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, 2012

 

¨      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 11, 2012 was 69,755,279 shares.

 

 

ENERJEX RESOURCES, INC.

FORM 10-Q

TABLE OF CONTENTS

 

			Page
PART I     FINANCIAL STATEMENTS
ITEM 1.	FINANCIAL STATEMENTS
	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		9
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		10
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		16
ITEM 4.	CONTROLS AND PROCEDURES		16
PART II    OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS		16
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		17
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES		17
ITEM 4.	(REMOVED AND RESERVED)		17
ITEM 5.	OTHER INFORMATION		17
ITEM 6.	EXHIBITS		17
SIGNATURES			20

 

 

PART 1 – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EnerJex Resources, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

Unaudited

		September 30,				December 31,
		2012				2011
Assets
Current assets:
Cash		$	406,287			$	2,770,440
Accounts receivable			1,290,235				1,454,405
Marketable securities			1,018,573				1,018,573
Deposits and prepaid expenses			297,958				114,436
Total current assets			3,013,053				5,357,854
Fixed assets			575,061				529,371
Less: Accumulated depreciation			291,638				232,508
Total fixed assets			283,423				296,863
Other assets:
Oil properties using full-cost accounting:
Properties not subject to amortization			8,170,112				7,922,734
Properties subject to amortization			23,091,885				17,837,766
Total other assets			31,261,997				25,760,500
Total assets		$	34,558,473			$	31,415,217
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable		$	1,563,179			$	2,355,692
Accrued liabilities			399,783				123,789
Derivative liability			764,672				959,114
Long-term debt, current			-				7,000
Total current liabilities			2,727,634				3,445,595
Asset retirement obligation			1,302,947				908,790
Long-term debt			5,666,000				3,826,484
Derivative liability			1,059,484				1,768,220
Total liabilities			10,756,065				9,949,089
Commitments & Contingencies
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 73,395,279  at September 30, 2012 and 73,355,279 at December 31, 2011			73,943				73,412
Treasury Stock, 3,750,000 shares			(1,500,000	)			(1,500,000	)
Equity based compensation unearned			(173,110	)			(230,813	)
Paid-in capital			44,889,205				43,556,486
Accumulated other comprehensive income			(552,589	)			(552,589	)
Retained (deficit)			(20,236,116	)			(20,450,876	)
Total stockholders' equity EnerJex Resources, Inc.			22,506,113				20,900,400
Non controlling interest in subsidiary			1,296,295				565,728
Total stockholder’s equity			23,802,408				21,466,128
Total liabilities and stockholders' equity		$	34,558,473			$	31,415,217

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,
		2012				2011				2012				2011
Oil revenues		$	2,252,681			$	1,673,857			$	6,204,738			$	4,728,198
Expenses:
Direct operating costs			807,887				787,994				2,162,470				2,461,978
Depreciation, depletion and  amortization			459,815				375,175				1,290,334				975,908
Professional fees			364,519				255,706				1,037,248				745,638
Salaries			112,370				150,673				355,750				434,319
Administrative expense			152,117				75,600				598,043				536,614
Total expenses			1,896,708				1,645,148				5,443,845				5,154,457
Income (loss) from operations		$	355,973			$	28,709			$	760,893			$	(426,259	)
Other income (expense):
Interest expense			(120,922	)			(111,472	)			(258,529	)			(333,977	)
Gain (loss)  on derivatives			(1,529,127	)			3,188,277				161,353				1,916,511
Other income (loss)			(1,973	)			13,857				20,278				37,900
Total other income (expense)			(1,652,022	)			3,090,662				(76,898	)			1,620,434
Net income (loss)		$	(1,296,049	)		$	3,119,371			$	683,995			$	1,194,175
Net income (loss) attributed to EnerJex Resources, Inc.			(1,422,880	)			-				411,801				-
Net income attributed to non controlling interest in subsidiary			126,831				-				272,194				-
Net income (loss)		$	(1,296,049	)		$	3,119,371			$	683,995			$	1,194,175
Net income (loss) per share		$	(0.02	)		$	0.04			$	0.01			$	0.02
Weighted average shares			69,714,165				69,436,529				69,770,308				68,767,860
Diluted earnings per  share		$	(0.02	)		$	0.04			$	0.01			$	0.02
Weighted average shares-diluted			69,714,165				69,436,529				71,295,730				68,767,860

