10-Q 1 v392167_10q.htm QUARTERLY REPORT

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2014

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

Commission file number 000-30234

ENERJEX RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Nevada		88-0422242
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

4040 Broadway
Suite 508
San Antonio, Texas		78209
(Address of principal executive offices)		(Zip Code)

(210) 451-5545

(Registrant's telephone number, including area code)

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

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

Large accelerated filer ¨	Accelerated filer ¨

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

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

Yes ¨ No þ

The number of shares of Common Stock, $0.001 par value, outstanding on November 14, 2014 was 7,643,114 shares.

ENERJEX RESOURCES, INC.

FORM 10-Q

TABLE OF CONTENTS

		Page
PART I FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS	2
	Condensed Consolidated Balance Sheets at September 30, 2014 (Unaudited) and December 31, 2013	2
	Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2014 and 2013 (Unaudited)	3
	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2014 and 2013 (Unaudited)	4
	Notes to Condensed Consolidated Financial Statements	5
	FORWARD-LOOKING STATEMENTS	10
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	11
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	17
ITEM 4.	CONTROLS AND PROCEDURES	17

PART II OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	17
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	18
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	18
ITEM 4.	(REMOVED AND RESERVED)	18
ITEM 5.	OTHER INFORMATION	18
ITEM 6.	EXHIBITS	18

SIGNATURES		20

PART 1 – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

Unaudited

	September 30,			December 31,
	2014			2013
Assets
Current assets:
Cash and cash equivalents	$	560,684		$	1,079,356
Restricted cash		-			228,840
Accounts receivable		1,858,251			2,461,746
Inventory		264,001			238,794
Marketable securities		1,018,673			1,018,573
Deposits and prepaid expenses		522,829			373,994
Total current assets		4,224,438			5,401,303

Non-current assets:
Fixed assets, net of accumulated depreciation of $1,909,974 and $1,785,401		2,424,199			2,406,591
Oil and gas properties using full-cost accounting, net of accumulated DD&A of $12,842,863 and $10,567,906		63,299,218			61,349,403
Other non-current assets		1,031,140			834,180
Total non-current assets		66,754,557			64,590,174
Total assets	$	70,978,995		$	69,991,477

Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	2,729,299		$	2,424,009
Accrued liabilities		1,517,634			3,070,461
Derivative liability		246,791			1,011,708
Total current liabilities		4,493,724			6,506,178

Asset retirement obligation		2,838,679			2,687,801
Long-term debt		21,019,968			31,547,255
Derivative liability		-			339,642
Total non-current liabilities		23,858,647			34,574,698
Total liabilities		28,352,371			41,080,876

Commitments & Contingencies
Stockholders' Equity:
10% Series A Cumulative Perpetual Preferred Stock, $0.001 par value, 25,000,000 shares authorized; 751,815 shares issued and outstanding at September 30, 2014		752			-
Preferred stock, $0.001 par value, 25,000,000 shares authorized; 4,779,460 shares issued and outstanding at December 31, 2013		-			4,780
Common stock, $0.001 par value, 250,000,000 shares authorized; shares issued and outstanding 7,643,114 at September 30, 2014 and 7,281,158 at December 31, 2013		7,643			7,281
Paid-in capital		63,670,570			49,913,535
Accumulated other comprehensive income		(552,589	)		(552,589	)
Retained (deficit)		(20,499,752	)		(20,462,406	)
Total stockholders' equity		42,626,624			28,910,601
Total liabilities and stockholders' equity	$	70,978,995		$	69,991,477

See Notes to Condensed Consolidated Financial Statements.

EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

(Unaudited)

	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013

Oil revenues	$	3,530,610		$	2,694,506		$	10,787,788		$	7,228,543
Natural gas revenues		280,078			-			827,273			-
Total revenues		3,810,688			2,694,506			11,615,061			7,228,543

Expenses:
Direct operating costs		1,920,968			916,567			4,964,009			2,450,596
Depreciation, depletion and amortization		899,177			484,478			2,495,317			1,347,576
Professional fees		126,581			264,050			578,696			889,529
Salaries		396,899			138,875			1,076,334			570,864
Administrative expense		243,136			220,693			635,364			534,340
Total expenses		3,586,761			2,024,663			9,749,720			5,792,905
Income from operations	$	223,927		$	669,843		$	1,865,341		$	1,435,638

