AgEagle Aerial Systems Inc. - Quarter Report: 2011 September (Form 10-Q)

Unassociated Document

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, 2011

¨	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 305
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 ¨ No þ

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 October 31, 2011 was 69,436,529 shares.

ENERJEX RESOURCES, INC.

FORM 10-Q

TABLE OF CONTENTS

		Page
PART I FINANCIAL STATEMENTS
ITEM 1.	FINANCIAL STATEMENTS	2
	Condensed Consolidated Balance Sheets	2
	Condensed Consolidated Statements of Operations	3
	Condensed Consolidated Statements of Cash Flows	4
	Notes to Condensed Consolidated Financial Statements	5
	FORWARD-LOOKING STATEMENTS	7
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	8
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	15
ITEM 4.	CONTROLS AND PROCEDURES	15

PART II OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	15
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	15
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	15
ITEM 4.	(REMOVED AND RESERVED)	15
ITEM 5.	OTHER INFORMATION	15
ITEM 6.	EXHIBITS	15

SIGNATURES		19

PART 1 – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

Unaudited	September 30,			December 31,
	2011			2010

Assets
Current assets:
Cash	$	1,221,671		$	2,961,819
Accounts receivable		926,540			357,387
Marketable Securities		1,543,293			2,971,162
Deposits and prepaid expenses		125,429			144,468
Derivate Gain		158,305			-
Total current assets		3,975,238			6,434,836

Fixed assets		526,403			253,847
Less: Accumulated depreciation		193,779			122,775
Total fixed assets		332,624			131,072

Other assets:
Oil properties using full-cost accounting:
Properties not subject to amortization		15,371,382			18,679,255
Properties subject to amortization		12,075,604			5,637,473
Total other assets		27,446,986			24,316,728
Total assets	$	31,754,848		$	30,882,636

Liabilities and Stockholders' Equity (Deficit)
Current liabilities:
Accounts payable	$	1,125,928		$	1,109,848
Accrued liabilities		209,118			161,811
Derivative liability		-			929,720
Long-term debt, current		7,000			6,131,000
Total current liabilities		1,342,046			8,332,379

Asset retirement obligation		1,082,791			883,066
Long-term debt		6,132,001			22,114
Derivative liability		660,038			2,267,109
Total liabilities		9,216,876			11,504,668

Stockholders' Equity :
Preferred stock, $0.001 par value, 10,000,000 shares authorized, 4,779,460 shares issued and outstanding		4,780			4,780
Common stock, $0.001 par value, 100,000,000 shares authorized; shares issued and outstanding – 69,436,529 at September 30, 2011 and 67,469,555 at December 31, 2010		73,187			67,460
Treasury Stock		(1,500,000	)		-
Equity based compensation unearned		(250,048	)		-
Paid-in capital		41,399,739			37,661,719
Accumulated other comprehensive income		(27,869	)		-
Retained (deficit)		(17,161,817	)		(18,355,991	)
Total stockholders' equity		22,537,972			19,377,968
Total liabilities and stockholders' equity	$	31,754,848		$	30,882,636

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,
	2011			2010			2011			2010

Oil revenues	$	1,673,857		$	897,219		$	4,728,198		$	3,097,216

Expenses:
Direct operating costs		787,994			524,442			2,461,978			1,442,098
Depreciation, depletion and amortization		375,175			173,269			975,908			399,584
Professional fees		255,706			106,276			745,638			251,780
Salaries		150,673			57,746			434,319			229,719
Administrative expense		75,600			103,267			536,614			495,332
Total expenses		1,645,148			965,000			5,154,457			2,818,513

Income (loss) from operations		28,709			(67,781	)		(426,259	)		278,703

Other income (expense):
Interest expense		(111,472	)		(216,314	)		(333,977	)		(793,984	)
Gain (loss) on derivative instruments		3,188,277			(702,148	)		1,916,511			(891,556	)
Other income (loss)		13,857			32,138			37,900			44,396
Total other income (expense)		3,090,662			(886,324	)		1,620,434			(1,641,144	)

