680	10,103,330
Future net cash flows	9,071,680	10,103,330
10% annual discount for estimating of future cash flows	(7,603,140)	(6,666,300)
Standardized measure of discounted net cash flows	$ 1,468,540	$ 3,437,030
Future Estimate Cash Flows Discount Percentage	10.00%

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Supplemental Oil and Gas Reserve Information (Unaudited) (Details 6) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Supplemental Oil Reserve Information [Abstract]
Balance beginning of year	$ 3,437,030	$ 8,769,970
Sales, net of production costs	34,942	199,531
Net change in pricing and production costs	16,312,304	(2,012,883)
Net change in future estimated development costs	269,890	(1,198,430)
LSA Disposition	(1,902,726)
Revisions	(17,693,233)	(4,538,173)
Accretion of discount	1,010,333	2,217,015
Balance end of year	$ 1,468,540	$ 3,437,030

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Supplemental Oil and Gas Reserve Information (Unaudited) - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017 USD ($) Boe bbl	Dec. 31, 2016 USD ($) Boe bbl
Percentage Of Oil For Proved Developed Reserves	100.00%	42.00%
Percentage Of Natural Gas For Proved Developed Reserves		58.00%
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease), Total	1,131.9	987.1
Proved Developed and Undeveloped Reserves, Production	33.9	66.6
Percentage of Decrease Proved Developed And Undeveloped Reserves Production	3.00%	6.70%
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates and Sales of Minerals	207.5	920.6
Payments To Acquire Oil and Gas Property | $	$ 4,632	$ 17,089
Assets, Current, Total | $	1,045,383	1,678,967
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Development Costs | $	$ 4,973,120	4,703,230
Natural Gas [Member]
Decrease in Oil and Gas Prices | $		$ 2,000
Percentage of Decrease in Oil And Gas Prices		37.00%
Proved Developed Reserves [Member]
Proved Developed and Undeveloped Reserves, Net	66.8	879.8
Oil and Gas Properties [Member]
Payments To Acquire Oil and Gas Property | $	$ 4,600
Crude Oil [Member]
Decrease in Oil and Gas Prices | $	$ 63	$ 349
Percentage of Decrease in Oil And Gas Prices	1.00%	8.00%
Proved Developed Producing Reserves [Member] | Natural Gas Liquids [Member]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates		3.6
Proved Developed Producing Reserves [Member] | Natural Gas [Member]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates		108.6
Proved Developed Producing Reserves [Member] | Crude Oil [Member]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	139.0	898.9
Proved Undeveloped Reserves [Member]
Proved Developed and Undeveloped Reserves, Net	398.0	707.8
Proved Undeveloped Reserves [Member] | Oil Equivalents [Member]
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Development Costs | $	$ 5,000	$ 4,300
Proved Developed and Undeveloped Reserve, Net (Energy), Beginning Balance | Boe	398.0	707.8