Other income (expense):
Interest expense		(267,764	)		(137,831	)		(1,005,431	)		(393,204	)
Gain (loss) on derivatives		1,831,105			(1,160,374	)		20,012			(992,556	)
Other income (loss)		399			8,460			4,574			66,841
Total other income (expense)		1,563,740			(1,289,745	)		(980,845	)		(1,318,919	)
Net income (loss)	$	1,787,667		$	(619,902	)	$	884,496		$	116,719

Net income (loss)	$	1,787,667		$	(619,902	)	$	884,496		$	116,719
Preferred dividends	$	(522,398	)	$	(199,492	)	$	(1,378,135	)	$	(567,142	)
Net income (loss) attributable to common stockholders		1,265,269			(819,394	)		(493,639	)		(450,423	)
Net income (loss) per common share basic and diluted	$	.17		$	(.18	)	$	(.07	)	$	(.10	)
Weighted average shares		7,642,748			4,534,550			7,426,949			4,522,468

See Notes to Condensed Consolidated Financial Statements.

EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	For the Nine Months Ended
	September 30,
	2014			2013
Cash flows from operating activities
Net income (loss)	$	884,496		$	116,719
Depreciation and depletion		2,495,317			1,347,576
Stock, options and warrants issued for services		460,343			162,021
Accretion of asset retirement obligation		191,348			84,578
Settlements of asset retirement obligations		(90,524	)		(36,758	)
(Gain) loss on derivatives		(1,104,559	)		67,748
Loss on disposal of fixed assets		181			7,785
Changes in assets and liabilities:
Accounts receivable		603,495			(137,386	)
Inventory		(25,207	)		(169,940	)
Deposits and prepaid expenses		(206,638	)		(187,477	)
Accounts payable		305,290			(101,643	)
Accrued liabilities		(1,096,538	)		650,172
Cash flows from operating activities		2,417,004			1,803,395

Cash flows from investing activities
Settlements of asset retirement obligations		-			(18,910	)
Purchase of fixed assets		(238,148	)		(103,874	)
Additions to oil and gas properties		(5,162,656	)		(4,962,813	)
Proceeds from sale of oil and gas properties		987,939			454,973
Proceeds from sale of fixed assets		-			1,600
Net cash acquired from Black Raven		-			656,693
Cash flows used in investing activities		(4,412,865	)		(3,972,331	)

Cash flows from financing activities
Payments on long-term debt		(14,027,287	)		-
Payments on note payable		-			(600,000	)
Deferred financing costs		(196,960	)		(211,584	)
Proceeds from borrowings		3,500,000			4,000,000
Proceeds from sale of preferred stock		13,350,731			-
Dividends paid on preferred stock		(1,378,135	)		(567,143	)
Cash flows from financing activities		1,248,349			2,621,273

Net increase (decrease) in cash		(747,512	)		452,337
Cash – beginning		1,308,196			767,494
Cash – ending	$	560,684		$	1,219,831

Supplemental disclosures:
Interest paid	$	503,571		$	212,751

Non-cash transactions:
Share based payments issued for services	$	460,343		$	162,021

See Notes to Condensed Consolidated Financial Statements.

EnerJex Resources, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

Note 1 – Basis of Presentation

The unaudited condensed consolidated financial statements of EnerJex Resources, Inc. (“we”, “us”, “our”, “EnerJex” and “Company”) have been prepared in accordance with United States generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and reflect all adjustments which, in the opinion of management, are necessary for a fair presentation. All such adjustments are of a normal recurring nature. The results of operations for the interim period are not necessarily indicative of the results to be expected for a full year. Certain amounts in the prior year statements have been reclassified to conform to the current year presentations. The statements should be read in conjunction with the financial statements and footnotes thereto included in our Annual Report Form 10-K for the fiscal year ended December 31, 2013.