Net income (loss)	$	3,119,371		$	(954,105	)	$	1,194,175		$	(1,362,441	)

Net income (loss) per share basic and diluted	$	.04		$	(0.19	)	$	.02		$	(.27	)

Weighted average shares outstanding-diluted		69,436,529			5,134,062			68,767,860			5,037,257

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,
	2011			2010
Cash flows from operating activities
Net income (loss)	$	1,194,175		$	(1,362,441	)
Depreciation and depletion		984,151			424,759
Accretion of interest on long-term debt discount		-			163,244
Shares issued for compensation and services		57,702			-
Accretion of asset retirement obligation		60,525			57,813
Gain (Loss) on derivatives		(2,695,096	)		289,044
Gain on purchase of debentures		-			(30,000	)
Loss on sale of fixed assets		1,400			52,361
Principal increase in debenture		-			280,009
Shares issued for interest on debenture		-			5,125
Changes in assets and liabilities:
Accounts receivable		(569,153	)		31,104
Prepaid expenses		19,039			62,841
Accounts payable		16,080			(28,549	)
Accrued liabilities		47,307			(148,868	)
Cash flows from operating activities		(883,870	)		(203,558	)

Cash flows from investing activities

Purchase of Treasury Stock		(1,500,000	)		-
Purchase of fixed assets		(273,956	)		(31,637	)
Additions to oil & gas properties		(3,904,205	)		(96,136	)
Proceeds from sale of oil & natural gas properties		-			92,000
Proceeds from sale of fixed assets		-			44,678
Cash flows from investing activities		(5,678,161	)		8,905

Cash flows from financing activities
Payments on long-term debt		(14,113	)		(217,674	)
Sale of marketable securities		1,400,000			-
Sale of common stock		3,435,996			-
Borrowings on long term debt		-			123,595
Cash flows from financing activities		4,821,883			(94,079	)

Net increase (decrease) in cash		(1,740,148	)		(288,732	)
Cash – beginning		2,961,819			412,370
Cash – ending	$	1,221,671		$	123,638

Supplemental disclosures:
Interest paid	$	333,977		$	287,930
Income taxes paid	$	-		$	-

Non-cash transactions:
Share-based payments issued for services and interest	$	57,702		$	177,412

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 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 Transition Report Form 10-K for the nine-month period ended December 31, 2010.

Our consolidated financial statements include the accounts of our wholly-owned subsidiaries, EnerJex Kansas, Inc., DD Energy, Inc., Black Sable Energy, LLC and Working Interest, LLC. All intercompany transactions and accounts have been eliminated in consolidation.

Note 2 - Stock Options

A summary of stock options is as follows:

	Options		Weighted Ave. Exercise Price		Warrants		Weighted Ave. Exercise Price
Outstanding December 31, 2011		-	$	-		2,838,330	$	0.90
Granted		900,000		0.40		-		-
Cancelled		-		-		-		-
Exercised		-		-		-		-
Outstanding September 30, 2011		900,000	$	0.40		2,838,330	$	0.90

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, 2011.

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.

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

	Fair Value Measurement
	Level 1		Level 2		Level 3
Crude oil contracts	$	—	$	501,733	$	—

Note 4 - Asset Retirement Obligation

Our asset retirement obligations relate to the liabilities associated with the abandonment of oil 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, 2010	$	883,066
Liabilities incurred during the period		139,200
Liabilities settled during the period		(1,039	)
Accretion		61,564
Asset retirement obligations, September 30, 2011	$	1,082,791

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 counterparty BP Corporation North America, Inc. ("BP"), and our agent Texas Capital Bank, N.A., which allows Texas Capital Bank to also act as agent for BP 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, 2011:


	Term	Monthly Volumes	Price per Bbl		Fair Value
Crude oil swap	1/13-12/14	1,150 Bbls		62.20		(596,618	)
Crude oil swap	7/11-12/15	3,006 Bbls		83.70		91,313
Crude oil swap	1/11-12/12	400 Bbls		82.20		7,516
Crude oil swap	12/11-12/12	400 Bbls		77.50		(16,248	)
Crude oil swap	1/11-12/14	400 Bbls		79.75		(2,636	)
Crude oil swap	4/11-4/12	400 Bbls		85.95		14,940
					$	(501,733	)

Monthly volume is the weighted average throughout the period.