 

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,
		2012				2011
Cash flows  from operating activities
Net income (loss)		$	683,995			$	1,194,175
Depreciation and depletion			1,290,334				984,151
Shares based payments issued for  services			154,074				57,702
Accretion of asset retirement obligation			75,551				60,525
(Gain) loss  on derivatives			(903,178	)			(2,695,096	)
Loss on sale of fixed assets			308				1,400
Changes in assets and liabilities:
Accounts receivable			164,170				(569,153	)
Prepaid expenses			(111,798	)			19,039
Accounts payable			(792,513	)			16,080
Accrued liabilities			275,994				47,307
Cash flows  from operating activities			836,937				(883,870	)
Cash flows  from investing activities
Purchase of Treasury Stock			-				(1,500,000	)
Purchase of fixed assets			(58,818	)			(273,956	)
Additions to oil  properties			(6,414,494	)			(3,904,205	)
Proceeds from sale of  fixed assets			8,562				-
Cash flows from investing activities			(6,464,750	)			(5,678,161	)
Cash flows  from financing activities
Payments on long-term debt			(17,484	)			(14,113	)
Sale of marketable securities			-				1,400,000
Sale of common stock			-				3,435,996
Proceeds from borrowings			1,850,000				-
Distribution to non controlling  interest in subsidiary			(353,162	)			-
Sale of non controlling  interest in subsidiary			2,000,000				-
Dividends paid on preferred stock			(215,694	)			-
Cash flows from financing activities			3,263,660				4,821,883
Net increase (decrease) in cash			(2,364,153	)			(1,740,148	)
Cash – beginning			2,770,440				2,961,819
Cash – ending			406,287			$	1,221,671
Supplemental disclosures:
Interest paid		$	182,978			$	333,977
Income taxes paid			-			$	-
Non-cash transactions:
Share based  payments issued for services		$	154,074			$	57,702

 

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 Annual Report Form 10-K for the fiscal year ended December 31, 2011.

 

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 as well as the accounts of Rantoul Partners, a general partnership in which we hold a majority and controlling interest. All intercompany transactions and accounts have been eliminated in consolidation.

 

Note 2 - Stock Options

 

A summary of stock options is as follows:

 

		Options				Weighted Avg. Exercise Price				Warrants				Weighted Avg. Exercise Price
Outstanding December 31, 2011			900,000			$	0.40				2,838,330			$	0.90
Granted			-				-				250,000				0.70
Cancelled			-				-				(2,838,330	)			(0.90	)
Exercised			-				-				-				-
Outstanding September 30, 2012			900,000			$	0.40				250,000			$	0.70

 

On March 31, 2011, EnerJex Resources, Inc. (the “Company”) completed a securities purchase agreement with accredited investors for the sale of 5,676,644 shares of the Company’s restricted common stock at a purchase price of $.60 per share. Each investor received a warrant to purchase one share of common stock at a price of $.90 per share for each two shares of common stock purchased. Each warrant was exercisable until December 31, 2011. Prior to the expiration of these warrants the exercise period was extended to September 30, 2012. On September 30, 2012 the warrants were cancelled, unexercised as reflected in the table above.

 

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, 2012.

 

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		$	-			$	(1,824,156	)		$	-
Marketable Securities		$	-			$	-			$	1,018,573

 

 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, 2011		$	908,790
Liabilities incurred during the period			318,606
Liabilities settled during the period			-
Accretion			75,551
Asset retirement obligations, September 30, 2012		$	1,302,947

 

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, 2012:

 

		Term				Monthly Volumes				Price/Bbl				Fair Value
Crude oil swap			7/12-12/15				1,823Bbls			$	76.74				(1,050,051	)
Crude oil swap			7/11-12/15				2,638Bbls				83.70				(736,625	)
Crude oil swap			1/11-12/12				500 Bbls				82.20				(15,215	)
Crude oil swap			12/11-12/12				500 Bbls				77.50				(22,265	)
														$	(1,824,156	)

 

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. 