Our consolidated financial statements include the accounts of our wholly-owned subsidiaries, EnerJex Kansas, Inc., Black Sable Energy, LLC, Working Interest, LLC and Black Raven Energy, Inc. (“Black Raven”) for the three month and nine month periods ended September 30, 2014 and for the year ended December 31, 2013. On September 27, 2013, we acquired Black Raven. Accordingly, only the financial position, results of operations and cash flows of Black Raven for the quarter ended December 31, 2013 were included in the Company’s consolidated financial statements for the year ended December 31, 2013. All intercompany transactions and accounts have been eliminated in consolidation.

Note 2 - Stock Options

A summary of stock options is as follows:

	Options			Weighted Average Price
Outstanding December 31, 2013		231,133		$	9.36
Granted		2,367			10.50
Cancelled		(2,168	)		10.50
Exercised		-			-
Outstanding September 30, 2014		231,332		$	9.33

Note 3 – 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 our debt approximates fair value at September 30, 2014.

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 our marketable securities to be Level 3.

Our derivative instruments consist of variable to fixed price commodity swaps.

	Fair Value Measurement
	Level 1		Level 2			Level 3
Crude oil contracts	$	-	$	(240,131	)	$	-
Marketable Securities	$	-	$	-		$	1,018,673

Note 4 - Asset Retirement Obligation

Our asset retirement obligations relate to the liabilities associated with the abandonment of oil and natural 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, December 31, 2013	$	2,687,801
Liabilities incurred during the period		50,054
Liabilities settled during the period		(90,524	)
Accretion		191,348
Asset retirement obligations, September 30, 2014	$	2,838,679

Note 5 - Derivative Instruments

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

We have an Intercreditor Agreement in place between us, our counterparties, BP Corporation North America, Inc. (BP), Cargill, Inc. 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 are not required to post additional collateral, including cash.

The following derivative contracts were in place at September 30, 2014:

	Term	Monthly Volumes	Price/Bbl		Fair Value
Deferred premium put	1/16-6/16	9,000 Bbls	$	85.00	$	39,681
Crude oil swap	1/15-12/15	5,800 Bbls	$	88.55		54,288
Crude oil swap	9/13-12/14	3,000 Bbls	$	95.15		44,460
Crude oil swap	7/11-12/15	2,850 Bbls	$	83.70		(190,463	)
Crude oil collar	1/14-12/14	1,900 Bbls	$	96.00		33,003
Crude oil swap	7/12-12/15	1,240 Bbls	$	76.74		(221,262	)
Crude oil swap	1/14-12/14	1,380 Bbls	$	90.25		162
					$	(240,131	)

Monthly volume is the weighted average throughout the period.

The current fair value is shown as a derivative instrument in the current liabilities and the long term fair value is included in other long term assets on the balance sheet.

Note 6 - Long-Term Debt

Senior Secured Credit Facility

On October 3, 2011, the Company, 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. (the “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 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 reflected the addition of Rantoul Partners as an additional Borrower and added 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 the Bank. The Second Amendment: (i) increased our 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 our 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 quarter ended December 31, 2011.

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

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

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

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

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

Our current borrowing base is $40 million, of which we had borrowed $21 million as of September 30, 2014. We intend to conduct an additional borrowing base review in early 2015. For the nine month period ended September 30, 2014, and for the year ended December 31, 2013, the interest rate on amounts borrowed under our credit facility was 3.3%. This facility expires on October 3, 2018.

Note 7 - Commitments & Contingencies

As of September 30, 2014, we had an outstanding irrevocable letter of credit in the amount of $50,000 issued in favor of the Texas Railroad Commission. The letter of credit is required by the Texas Railroad Commission for all companies operating in the state of Texas with production greater than limits they prescribe.

Rent expense for the nine months ended September 30, 2014 and 2013 was approximately $123,000 and $126,000 respectively. Future non-cancellable minimum lease payments are approximately $40,000 for the remainder of 2014, $154,000 for 2015, $147,000 for 2016, $145,000 for 2017, $90,000 for 2018 and $77,000 for 2019.

Note 8 – Equity Transactions

On January 15, 2014, 7,333 shares were issued to two employees of the Company as compensation. The share price on the issue date was $7.05. From February 5, 2014 through March 17, 2014, 9,595 shares were issued for professional services rendered on behalf of the Company. The share price on all issuance dates for those shares was $7.50.