The total fair value is shown as a derivative instrument in both the current and non-current liabilities on the balance sheet, including any current derivative gains.

Note 6 - Long-Term Debt

Senior Secured Credit Facility

On October 3, 2011, we entered into a new Senior Secured Reducing Revolving Line of Credit of up to $50,000,000 (the "Credit Facility") pursuant to an Amended and Restated Credit Agreement with Texas Capital Bank, N.A. The Credit Facility was used to refinance amounts outstanding under the prior credit facility, and will be used for working capital and general corporate purposes.

Borrowings under the Credit Facility are subject to a borrowing base limitation based on our current proved oil reserves and will be subject to semi-annual redeterminations. The borrowing base effective as of October 3, 2011 was determined to be $7,200,000.

The Credit Facility is secured by a first priority lien and security interest in the assets of the Borrowers. The Credit Facility has a term of four years, and all principal amounts, together with all accrued and unpaid interest, will be due and payable in full on October 3, 2015. The Credit Facility also provides for the issuance of letters-of-credit up to a $750,000 sub-limit under the borrowing base.

At the Company's option, loans under the Credit 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 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 Credit Agreement). A commitment fee of 0.500% on the unused portion of the borrowing base will accrue, and be payable quarterly in arrears.

The Credit Facility includes usual and customary affirmative covenants for credit facilities of this type and size, as well as customary negative covenants, including, among others, limitations on liens, mergers, asset sales or dispositions, payments of dividends, incurrence of additional indebtedness, and investments. The Credit Facility requires that we, at the end of each fiscal quarter beginning with the quarter ending September 30, 2011, maintain a minimum current assets to current liabilities ratio of no less than 1.00 to 1.00, and maintain a ratio of senior funded debt to EBITDA no greater than 4.75:1.00 for the quarters ending September 30, 2011 and December 31, 2011, and no greater than 4.50:1.00 for the quarter ending March 31, 2012 and each fiscal quarter thereafter.

The Credit Facility establishes minimum volumes to be hedged of not less than 50% nor more than 85% of the proved developed producing reserves attributable to our interest in the borrowing base oil properties projected to be produced.

Other Long-Term Debt

We financed the purchase of vehicles through a bank. The notes are for four years and the weighted average interest is 7.2% per annum and vehicles collateralize these notes.

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 (especially 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;

·	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 Transition Report on Form 10-K for the nine-month period ended December 31, 2010.

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., DD Energy, Inc., Black Sable Energy, LLC and Working Interest, LLC, unless the context requires otherwise. We report our financial information on the basis of a December 31st 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 305, 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 Eastern Kansas and South Texas.

The Opportunity in Kansas

According to the Kansas Geological Survey, the State of Kansas has historically been one of the top 10 domestic oil producing regions in the United States. For the years ended December 31, 2010 and 2009, 40.5 million barrels and 39.5 million barrels of oil were produced in Kansas. Of the total barrels produced in Kansas in the calendar year ended December 31, 2010, 20 companies accounted for approximately 34% of the total production, with the remaining 66% produced by over 2,000 active producers.

In addition to significant historical oil production levels in the region, we believe that a confluence of the following factors in Eastern Kansas and the surrounding region make it an attractive area for oil development activities:

Numerous Acquisition Opportunities in Fragmented Markets. The exploration and production business in Eastern Kansas is highly fragmented and consists of many small operators that operate producing oil properties on relatively small budgets. Consequently, numerous acquisition opportunities with drilling and expansion potential exist in the area.

Opportunity to Enhance Operational Efficiency of Mature Leases. Many potential acquisition targets include significant opportunities for enhanced operational efficiencies and increased ultimate recoveries of oil through the application of modern engineering technologies, professional approaches to reservoir engineering and operations management, and the potential application of a number of enhanced oil recovery technologies.