 

 

Note 6 - Long-Term Debt

 

Senior Secured Credit Facility

 

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

 

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

 

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

 

We entered into a Second Amendment to Amended and Restated Credit Agreement and Second Amended and Restated Promissory Note in the amount of $50,000,000 with the Texas Capital Bank, which closed on August 31, 2012. The Amendment reflects the following changes: i) the reduction of the minimum interest rate to 3.75%, ii) an increase in the borrowing base to $7.0 million, iii) the addition of a provision resulting in an event of default if Robert G. Watson ceases to be the chief executive officer of any Borrower for any reason and a successor reasonably acceptable to Administrative Agent is not appointed within one hundred twenty (120) days thereafter, and iv) the addition of new leases to the collateral pool.

 

We entered into a Third Amendment to Amended and Restated Credit Agreement and Second Amended and Restated Promissory Note in the amount of $50,000,000 with the Texas Capital Bank, which closed on November 5, 2012. The Amendment reflects the following changes: i) an increase in the borrowing base to $12.150 million, iii) the addition of a provision permitting the repurchase of up to $2,000,000 of common stock on or before December 31, 2013, subject to certain liquidity requirements, iii) the amendment of certain financial covenant definitions for the purposes of clarity, and iv) the provision of a limited waiver for the failure to comply with the Interest Coverage Ratio for the period ending December 31, 2011.

 

Our current borrowing base is $12.150 million, of which we had borrowed approximately $5.7 million as of September 30, 2012. We intend to conduct an additional borrowing base review in the first quarter of 2013 and we expect increases in production and the maturity of existing production to result in an additional borrowing base increase prior to such additional borrowing base review.

 

Note 7 Equity Transactions

 

50,000 shares of our common stock were issued to a director as compensation for service.

 

Note 8 Subsequent Events

 

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

 

The Board of Directors has approved the issuance of (1) 60,000 of our common shares to certain third-parties in exchange for services, and 2) ) options to acquire 25,000 of our common shares to an employee with an exercise price of $0.70 expiring on June 30, 2017 or within three months of employment termination.

 

On October 5, 2012, the Company entered into a Share Option Agreement, effective as of August 31, 2012, with Enutroff, LLC (the “Owner”), whereby the Company and Owner agreed that in consideration of the Company’s agreement to pay to Owner an option fee in the amount of $151,000 (the “Option Fee Amount”), the Company shall have the option but not the obligation to purchase up to 2,000,000 shares of Common Stock of the Company (the “Option Shares”) from Owner at a cash price of $0.45 per share. Pursuant to this agreement, the Company must exercise at least 500,000 Option Shares during each consecutive calendar quarter, beginning in the first calendar quarter of 2013 and ending in the last calendar quarter of 2013. If the Company does not exercise at least 500,000 Option Shares by the end of any such quarter, then it shall forfeit its right to exercise any additional Option Shares thereafter. The Option Fee Amount shall be paid within five (5) business days of January 1, 2013.

 

 

On November 2, 2012 the Board of Directors approved and authorized the Company to expend up to $2.0 million to repurchase shares of the Company’s common stock. The authorization will remain open through December 31, 2013. The Company is authorized to repurchase from time to time shares of its outstanding common stock on the open market or in privately negotiated transactions. The timing and amount of stock repurchases will depend upon a variety of factors, including the market conditions as well as corporate and regulatory considerations. The share repurchase program may be suspended, modified or discontinued at any time and the Company has no obligation to repurchase any amount of its common stock under the program. The Company intends to make all repurchases in compliance with applicable regulatory guidelines and to administer the plan in accordance with applicable laws, including Rule 10b-18 of the Securities Act of 1934, as amended.