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

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

On June 20, 2014, we closed an underwritten initial public offering of 639,157 shares of our Series A preferred stock at a purchase price of $23.75 per share for gross proceeds of $15.2 million. The shares sold to the underwriters included 83,368 shares pursuant to a 45-day option that was exercised by the underwriters in full on June 20, 2014.

Note 9 - Subsequent Events

We have reviewed all material events through the date of this report in accordance with ASC 855-10.

On October 14, 2014, the Company acquired a 100% working interest in leases covering 3,400 mineral acres in Weld County, Colorado for approximately $300,000. This acreage is prospective for horizontal drilling targeting oil production from the Niobrara and Codell formations and has a remaining term of approximately 4 years.

On October 15, 2014, the Company appointed Kent Roach, whose employment began on October 20, 2014, as the company’s Executive Vice President of Engineering.

On October 31, 2014, the Company paid a dividend of approximately $156,000 on our 10% Series A Cumulative Perpetual Preferred Stock to shareholders of record at the close of business on October 15, 2014. The dividend was for the period beginning October 1, 2014 through October 31, 2014.

On November 4, 2014, the Company declared a dividend of approximately $156,000 on our 10% Series A Cumulative Perpetual Preferred Stock to be paid on December 1, 2014 to shareholders of record at the close of business on November 14, 2014. The dividend is for the period beginning of November 1, 2014 through November 30, 2014.

FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, contained in this report, including statements regarding future events, our future financial performance, business strategy and plans and objectives of management for future operations, are 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. These statements are only predictions and involve known and unknown risks, uncertainties and other factors, including the risks outlined under "Risk Factors" or elsewhere in this report, which may cause our or our industry's actual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by these forward-looking statements. 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. 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 reserves;
	·	declining local, national and worldwide economic conditions;
	·	fluctuations in the price of oil;
	·	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 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;
	·	adverse state or federal legislation or regulation that increases the costs of compliance, or adverse findings by a regulator with respect to existing operations; and
	·	changes in U.S. GAAP or in the legal, regulatory and legislative environments in the markets in which we operate.

You should not place undue reliance on any forward-looking statement, each of which applies only as of the date of this report. Except as required by law, we undertake no obligation to update or revise publicly any of the forward-looking statements after the date of this report to conform our statements to actual results or changed expectations. For a detailed description of these and other factors that could cause actual results to differ materially from those expressed in any forward-looking statement, please see "Risk Factors" in this document and in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013.

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.

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

INDUSTRY AND MARKET DATA

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

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following discussion of our financial condition and results of operations should be read in conjunction with our financial statements and the related notes to our financial statements included elsewhere in this report. In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our actual results and timing of selected events may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under ITEM 1A. Risk Factors and elsewhere in this report.

Overview

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

We continue to investigate multiple opportunities to both unlock value and accelerate growth in an accretive manner on behalf of shareholders, including but not limited to mergers, acquisitions, joint ventures, and non-dilutive financings. There can be no assurance of the results or timing associated with this process.

We are focusing our capital budget on the development of our Colorado and Kansas properties where we have identified hundreds of drilling locations and reactivation or recompletion opportunities.

Recent Developments

The following is a brief description of our most significant corporate developments that have occurred since the end of 2013:

In our Adena Field Project, we reactivated and initiated production from 7 new J-Sand oil wells and 1 new J-Sand natural gas well, recompleted and initiated water injection into 4 new secondary recovery J-Sand wells, and recompleted 2 D-sand oil wells in a secondary recovery waterflood pilot that was initiated during 2013. Preliminary production tests in this D-Sand waterflood pilot indicate that secondary recovery operations have increased reservoir pressure, fluid volumes and oil cut. Initial oil production from this pilot commenced in September 2014.

During June and July 2014, we conducted detailed production tests on our J-Sand oil wells in order to measure oil and water volumes. Data collected from these testing operations is being utilized to optimize field operations and future development planning. The testing process resulted in inefficient run times that negatively impacted production volumes during these months. After reviewing the results of the testing information and experiencing water injection and other infrastructure constraints, EnerJex decided to upgrade its infrastructure in order to increase production capacity and decrease operating expenses. The company is currently replacing key portions of the primary production infrastructure and reconfiguring the water injection system to handle additional production volumes.