Opportunity to Reduce Operating Costs per Barrel Through Economies of Scale. A significant portion of expenses at the field level are fixed (primarily labor and equipment). These costs are scalable, and lease operating expenses per barrel may be significantly reduced by increasing production in current areas of operation via the drilling of low risk development wells, acquisition of producing properties in close proximity to existing operations, and the application of modern enhanced oil recovery technologies.

Large Oil Reserves in Place and Relatively Low Exploration Risk. A majority of the oil reserves in Eastern Kansas are present at relatively shallow horizons (most at a depth less than 3,000 feet) and contain significant volumes of oil in place. These shallow reservoirs often lack a strong natural drive mechanism and ultimate recovery of oil in place can be significantly increased through the application of secondary recovery technologies. Secondary recovery operations generally involve higher operating costs on a per barrel basis as compared to primary recovery; however, exploration risk in the area is relatively low, which can more than offset higher operating costs.

The Opportunity in South Texas

Technological advances in the oil industry have made great strides over the last decade, especially in the area of completion technologies, mainly through horizontal drilling and artificial fracture stimulation. Multiple sizeable oil deposits were discovered in South Texas during past decades, but operators lacked the technology to produce economically from these reservoirs at the time of discovery. The availability of modern completion technologies coupled with the current commodity price environment provide an opportunity for operators to economically produce oil from reservoirs that were discovered in the past, yet never fully developed due to technology and economic constraints.

Recent Developments

The following is a brief description of our most significant corporate developments that occurred in the third quarter of 2011:

In July and August 2011, we drilled and cased three wells in our El Toro project in South Texas. Logs and core data indicate that these wells are similar to nearby producers and we believe these wells will be an economic success. Frenzied industry activity in South Texas due to the Eagleford Shale play has created significant delays in the procurement of oil field services. We are currently working with vendors to schedule stimulation treatments on the three new wells in the El Toro project, and we anticipate stimulating and beginning to produce these wells before the end of 2011. The Company owns a 40% working interest in these wells.

On August 11, 2011, we executed an option to purchase additional oil producing assets in Woodson County, Kansas, commonly identified as the "Nickletown Leasehold." The Nickletown Leasehold consists of up to 2,000 acres located adjacent to our Black Oaks Project, which produces oil from the Mississippian formation. We exercised this option on November 9, 2011. Pursuant to the terms of this agreement, we acquired a 90% working interest in 720 acres and we may acquire a 90% working interest in 1,280 additional adjacent acres upon fulfilling certain drilling milestones.

On October 3, 2011, we entered into a new four-year $50,000,000 Credit Facility with Texas Capital Bank, N.A. The Credit Facility was used to replace and refinance our previous credit facility that expired on October 3, 2011. The new Credit Facility resulted in a 16% increase in our borrowing base from $6.1 million to $7.1 million, and our current interest rate was reduced by 33% from 6% to 4%.

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) for the period ending September 30, 2011 and period ended September 30, 2010, the average sales prices, average production costs and direct lifting costs per unit of production.

	For the Three Months Ended				For the Nine Months Ended
	September 30,				June 30,
	2011		2010		2011		2010

Net Production		19,724		14,442		52,748		41,776
Oil (Bbl)

Average Sales Prices
Oil (per Bbl)	$	84.87	$	62.13	$	89.64	$	74.14

Average Production Cost (1)
Per Bbl of oil	$	58.97	$	48.31	$	65.18	$	44.08

Average Lifting Costs (2)
Per Bbl of oil	$	39.95	$	36.31	$	46.67	$	34.52

(1)	Production costs include all operating expenses, depreciation, depletion and amortization, lease operating expenses and all associated taxes. Impairment of oil and natural gas 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 Nine Months Ended September 30, 2011 and 2010 compared.