 

On November 5, 2012, we entered into a Third Amendment to Amended and Restated Credit Agreement and Second Amended and Restated Promissory Note in the amount of $50,000,000 with the Texas Capital Bank. The Amendment reflects the following changes: i) an increase in the borrowing base to $12.150 million, iii) the addition of a provision permitting the repurchase of up to $2,000,000 of common stock on or before December 31, 2013, subject to certain liquidity requirements, iii) the amendment of certain financial covenant definitions for the purposes of clarity, and iv) the provision of a limited waiver for the failure to comply with the Interest Coverage Ratio for the period ending December 31, 2011.

 

 

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 Annual Report on Form 10-K for the fiscal year ended December 31, 2011.

 

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, Rantoul Partners and Working Interest, LLC, 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 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. Approximately 41 million barrels of oil were produced in Kansas during 2011. Twenty companies accounted for approximately 35% of the state’s total production, with the remaining 65% produced by more than 3,000 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 by drilling low risk development wells, acquiring producing properties in close proximity to existing operations, and utilizing 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 of less than 3,000 feet) and contain significant volumes of oil in place. These shallow reservoirs often have relatively low reservoir pressure and lack a strong natural drive mechanism. As a result, the ultimate recovery of oil in place can be significantly increased through the application of secondary recovery technologies.

 

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 previous decades, but operators lacked the technology to economically produce oil 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 were never fully developed due to technology and economic constraints.

 

 

Recent Developments

The following is a brief description of our most significant corporate developments that have occurred since the end of 2011:

 

·

We expect that an additional $650,000 will be contributed to Rantoul Partners by one of its investors on or before December 1, 2012. This contribution would reduce our ownership interest in this general partnership to 75.00%. These contributions are being utilized to develop the assets owned by Rantoul Partners which are located in our Rantoul Project in Eastern Kansas. The $650,000 contribution would represent the final capital contribution in the Partnership.

 

·

From the inception of Rantoul Partners on October 1, 2011 through October 31, 2012, we have drilled and completed 70 new producing oil wells and 78 new secondary recovery water injection wells in our Cherokee Project located in Eastern Kansas. All of these wells were successful.

 

·

From January 1, 2012 through October 31, 2012, we have drilled 20 new oil wells and 5 new secondary recovery water injection wells in our Mississippian Project that are not owned by Rantoul Partners.

 

·

During the third quarter ended September 30, 2012, we drilled and completed 28 new oil wells and 10 new secondary recovery water injection wells on new expansion leases in our Cherokee Project located in Southeast Kansas. The expansion leases are in the same trend as the Rantoul Partners leases. Production from these wells reached 30 gross barrels per day in October 2012 prior to the effect of secondary waterflood operations. Wells drilled on these leases proved up significant reserve value and several additional low risk locations.

 

·

We continue to monitor and maintain production in our El Toro project in South Texas. Availability of oil field services continue to be stretched as a result of the booming Eagleford Shale play in the area. As a result, we intend to focus our capital program on Kansas projects in the near term while evaluating the possibility of horizontal development of the El Toro project at a later date. Gross production is currently averaging 55 gross barrels per day on this project.

 

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 ending September 30, 2012 and September 30, 2011.

 

		For the Three Months Ended								For the Nine Months Ended
		September 30,								September 30,
		2012				2011				2012				2011
Net Production			26,038				19,724				68,986				52,748
Oil (Bbl)
Average Sales Prices
Oil (per Bbl)		$	86.52			$	84.87			$	89.94			$	89.64
Average Production Cost (1)
Per Bbl of oil		$	48.69			$	58.97			$	50.05			$	65.18
Average Lifting Costs (2)
Per Bbl of oil		$	31.03			$	39.95			$	31.35			$	46.67

 

(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, 2012 and 2011 compared.

 

Income:

 

		Three Months Ended								Increase /				Nine Months Ended								Increase /
		September 30,								(Decrease)				September 30,								(Decrease)
		2012				2011				$				2012				2011				$
Oil revenues		$	2,252,681			$	1,673,857			$	578,824			$	6,204,738			$	4,728,198			$	1,476,540

 

Revenues

 

Oil revenues for the three months and nine months ended September 30, 2012 increased primarily as a result of higher oil production.