In our Mississippian Project, we initiated a development drilling program in July and have since drilled ten successful oil wells, six of which are currently awaiting completion, and one secondary recovery water injection well.

In our Niobrara Project, we successfully completed workover operations on eight natural gas wells. In addition we tested two wells located approximately one mile apart in a portion of our Niobrara Project located in Sedgwick County, Colorado. Each well achieved an initial production rate of more than 600 thousand cubic feet of natural gas (Mcf) per day from the Niobrara formation at a depth of approximately 2,900 feet.

The Company has filed 17 drilling permits in in this area, where we have identified dozens of high-ranked drilling locations based on 3D seismic analysis. We have completed our assessment of the costs and timing associated with this development, including drilling and completion operations, pipeline construction, and the upgrade of an existing tap which the Company previously acquired that connects to the Trailblazer pipeline. We are currently waiting on a third party to complete the upgrade of the tap which we paid for during September. We expect to have the tap upgrade completed and all permits finalized for the 17 well drilling program by the first quarter of 2015.

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

On June 17, 2014 our common stock and non-dilutive Series A Cumulative Perpetual Preferred Stock began trading on the NYSE MKT under the symbols ENRJ and ENRJPR. The Company’s common stock prior to June 17, 2014 traded on the OTCQB.

On June 20, 2014, we closed an underwritten public offering of 639,157 shares of 10% Series A Cumulative Perpetual Preferred Stock (liquidation preference of $25.00 per share) at a price to the public of $23.75 per share for gross proceeds of $15.2 million. The shares sold to the underwriters included 83,368 shares pursuant to a 45-day option that was exercised by the underwriters in full on June 20, 2014. The Series A Preferred Shares contain the following provisions: (i) Series A Preferred Shareholders shall receive cumulative dividends at the stated rate of 10% per annum of the $25.00 per share liquidation preference; (ii) the Series A Preferred Shares shall not be redeemable by the Company except on or after June 16, 2017 or after a Change of Control of the Company; (iii) the Series A Preferred Shares shall not have any relative, participating, option or other voting rights or powers: and (iv) the Series A Preferred Shares shall not be convertible into our common stock.

On September 30, 2014, we acquired an 85% operated working interest in 640 acres in Weld County, Colorado. This acreage is held by production from three existing wells including two wells that produce oil from the Niobrara and Codell formations and one well that produces oil from the J-Sand formation. This acreage is prospective for horizontal drilling targeting oil production from the Niobrara and Codell formations.

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

The table below sets forth our net oil production (net of all royalties, overriding royalties and production due to others), the average sales prices, average production costs and direct lifting costs per unit of production for the periods ended September 30, 2014 and September 30, 2013.

	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013

Net Production
Oil (Bbl)		40,477		25,933		118,023		76,327
Natural gas (Mcf)		103,664		-		251,127		-

Average Sales Prices
Oil (Bbl)	$	87.23	$	103.90	$	91.40	$	94.70
Natural gas (Mcf)	$	2.70	$	-	$	3.95	$	-

Average Production Cost ⁽¹⁾
Per barrel of oil equivalent (“Boe”)	$	48.83	$	54.03	$	46.66	$	49.76

Average Lifting Costs ⁽²⁾
Per Boe	$	33.26	$	35.34	$	31.05	$	31.11

⁽¹⁾ Production costs include all operating expenses, transportation expenses, depreciation, depletion and amortization, lease operating expenses and all associated taxes. Impairment of oil properties is not included in production costs.

⁽²⁾ Direct lifting costs do not include impairment expense or depreciation, depletion and amortization.

Results of Operations for the Three and Nine Months Ended September 30, 2014 and 2013 compared

Revenues:

	Three Months Ended				Increase /		Nine Months Ended				Increase /
	September 30,				(Decrease)		September 30,				(Decrease)
	2014		2013				2014		2013
Oil revenues	$	3,530,610	$	2,694,506	$	836,104	$	10,787,788	$	7,228,543	$	3,559,245
Natural gas revenues		280,078		-		280,078		827,273		-		827,273
Total revenues	$	3,810,688	$	2,694,506	$	1,116,182	$	11,615,061	$	7,228,543	$	4,386,518

Oil Revenues

Oil revenues for the nine months ended September 30, 2014 were $10,787,788 compared to revenues of $7,228,543 for the nine months ended September 30, 2013. Revenues increased primarily as a result of higher oil production associated with the assets acquired via the Black Raven merger and were partially offset by lower oil prices.