Income:

	Three Months Ended				Increase /		Nine Months Ended				Increase /
	September 30,				(Decrease)		September 30,				(Decrease)
	2011		2010				2011		2010
Oil revenues	$	1,673,857	$	897,219	$	776,638	$	4,728,198	$	3,097,216	$	1,630,982

Revenues

Oil revenues for the nine months ended September 30, 2011 were $4,728,198 compared to revenues of $3,097,216 in the nine months ended September 30, 2010. Oil revenues for the three months ended September 30, 2011 were $1,673,857 compared to revenues of $897,219 in the three months ended September 30, 2010. Revenue increases compared to prior periods are attributable to higher production resulting from the 2011 drilling program and the addition of producing assets that were acquired on December 31, 2010. Revenues also increased due to an increase in commodity prices compared to the prior year periods.

Expenses:

	Three Months Ended						Increase /			Nine Months Ended						Increase /
	September 30,						(Decrease)			September 30,						(Decrease)
	2011			2010						2011			2010
Production expenses:
Direct operating costs	$	787,994		$	524,442		$	263,552		$	2,461,978		$	1,442,098		$	1,019,880
Depreciation, depletion and amortization		375,175			173,269			201,906			975,908			399,584			576,324
Total production expenses		1,163,169			697,711			465,458			3,437,886			1,841,682			1,596,204

General expenses:
Professional fees		255,706			106,276			149,430			745,638			251,780			493,858
Salaries		150,673			57,746			92,927			434,319			229,719			204,600
Administrative expense		75,600			103,267			(27,667	)		536,614			495,332			41,282
Total general expenses		481,979			267,289			214,690			1,721,105			976,831			739,740
Total production and general expenses		1,645,148			965,000			680,148			5,158,991			2,818,513			2,335,944

Income (loss) from operations		28,709			(67,781	)		96,490			(426,259	)		278,703			(704,962	)

Other income (expense)
Interest expense		(111,472	)		(216,314	)		104,842			(333,977	)		(793,984	)		460,007
Gain (loss) on derivatives		3,188,277			(702,148	)		3,890,425			1,916,511			(891,556	)		2,808,067
Other income (loss)		13,857			32,138			(18,281	)		37,900			44,396			(6,496	)
Total other income (expense)		3,090,662			(886,324	)		3,976,986			1,620,434			(1,641,144	)		3,356,756

Net income (loss)	$	3,119,371		$	(954,105	)	$	4,073,476		$	1,194,175		$	(1,362,441	)	$	2,556,616

Direct Operating Costs

Direct operating costs primarily include direct labor and equipment costs related to pumping, gauging, pulling, well repairs, and general maintenance requirements. These costs also include certain contract labor costs, and other non-capitalized expenses. Direct operating costs for the nine months ended September 30, 2011 were $2,461,978 compared to $1,442,098 for the nine months ended September 30, 2010. Direct costs increased primarily as a result of deferred maintenance expenditures on vintage leases and expenses associated with the additional producing properties acquired on December 31, 2010. A majority of deferred maintenance expenditures were incurred in the first six months of 2011and we estimate that total deferred maintenance expenditures were approximately $500,000.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the nine months ended September 30, 2011 and September 30, 2010 was $975,908 and $399,584 respectively.

Professional Fees

Professional fees for the nine months ended September 30, 2011 were $745,638 compared to $251,780 for the nine months ended September 30, 2010. The increase in professional fees was primarily a result of legal fees incurred for the closing of new acquisitions and capital raising activities. We incurred approximately $200,000 of non-recurring professional fees during the nine month period ended September 30, 2010. Non-recurring items include legal fees related to multiple transactions that closed on December 31, 2010, additional contract engineering work performed during the period, non-recurring legal expenses associated with a billing dispute, and consulting fees related to an operations study completed during the period.

Salaries

Salaries for the nine months ended September 30, 2011 were $434,319 compared to $229,719 for the nine months ended September 30, 2010.

Administrative Expense

Administrative expense for the nine months ended September 30, 2011 were $536,614 compared to $495,332 in the nine months ended September 30, 2010. We incurred approximately $65,000 of non-recurring administrative expenses during the nine months ended September 30, 2011. Non-recurring items include transaction related financing fees and legal fees incurred for transaction related work.