 

Expenses:

 

		Three Months Ended								Increase /				Nine Months Ended								Increase /
		September 30,								(Decrease)				September 30,								(Decrease)
		2012				2011								$2012				2011				$
Production expenses:
Direct operating costs		$	807,887			$	787,994			$	19,893			$	2,162,470			$	2,461,978			$	(299,508	)
Depreciation, depletion and amortization			459,815				375,175				84,640				1,290,334				975,908				314,426
Total production expenses			1,267,702				1,163,169				104,533				3,452,804				3,437,886				14,918
General expenses:
Professional fees			364,519				255,706				108,813				1,037,248				745,638				291,610
Salaries			112,370				150,673				(38,303	)			355,750				434,319				(78,569	)
Administrative expense			152,117				75,600				76,517				598,043				536,614				61,429
Total general expenses			629,006				481,979				147,027				1,991,041				1,716,571				274,470
Total production and general expenses			1,896,708				1,645,148				251,560				5,443,845				5,154,457				289,388
Income (loss) from operations			355,973				28,709				327,264				760,893				(426,259	)			1,187,152
Other income (expense)
Interest expense			(120,922	)			(111,472	)			(9,450	)			(258,529	)			(333,977	)			75,448
Gain (loss) on derivatives			(1,529,127	)			3,188,277				(4,717,404	)			161,353				1,916,511				(1,755,158	)
Other income (loss)			(1,973	)			13,857				(15,830	)			20,278				37,900				(17,622	)
Total other income (expense)			(1,652,022	)			3,090,662				(4,742,684	)			(76,898	)			1,620,434				(1,697,332	)
Net income (loss)		$	(1,296,049	)		$	3,119,371			$	(4,415,420	)		$	683,995			$	1,194,175			$	(510,180	)

 

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, 2012 decreased compared to the prior year period due primarily to sale of assets, cost reduction measures and increased operating efficiency. Direct operating costs for the three months ended September 30, 2012 increased slightly.

 

 

Depreciation, Depletion and Amortization

 

Depreciation, depletion and amortization for the three month and nine months ended September 30, 2012 increased primarily due to higher production.

 

Professional Fees

 

Professional fees for the three month and nine months ended September 30, 2012 increased as a result of higher landman fees related to our Cherokee Project leasing activities, higher reserve engineering fees, higher legal fees and higher investment banking fees incurred during 2012. Professional fees were also higher as a result of increased discretionary investor relations activity that primarily occurred during the third quarter ended September 2012.

 

Salaries

 

Salaries for the three month and nine months ended September 30, 2012 were slightly lower compared to the prior periods.

 

Administrative Expenses

 

Administrative expenses for the three month and nine months ended September 30, 2012 were slightly higher than prior periods. 

 

Interest Expense

 

Interest expense for the nine months ended September 30, 2012 decreased as a result of reduced borrowing under our Credit Facility. Interest expense for the three months ended September 30, 2012 increased compared to the prior period due to higher borrowings under the Credit Facility.

 

Gain (Loss) on Derivatives

 

We incurred a significant loss of $1,529,127 on our derivative contracts in the third quarter of 2012 due to an increase in oil prices. A significant portion of the loss on derivative contracts in the third quarter is related to a non-cash write down of the value of the derivative portfolio.

 

Net Income (Loss)

 

Net income for the nine months ended September 30, 2012 was $683,995 compared to net income of $1,194,175 for the nine months ended September 30, 2011.  The decrease in Net Income during the third quarter 2012 compared to the prior year period was primarily a result of the non-cash write down of our derivative portfolio. Increased revenue from production growth and decreased operating expenses per barrel partially offset the decrease in third quarter 2012 Net Income compared to the prior year period. The net loss for the three months ended September 30, 2012 was due primarily to non-cash charges to our derivative portfolio.

 

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 2012 and 2013.