Natural Gas Revenues

Natural gas revenues for the nine months ended September 30, 2014 were $827,273. Natural gas revenues increased as result of increased natural gas production from assets that were acquired as part of our merger with Black Raven on September 27, 2013.

Expenses:

	Three Months Ended						Increase /			Nine Months Ended						Increase /
	September 30,						(Decrease)			September 30,						(Decrease)
	2014			2013						2014			2013
Production expenses:
Direct operating costs	$	1,920,968		$	916,567		$	1,004,401		$	4,964,009		$	2,450,596		$	2,513,413
Depreciation, depletion and amortization		899,177			484,478			414,699			2,495,317			1,347,576			1,147,741
Total production expenses		2,820,145			1,401,045			1,419,100			7,459,326			3,798,172			3,661,154

General expenses:
Professional fees		126,581			264,050			(137,469	)		578,696			889,529			(310,833	)
Salaries		396,899			138,875			258,024			1,076,334			570,864			505,470
Administrative expense		243,136			220,693			22,443			635,364			534,340			101,024
Total general expenses		766,616			623,618			142,998			2,290,394			1,994,733			295,661
Total production and general expenses		3,586,761			2,024,663			1,562,098			9,749,720			5,792,905			3,956,815

Income (loss) from operations		223,927			669,843			(445,916	)		1,865,341			1,435,638			429,703

Other income (expense)
Interest expense		(267,764	)		(137,831	)		(129,933	)		(1,005,431	)		(393,204	)		(612,227	)
Gain (loss) on derivatives		1,831,105			(1,160,374	)		2,991,479			20,012			(992,556	)		1,012,568
Other income (loss)		399			8,460			(8,061	)		4,574			66,841			(62,267	)
Total other income (expense)		1,563,740			(1,289,745	)		2,853,485			(980,845	)		(1,318,919	)		338,074

Net income (loss)	$	1,787,667		$	(619,902	)	$	2,407,569		$	884,496		$	116,719		$	767,777

Direct Operating Costs

Direct operating costs include direct labor and equipment costs related to pumping, gauging, pulling, well repairs, compression, transportation costs and general maintenance requirements in our oil and gas fields. These costs also include certain contract labor costs, and other non-capitalized expenses. Direct operating costs for the nine months ended September 30, 2014 increased 103% to $4,964,009 from $2,450,596 for the nine months ended September 30, 2013. However, direct operating costs per Boe decreased from $31.11 to $31.05. The $2,513,413 increase in direct operating costs is due primarily to new production associated with the assets acquired as part of our merger with Black Raven on September 27, 2013.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the nine months ended September 30, 2014 was $2,495,317 compared to $1,347,576 for the nine months ended September 30, 2013. The increase in depletion expense is due primarily to increased oil and natural gas production during the first nine months of 2014 compared to the first nine months of 2013. However, depletion expense per Boe decreased $2.05 or 12% in the first nine months of 2014 compared to the first nine months of 2013.

Professional Fees

Professional fees for the nine months ended September 30, 2014 were $578,696 compared to $889,529 for the nine months ended September 30, 2013. The decrease in professional fees is due primarily to a reduction in lawsuit related legal fees and a reduction in fees related to outsourced third party engineering and consulting work that we conducted during the first half of 2013.

Salaries

Salaries for the nine months ended September 30, 2014 were $1,076,334 compared to $570,864 for the nine months ended September 30, 2013. The increase in salaries is due primarily to the addition of employees following our merger with Black Raven.

Administrative Expenses

Administrative expenses for the nine months ended September 30, 2014 were $635,364 compared to $534,340 for the nine months ended September 30, 2013. The increase in administrative expenses is due primarily to the addition of employees, office space and the administrative costs associated with our merger with Black Raven on September 27, 2013

Interest Expense

Interest expense for the nine months ended September 30, 2014 was $1,005,431 compared to $393,204 for the nine months ended September 30, 2013. Interest expense and amortization of deferred financing costs increased as a result of increased borrowings. Proceeds from the Series A Preferred Stock offering June 20, 2014 were used to reduce outstanding borrowings on our line of credit with Texas Capital Bank. In addition, accretion increased due to assets acquired as part of our merger with Black Raven on September 27, 2013.