Interest Expense

Interest expense for the nine months ended September 30, 2011 was $333,977 whereas interest expense for the nine months ended September 30, 2010 was $793,984. Interest expense is lower due to reduced borrowing under the Credit Facility and the conversion of the subordinated debentures into common equity.

Gain (Loss) on Derivatives

There was a gain on the derivative contracts in 2011 due to an increase in oil prices in addition to a new hedge contract entered into for the period of July 2011 through December 2015 with increased volume. The hedge price in the new hedge contract is $83.70, and the new contract replaced a prior hedge contract with a hedge price of $57.50.

Net Income (Loss)

Net income for the nine months ended September 30, 2011 was $1,194,175 as compared to a loss of $1,362,441 in the nine months ended September 30, 2010. Non-cash expenses such as depreciation and depletion as well as loan costs and accretions are significant factors contributing to the net loss in the prior periods. The gain on the derivative contracts is a significant factor contributing to the net income in the current period.

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. On October 3, 2011, we entered into a new four-year $50,000,000 Credit Facility with Texas Capital Bank, N.A. The Credit Facility provides a borrowing base of $7,200,000 of which $6,131,000 is funded. We have approximately $1,070,000 of availability under the Credit Facility.

We manage our exposure to commodity price fluctuations by executing derivative transactions to hedge the change in prices of our production, thereby mitigating our exposure to price declines, but these transactions will also limit our earnings potential in periods of rising commodity prices. There also is a risk that we will be required to post collateral to secure our hedging activities and this could limit our available funds for our business activities.

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

	September 30, 2011		December 31, 2010		Increase / (Decrease)

Current Assets	$	3,975,238	$	6,434,836	$	(2,459,598)

Current Liabilities	$	1,342,046	$	8,332,379	$	(6,990,333)

Working Capital (deficit)	$	2,474,887	$	(1,897,543)	$	4,372,430)

Senior Secured Credit Facility

Satisfaction of our cash obligations for the next 12 months

A critical component of our operating plan is the ability to obtain additional capital through additional equity and/or debt financing and working interest participants. We believe that our current amount of cash on hand and the Credit Facility will enable us to meet our obligations.

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 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 and we currently have 21 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 our oil and gas properties, asset retirement obligations, and share-based payments.

Oil Properties

The accounting for our business is subject to special accounting rules that are unique to the oil industry. There are two allowable methods of accounting for oil business activities: the successful efforts method and the full-cost method. 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 any costs related to production, general corporate overhead or similar activities.

Under the full-cost method, capitalized costs are amortized on a composite unit-of-production method based on proved oil reserves. Depreciation, depletion and amortization expense is also based on the amount of estimated reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves changes significantly. Proceeds from the sale of properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in the relationship between costs and the value of proved reserves or the underlying value of unproved properties, in which case a gain or loss is recognized. The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties, and otherwise if impairment has occurred. Unevaluated properties are assessed individually when individual costs are significant.

We review the carrying value of our oil properties under the full-cost accounting rules of the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. In calculating future net revenues, current prices and costs used are those as of the end of the appropriate quarterly period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives qualifying as cash flow hedges. Two primary factors impacting this test are reserve levels and current prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. Under SEC regulations, the excess above the ceiling is not expensed (or is reduced) if, subsequent to the end of the period, but prior to the release of the financial statements, oil prices increase sufficiently such that an excess above the ceiling would have been eliminated (or reduced) if the increased prices were used in the calculations.

The process of estimating oil reserves is very complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates.

As of December 31, 2010, approximately 100% of our proved reserves were evaluated by an independent petroleum consultant. All reserve estimates are prepared based upon a review of production histories and other geologic, economic, ownership and engineering data.

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 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 apportion of our production.

We have an Intercreditor Agreement in place between us, our counterparty BP Corporation North America, Inc. ("BP"), and our agent Texas Capital Bank, N.A., which allows Texas Capital Bank to also act as agent for BP for the purpose of holding and enforcing any liens or security interests resulting from our derivative arrangements. Therefore, we generally are not required to post additional collateral, including cash.