 

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

 

		September 30, 2012				December 31, 2011				Increase / (Decrease)
Current Assets		$	3,013,053			$	5,357,854			$	(2,344,801	)
Current Liabilities		$	2,727,634			$	3,445,595			$	(717,961	)
Working Capital		$	285,419			$	1,912,259			$	(1,626,840	)

 

 

Senior Secured Credit Facility

 

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

 

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

 

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

 

We entered into a Second Amendment to Amended and Restated Credit Agreement and Second Amended and Restated Promissory Note in the amount of $50,000,000 with the Texas Capital Bank, which closed on August 31, 2012. The Amendment reflects the following changes: i) the reduction of the minimum interest rate to 3.75%, ii) an increase in the borrowing base to $7.0 million, iii) the addition of a provision resulting in an event of default if Robert G. Watson ceases to be the chief executive officer of any Borrower for any reason and a successor reasonably acceptable to Administrative Agent is not appointed within one hundred twenty (120) days thereafter, and iv) the addition of new leases to the collateral pool.

 

We entered into a Third Amendment to Amended and Restated Credit Agreement and Second Amended and Restated Promissory Note in the amount of $50,000,000 with the Texas Capital Bank, which closed on November 5, 2012. The Amendment reflects the following changes: i) an increase in the borrowing base to $12.150 million, iii) the addition of a provision permitting the repurchase of up to $2,000,000 of common stock on or before December 31, 2013, subject to certain liquidity requirements, iii) the amendment of certain financial covenant definitions for the purposes of clarity, and iv) the provision of a limited waiver for the failure to comply with the Interest Coverage Ratio for the period ending December 31, 2011.

 

Our current borrowing base is $12.150 million, of which we had borrowed approximately $5.7 million as of September 30, 2012. We intend to conduct an additional borrowing base review in the first quarter of 2013 and we expect increases in production and the maturity of existing production to result in an additional borrowing base increase subsequent to that borrowing base review.

 

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 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 the number of our 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 expenses, 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, 2011, 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 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 and principal financial officer, Robert G. Watson, Jr., 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 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 legal fees paid of over $484,000.  There can be no assurance of the outcome in the litigation, including whether and in what amount we may recover damages. On June 30, 2012, the defendants answered the complaint and filed a counterclaim against us for $492,133.95. This amount is already reflected as a liability under accounts payable on our balance sheet.

 

On September 13, 2012, we filed a petition seeking recovery of damages arising from the slander of title, tortious interference with contractual relations, and requesting a declaratory judgment to quiet title in the Fourth Judicial District Court, Anderson County, Kansas, against defendants John J. Benge and Northwest Missouri Land Company.  The petition in this action, DD Energy, Inc., v. Benge, et al., alleges, among other things, that the defendants deliberately and intentionally slandered title to prevent the sale of an oil lease in Anderson County, Kansas after negotiations to sell the subject leases to the defendants fell through in 2012.

 

 

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 Transition Report on Form 10-K filed on April 21, 2011).
10.34		Fourth Amendment to Credit Agreement dated December 31, 2010 (incorporated by reference to Exhibit 10.34 to the Transition Report on Form 10-K filed on April 21, 2011).
10.35		Letter Agreement with Registrant, James Loeffelbein, John Loeffelbein and J&J Operating dated January 14, 2011 (incorporated by reference to Exhibit 10.1 on Form 8-K filed on January 18, 2011).
10.36		Form of Securities Purchase Agreement among Registrant and Investors dated March 31, 2011 (incorporated by reference to Exhibit 10.1 on Form 8-K filed on April 4, 2011).
10.37		Form of Warrant among Registrant and Investors dated March 31, 2011 (incorporated by reference to Exhibit 10.2 on Form 8-K filed on April 4, 2011).
10.38		Form of Stock Redemption Agreement among Registrant and Working Interest Holdings, LLCs dated March 31, 2011 (incorporated by reference to Exhibit 10.1 on Form 8-K filed on April 4, 2011).
10.39		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).
10.40		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).
10.41		Rantoul Partners General Partnership Agreement dated December 14, 2011 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on December 14, 2011).
10.42		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).
10.43 31.1		First Amendment to General Partnership Agreement for Rantoul Partners dated March 30, 2012 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on April 5, 2012). 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, Jr.
	Robert G. Watson, Jr. Chief Executive Officer
	(Principal Financial Officer)
Date: November 13, 2012