Gain (Loss) on Derivatives

We recorded an unrealized gain of $20,012 on our derivative contracts in the first nine months of 2014 compared to a loss of $992,556 for the nine months ended September 30, 2013. The gain was due primarily to the “mark to market” valuation of our derivative contracts at prices below our average hedge price. This gain was partially offset by the completion of contracts during the nine month period ending September 30, 2014 above our average contracted hedge prices.

Net Income (Loss)

Net income for the nine months ended September 30, 2014 was $884,496 compared to net income of $116,719 for the nine months ended September 30, 2013. The increase in net income was due primarily to the increase in net operating income associated with our acquisition of Black Raven Energy, as well as hedging gains in 2014 versus hedging losses in 2013. Increases in net income were partially offset by increased interest expense associated with increased borrowings in 2014 versus 2013.

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 and the issuance of equity securities. We believe that our historical means of meeting our capital requirements will provide us with adequate liquidity to fund our operations and capital program in 2014.

The following table summarizes total current assets, total current liabilities and working capital.

	September 30, 2014			December 31, 2013			Increase / (Decrease)

Current Assets	$	4,224,438		$	5,401,303		$	(1,176,865	)

Current Liabilities	$	4,493,724		$	6,506,178		$	(2,012,454	)

Working Capital	$	(269,286	)	$	(1,104,875	)	$	835,589

Senior Secured Credit Facility

On October 3, 2011, the Company, 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. (the “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 used to refinance Borrowers prior outstanding revolving loan facility with Bank, dated July 3, 2008, and for working capital and general corporate purposes.

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, which closed on December 15, 2011. The Amendment reflected the addition of Rantoul Partners as an additional Borrower and added as additional security for the loans the assets held by Rantoul Partners.

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

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 into our credit facility, and (ii) made a technical correction to our covenant calculations.

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.

Satisfaction of our cash obligations for the next 12 months

We intend to meet our near term cash obligations through financings under our credit facility with Texas Capital Bank and through cash flow generated from operations.

Summary of product research and development

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

Expected purchase or sale of any significant equipment

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

Significant changes in the number of employees

There have been no significant changes in number of employees since December 31, 2013. We currently have 34 full-time employees, including field personnel. As production and drilling activities increase or decrease, we may have to continue to adjust our technical, operational and administrative personnel as appropriate. We are using and will continue to use independent consultants and contractors to perform various professional services, particularly in the area of land services, reservoir engineering, geology drilling, water hauling, pipeline construction, well design, well-site monitoring and surveillance, permitting and environmental assessment. We believe that this use of third-party service providers may enhance our ability to contain operating and general expenses, and capital costs.

Off-Balance Sheet Arrangements

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

Critical Accounting Policies and Estimates

Our critical accounting estimates include the value of our oil and gas properties, asset retirement obligations, and share-based payments

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 to proved property immediately. Unproved properties are reviewed for impairment quarterly.

Under the full-cost-method of accounting, the net book value of oil 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. During the quarter ended September 30, 2014 and the year ended December 31, 2013, there were no impairments resulting from the quarterly ceiling tests.

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.

Effects of Inflation and Pricing

The oil industry is very cyclical and the demand for goods and services of oil 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 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 prices for oil remains volatile.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

We are a smaller reporting Company as defined by Rule 12b-2 under the Securities Exchange Act of 1934, and are not required to provide the information required under this item.

ITEM 4. CONTROLS AND PROCEDURES.

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

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.

PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

We may become involved in various routine legal proceedings incidental to our business. However, to our knowledge as of the date of this transition report, there are no material pending legal proceedings to which we are a party or to which any of our property is subject.

On January 23, 2012, we filed a petition seeking recovery of damages arising from breach of contract, legal malpractice, breach of fiduciary duty and fraud in the Circuit Court of Jackson County, Missouri against attorneys Jeffrey T. Haughey, Robert K. Green, and the law firm Husch Blackwell LLP f/k/a Husch Blackwell Sanders, LLC. The petition in this action, EnerJex Resources, Inc., v. Haughey, et al., alleges, among other things, that the defendants violated their fiduciary duties and defrauded us in connection with our stock offering in 2008.