ITEM 4. CONTROLS AND PROCEDURES.

Our chief executive officer and principal financial officer, Robert G. Watson, 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. Based on the evaluation, Mr. Watson concluded that our disclosure controls and procedures are effective in timely altering him to material information relating to us (including our consolidated subsidiaries) required to be included in our periodic SEC filings.

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 report, there are no material pending legal proceedings to which we are a party or to which any of our property is subject.

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 between Millennium Plastics Corporation and Midwest Energy, Inc. effective August 15, 2006 (incorporated by reference to Exhibit 2.3 to the Form 8-K filed on August 16, 2006)

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)

4.1			Article VI of Amended and Restated Articles of Incorporation of Millennium Plastics Corporation (incorporated by reference to Exhibit 1.3 to the Form 8-K filed on December 6, 1999)

4.2			Article II and Article VIII, Sections 3 & 6 of Amended and Restated Bylaws of Millennium Plastics Corporation (incorporated by reference to Exhibit 4.1 to the Form SB-2 filed on February 23, 2001)

4.3			Specimen common stock certificate (incorporated by reference to Exhibit 4.3 to the Form S-1/A filed on May 27, 2008)

4.4			Certificate of Designation (incorporated by reference to Exhibit 4.1 to the Form 8-K filed on January 6, 2011).

10.1			Credit Agreement with Texas Capital Bank, N.A. dated July 3, 2008 (incorporated by reference to Exhibit 10.33 to the Form 10-K filed on July 10, 2008)

10.2			Promissory Note to Texas Capital Bank, N.A. dated July 3, 2008 (incorporated by reference to Exhibit 10.34 to the Form 10-K filed on July 10, 2008)

10.3			Amended and Restated Mortgage, Security Agreement, Financing Statement and Assignment of Production and Revenues with Texas Capital Bank, N.A. dated July 3, 2008 (incorporated by reference to Exhibit 10.35 to the Form 10-K filed on July 10, 2008)

10.4			Security Agreement with Texas Capital Bank, N.A. dated July 3, 2008 (incorporated by reference to Exhibit 10.36 to the Form 10-K filed on July 10, 2008)

10.5			Letter Agreement with Debenture Holders dated July 3, 2008 (incorporated by reference to Exhibit 10.37 to the Form 10-K filed on July 10, 2008)

10.6†			C. Stephen Cochennet Employment Agreement dated August 1, 2008 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on August 1, 2008)

10.7†			Dierdre P. Jones Employment Agreement dated August 1, 2008 (incorporated by reference to Exhibit 10.2 to the Form 8-K filed on August 1, 2008)

10.8†			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)
10.9			Form of Officer and Director Indemnification Agreement (incorporated by reference to Exhibit 10.2 to the Form 8-K filed on October 16, 2008)

10.10			Euramerica Letter Agreement Amendment dated September 15, 2008 (incorporated by reference to Exhibit 10.10 to the Form 8-K filed on September 18, 2008)

10.11			Euramerica Letter Agreement Amendment dated October 15, 2008 (incorporated by reference to Exhibit 10.11 to the Form 8-K filed on October 21, 2008)

10.12(a) †			C. Stephen Cochennet Rescission of Option Grant Agreement dated November 17, 2008 (incorporated by reference to Exhibit 10.38(a) to the Form 10-Q filed on February 23, 2009)

10.12(b) †			Dierdre P. Jones Rescission of Option Grant Agreement dated November 17, 2008 (incorporated by reference to Exhibit 10.38(b) to the Form 10-Q filed on February 23, 2009)

10.12			Daran G. Dammeyer Rescission of Option Grant Agreement dated November 17, 2008 (incorporated by reference to Exhibit 10.38(c) to the Form 10-Q filed on February 23, 2009)

10.12(d)			Darrel G. Palmer Rescission of Option Grant Agreement dated November 17, 2008 (incorporated by reference to Exhibit 10.38(d) to the Form 10-Q filed on February 23, 2009)
10.12(e)			Dr. James W. Rector Rescission of Option Grant Agreement dated November 17, 2008 (incorporated by reference to Exhibit 10.38(e) to the Form 10-Q filed on February 23, 2009)

10.12(f)			Robert G. Wonish Rescission of Option Grant Agreement dated November 17, 2008 (incorporated by reference to Exhibit 10.38(f) to the Form 10-Q filed on February 23, 2009)

10.13			Letter Agreement with Debenture Holders dated June 11, 2009 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on June 16, 2009)

10.14			Joint Operating Agreement with Pharyn Resources to explore and develop the Brownrigg Lease Press Release dated June 1, 2009 (incorporated by reference to Exhibit 99.1 to the Form 8-K filed on June 5, 2009)

10.15			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)


10.16			Waiver from Texas Capital Bank, N.A. dated July 14, 2009 (incorporated by reference to Exhibit 10.16 to Form 10-K filed July 14, 2009)

10.17			First Amendment to Credit Agreement dated August 18, 2009 (incorporated by reference to the Exhibit 10.12 to the Form 10-Q filed August 18, 2009)

10.18			Debenture Holder Amendment Letter dated November 16, 2009 (incorporated by reference to the Exhibit 10.13 to the Form 10-Q filed November 20, 2009)

10.19			Standby Equity Distribution Agreement with Paladin Capital Management, S.A. dated December 3, 2009 (incorporated by reference to Exhibit 10.52 to the Form S-1 filed on December 9, 2009)

10.20			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)

10.21			Second Amendment to Credit Agreement dated January 13, 2010 (incorporated by reference to Exhibit 10.16 to the Form 10-Q filed on February 16, 2010)

10.22			Debenture Holder Amendment Letter dated January 27, 2010 (incorporated by reference to Exhibit 10.17 to the Form 10-Q filed on February 16, 2010)

10.23			Waiver from Texas Capital Bank, N.A. dated February 10, 2009 (incorporated by reference to Exhibit 10.18 to the Form 10-Q filed on February 16, 2010)

10.24			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)

10.25			Debenture Holder Amendment Letter dated April 1, 2010 (incorporated by reference to Exhibit 10.25 to the Form 10-K filed on July 15, 2010)

10.26			Separation and Settlement Agreement with C. Stephen Cochennet dated December 31, 2010 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on December 28, 2010).

10.27			Securities Purchase and Asset Acquisition Agreement between Enerjex Resources, Inc. and West Coast Opportunity Fund, LLC; Montecito Venture Partners, LLC; J&J Operating Company, LLC and Frey Living Trust dated December 31, 2010 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on January 6, 2011).

10.28			Stock Repurchase Agreement between Enerjex Resources, Inc. and Working Interest Holdings, LLC dated December 31, 2010 (incorporated by reference to Exhibit 10.2 to the Form 8-K filed on January 6, 2011).

10.29			Securities Purchase Agreement between Enerjex Resources, Inc. and various Investors dated December 31, 2010 (incorporated by reference to Exhibit 10.3 to the Form 8-K filed on January 6, 2011).

10.30			Employment Agreement between Enerjex Resources, Inc. and Robert G. Watson dated December 31, 2010 (incorporated by reference to Exhibit 10.4 to the Form 8-K filed on January 6, 2011).

10.31			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).

10.32			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).

10.33			Third Amendment to Credit Agreement dated September 29, 2010 (incorporated by reference to Exhibit 10.33 to the Form 10-K filed on April 21, 2011).

10.34			Fourth Amendment to Credit Agreement dated December 31, 2010 (incorporated by reference to Exhibit 10.33 to the Form 10-K filed on April 21, 2011).

10.35			Amended and Restated Credit Agreement dated October 3, 2011 (incorporated by reference to Exhibit 10.1 to the Form 8-K, filed on October 5, 2011).


31.1		Certification of Chief Executive and Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1		Certification of Chief Executive and Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
†	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
	Robert G. Watson, Chief Executive Officer
	(Principal Financial Officer)

Date: November 21, 2011