The petition alleges economic loss of approximately $50 million and demands judgment for unspecified actual and punitive damages together with repayment of $484,473 in legal fees paid by EnerJex. At the time the petition was filed, we estimated our economic loss of approximately $50 million by conducting an analysis that considered a number of factors, including the loss of at least $25 million of gross proceeds we would have received in the failed 2008 stock offering, the loss of the value we could have created had EnerJex been able to utilize the proceeds from the stock offering to execute its business plan in the 2008 economic environment, and the loss of market value for our common stock.

A trial to hear a portion of this case in the 16th Circuit Court of Jackson County, Missouri, began on December 2, 2013. In that trial, based on its rulings on written motions, the court disallowed our claims for actual and consequential damages for breach of contract and legal malpractice against the defendants. On December 19, 2013, the Company reached an agreement with the defendants to settle our claims for breach of fiduciary duty and fraud in return for (i) the defendants paying to us the sum of $500,000, which was paid to us in January 2014, and (ii) dismissal of the defendants’ counterclaim of $492,134 and interest on that amount, which was removed from our balance sheet and is not reflected as a liability as of December 31, 2013. Our financial statements reflect the litigation costs that we have incurred to date.

In entering into this settlement, the defendants have not admitted liability on any matter related to the claims in the litigation. In June 2014, we appealed the court’s rulings and requested from the appellate court authorization to pursue our claims for actual and consequential damages with respect to our claims alleging breach of contract and legal malpractice against the defendants. There can be no assurance of the outcome of the appellate process, including whether the appellate court will allow us to seek actual and consequential damages for breach of contract and legal malpractice and breach of fiduciary duty, as well as what amount of damages, if any, we may recover.

Any additional monetary award resulting from a settlement of this litigation that is reached for our benefit in an amount that exceeds our total costs of litigation shall be subject to a contingency fee for the benefit of our attorneys. There can be no assurance of the outcome of this litigation, including whether and in what amount EnerJex may recover damages.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

None

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4. (REMOVED AND RESERVED).

ITEM 5. OTHER INFORMATION.

None.

ITEM 6.

EXHIBITS.

Exhibit No.		Description
2.1		Agreement and Plan of Merger by and among Registrant, BRE Merger Sub, Inc., Black Raven Energy, Inc. and West Coast Opportunity Fund, LLC dated July 23, 2013 (incorporated herein by reference to Exhibit 10.4 on Form 8-K filed July 29, 2013).
3.1		Amended and Restated Articles of Incorporation, as currently in effect (incorporated by reference to Exhibit 3.1 to the Form 10-Q filed on August 14, 2008)
3.2		Amended and Restated Bylaws, as currently in effect (incorporated by reference to Exhibit 3.3 to the Form SB-2 filed on February 23, 2001)
3.3		Certificate of Amendment of Amended and Restated Articles of Incorporation (incorporated herein by reference as Appendix B to Schedule 14A filed on June 6, 2013).
3.4		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).
3.5		Amended and Restated Certificate of Designathion as filed with the Nevada Secretary of State on June 16,2014 (incorporated herein by reference as Exhibit 4.6 to Registration Statement on Form S-1 filed on June 3, 2014).
4.1		Amended and Restated Bylaws, as currently in effect (incorporated by reference to Appendix C to Schedule 14A filed on June 6, 2013).
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).
21.1		Subsidiaries
31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2		Certification of Chief Financial Officer pursuant to Section 302 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		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS		XBRL Instance Document
101.SCH		XBRL Taxonomy Extension Schema Document
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF		XBRL Taxonomy Extension Definition Linkbase Document
101.LAB		XBRL Taxonomy Extension Labels Linkbase Document
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

† Indicates management contract or compensatory plan or arrangement.

SIGNATURES

In accordance with the requirements of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

ENERJEX RESOURCES, INC.
(Registrant)

By:	/s/ Robert G. Watson, Jr.
	Robert G. Watson, Jr. Chief Executive Officer
	(Principal Financial Officer)

Date: November 14, 2014